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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2006
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 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 (I.R.S. Employer Identification No.)
100 22nd Avenue Brookings, South Dakota (Address of principal executive offices)		57006 (Zip Code)

(605) 696-7200
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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

The aggregate market value of voting and non-voting stock held by non-affiliates of the Registrant as of June 30, 2006 was $645,025,304. Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.


Class		Outstanding at March 15, 2007
Common Stock, $0.01 par value per share		76,331,326 shares

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s definitive Proxy Statement for its May 16, 2007 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

This Annual Report on Form 10-K also constitutes an annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the following subsidiaries of VeraSun Energy Corporation:


		State of	I.R.S. Employer
	Commission File	Incorporation or	Identification
Company	Number	Organization	Number

VeraSun Aurora Corporation	333-13342-03	South Dakota	40-0462174
VeraSun Fort Dodge, LLC	333-13342-02	Delaware	42-1630527
VeraSun Charles City, LLC	333-13342-04	Delaware	20-3735184
VeraSun Marketing, LLC	333-13342-01	Delaware	20-3693800
VeraSun Hartley, LLC		Delaware	20-5381200
VeraSun Granite City, LLC		Delaware	20-5909621
VeraSun Reynolds, LLC		Delaware	20-5914827
VeraSun Welcome, LLC		Delaware	20-4115888

The address of the principal executive offices of each of these entities is 100 22nd Avenue, Brookings, S.D. 57006 and the telephone number is (605) 696-7200.

FORWARD LOOKING STATEMENTS

This Form 10-K contains forward-looking statements. In particular, statements that we make under Item 1 “Business”, Item 1A “Risk Factors,” and Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding future events and developments and our future performance, extraction of oil from distillers grains, construction of a biodiesel production facility, expected completion of our facilities, the commencement of our ethanol marketing efforts and expectations concerning our ability to finance our growth plans, as well as management’s expectations, anticipations, beliefs, plans, targets, estimates, or projections and similar expressions relating to the future, are forward-looking statements within the meaning of these laws. These statements are based on assumptions and assessments made by our management in light of their experience and their perception of historical trends, current conditions, expected future developments and other factors they believe to be appropriate. Any forward-looking statements are not guarantees of our future performance and are subject to risks and uncertainties that could cause actual results, developments and business decisions to differ materially from those contemplated by any forward-looking statements. We disclaim any duty to update any forward-looking statements. Some of the factors that may cause actual results, developments and business decisions to differ materially from those contemplated by any forward-looking statements include the volatility and uncertainty of corn, natural gas, ethanol and unleaded gasoline prices; the results of our hedging transactions and other risk mitigation strategies; operational disruptions at our facilities; our ability to implement our expansion strategy as planned or at all; our ability to locate and integrate potential future acquisitions; our ability to develop an oil extraction business; development of infrastructure related to the sale and distribution of ethanol; our limited operating history; excess production capacity in our industry; our ability to compete effectively in our industry; our ability to implement a marketing and sales network for our ethanol; changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices; environmental, health and safety laws, regulations and liabilities; our reliance on key management personnel; future technological advances; limitations and restrictions contained in the instruments and agreements governing our indebtedness; our ability to raise additional capital and secure additional financing; our ability to implement additional financial and management controls, reporting systems and procedures; and costs of construction and equipment, as more fully described in Item 1A “Risk Factors” in this report.

PART I


ITEM 1.	*BUSINESS*

Overview

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

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

We own and operate 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”. As of February 25, 2007, our ethanol production capacity represented approximately 4% of the total ethanol production capacity in the U.S., according to the RFA. We expect to operate three facilities with an aggregate production capacity of 340 MMGY by the end of April 2007 and five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008. See Note 16 to the Consolidated Financial Statements under Item 8 of this Form 10-K for information concerning our business segments.

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

Our facility in Aurora, South Dakota commenced operations in December 2003 and our facility in Fort Dodge, Iowa commenced operations in October 2005. We commenced construction of our facility in Charles City, Iowa in 2006 and expect to begin operations there in April of 2007. We also began construction of facilities in Hartley, Iowa, and Welcome, Minnesota in 2006 and expect those facilities to begin production by the end of the first quarter of 2008.

Demand for Ethanol

We believe the ethanol market will grow as a result of a shortage of domestic petroleum refining capacity; geopolitical concerns; and federally mandated renewable fuel usage. We also believe that E85 may become increasingly important over time as an alternative to unleaded gasoline.

Shortage of domestic petroleum refining capacity. While the number of operable U.S. petroleum refineries has decreased from 319 in 1980 to 149 in 2006, according to the EIA, domestic demand has increased 40% over the same period. The EIA expects growth in refining capacity to average 1.3% per year until 2025, with demand for refined petroleum products growing at 1.5% per year over the same period. Because ethanol is blended with gasoline after the refining process, it directly increases domestic fuel capacity. We believe that domestic fuel refining shortages will result in greater demand for ethanol.

Geopolitical concerns. The U.S. is increasingly dependent on foreign oil. According to the EIA, crude oil imports represented 66% of the U.S. crude oil supply in 2006 and are estimated to rise to 75% by 2025. Political unrest and attacks on oil infrastructure in the major oil producing nations, particularly in the Middle East, have periodically disrupted the flow of oil. Fears of terrorist attacks have added a “risk premium” to world oil prices. At the same time, developing nations such as China and India have increased their demand for oil. As a result, in 2006, world oil prices topped $70 a barrel at times and averaged above $60 a barrel. As a domestic renewable source of energy, ethanol reduces the U.S.’s dependence on foreign oil by increasing the availability of domestic fuel supplies.

Renewable Fuels Standard. In August 2005, President Bush signed the Energy Policy Act establishing the Renewable Fuels Standard, or RFS, which eliminated the mandated use of oxygenates in reformulated gasoline and mandates annual use of 7.5 billion gallons per year, or BGY, of renewable fuels in the U.S. fuel supply by the year 2012. The RFS requires motor fuels sold in the U.S. to contain, in the aggregate, minimum volumes of renewable fuels in future years, ranging from 4.7 billion gallons in 2007 to 7.5 billion gallons in 2012. We expect this mandate to result in a significant increase in ethanol demand, and we believe the actual use of ethanol and other renewable fuels will surpass the mandated requirements, especially in the early years of implementation of the RFS. Additional legislation that we believe affects the demand for ethanol, including the federal tax incentive program, is discussed below under “Legislation.”

Supply of Ethanol

Production in the ethanol industry remains fragmented. According to the RFA, while domestic ethanol production capacity increased from 1.7 billion gallons in 1997 to 5.4 billion gallons in 2006, the top five producers accounted for approximately 37% of the industry’s total estimated production capacity as of December 2006. The remaining production was generated by more than 50 smaller producers and farmer-owned cooperatives, most with production of 50 MMGY or less. Since a typical ethanol facility can be constructed in approximately 16-20 months from groundbreaking to operation, the industry is able to forecast capacity additions for up to 18 months in the future. As of February 25, 2007, the RFA estimated that ethanol facilities with capacity of an aggregate of an additional 6.2 BGY were under construction. The potential increase in ethanol production capacity could have an adverse impact on our business. See Item 1A “Risk Factors — New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry”.

Although the ethanol industry continues to explore production technologies employing various feedstocks, such as biomass, corn-based production technologies remain the most practical and provide the lowest operating risks. Consequently, most U.S. ethanol is produced from corn grown in Illinois, Iowa, Minnesota, Nebraska and South Dakota, where corn is abundant. In addition to corn, the production process employs natural gas or, in some cases, coal to power the facility and to dry distillers grains. Proximity to sufficient low-cost corn and natural gas supply, therefore, provides a key competitive advantage for ethanol producers.

Ethanol is typically either produced by a dry-milling or wet-milling process. Although the two processes have numerous technical differences, the primary operating trade-off of the wet-milling process is a higher co-product yield in exchange for a lower ethanol yield. Dry-milling ethanol production facilities constitute the substantial majority of new ethanol production facilities constructed in the past five years because of the increased efficiencies and lower capital costs of dry-milling technology. Dry-mill ethanol facilities typically produce between five and 50 MMGY, with newer dry-mill facilities, like ours, producing over 100 MMGY and generally enjoying economies of scale in both construction and operating costs per gallon. The largest ethanol production facilities are wet-mill facilities that have capacities of 200 to 300 MMGY. According to the RFA, 79% of the ethanol production capacity is generated from dry-mill facilities, with only 21% from wet-mill facilities.

Over half of total U.S. ethanol production is consumed in the east- and west-coast markets, primarily as a result of the stricter air quality requirements in large parts of those markets. The primary means of transporting ethanol from the Midwest to the coasts is by rail. As a result, adequate access to rail transportation is a key consideration for locating ethanol production facilities. Furthermore, a producer’s ability to form unit trains, consisting entirely of ethanol tank cars from one facility, allows for reduced transportation costs and faster delivery times. The movement of ethanol via pipeline is limited as a result of the tendency of ethanol to absorb water and other impurities found in the pipelines, logistical limitations of existing pipelines and limited volumes of ethanol that need to be transported. Barges and trucks are also used in ethanol transportation.

Ethanol Production Process

In the dry-mill process of converting corn into ethanol, each bushel of corn yields approximately 2.8 gallons of ethanol and approximately 18 pounds of distillers grains. This process is described below.

1. The corn kernels are first ground into a flour, or “meal,” and mixed with water in cookers to form slurry, called “mash.”

2. In the cooking system, the action of heat liquefies the starch in the corn, and enzymes are added to break down the starch to fermentable sugars.

3. The cooked mash is then cooled and pumped to the fermenters where yeast is added. The action of the yeast converts the sugars in the mash into ethanol.

4. The fermented mash is pumped to the distillation system where the ethanol is separated from the non-fermentable solids (the stillage), and water is removed to concentrate the ethanol to a strength of 190-proof (95% ethanol).

5. The ethanol is further concentrated in a molecular sieve dehydrator to a strength of 200-proof (99+% ethanol), to produce fuel-grade ethanol which is then denatured (rendered unfit for human consumption) with gasoline and transferred to storage tanks.

6. The stillage from the distillation system is sent through a centrifuge that separates the coarse grain from the solubles. The solubles are then concentrated in an evaporator system. The resulting material, condensed distillers solubles or “syrup,” is mixed with the coarse grain from the centrifuge and then dried to produce dried distillers grains with solubles, or DDGS, a high quality, nutritious livestock feed. Some of the distillers grains may bypass the final drying stage and be sold as wet distillers grains with solubles, or WDGS.

Ethanol Co-Products

Dried distillers grain with solubles. A co-product of dry-mill ethanol production, DDGS is a high-protein and high-energy animal feed that is sold primarily as an ingredient in beef and dairy cattle rations. DDGS consists of the concentrated nutrients (protein, fat, fiber, vitamins and minerals) remaining after starch in corn is converted to ethanol. Over 85% of DDGS is fed to dairy cattle because it contains high quality “by-pass protein,” which improves milk production economics. It is also used in beef and, to a lesser extent, swine, poultry and other livestock feed.

Our facilities utilize the latest DDGS production technology and produce high quality, or “golden,” DDGS, which commands a premium over products from older plants. Golden DDGS has higher concentration of nutrients and is more easily digested than other products.

Wet distillers grains with solubles. WDGS is similar to DDGS except that the final drying stage is bypassed and the product is sold as a wet feed containing 35% to 50% dry matter, as compared to DDGS which contains about 90% dry matter. WDGS is an excellent livestock feed due to increased palatability in rations that need additional moisture. The sale of WDGS is usually more profitable because the plant saves the cost of natural gas for drying. The product is sold locally because of the higher cost of transporting the product to distant markets and the potential for WDGS to deteriorate in quality if transported over long distances.

Corn oil. Corn oil can be produced as a co-product of ethanol production by installing equipment to separate the oil from the distillers grains during the production process. Corn oil can be sold as an animal feed and commands higher prices than DDGS. It can also be used to produce biodiesel, a clean burning alternative fuel that can be used in diesel engines with petroleum diesel to lower emissions and improve lubricity. We have conducted research and testing on extracting corn oil during the ethanol production process and using it to produce biodiesel. We will install corn oil extraction equipment at our facilities, and we are considering development and construction of a biodiesel production facility.

Overview of Raw Material Supply, Pricing and Hedging

We seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn requirements on a fixed price basis and by purchasing corn and natural gas futures contracts. To mitigate ethanol price risk, we sell a portion of our production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract such as unleaded gasoline on the New York Mercantile Exchange, or NYMEX, and we may hedge a portion of the price risk associated with index contracts by selling exchange-traded unleaded gasoline contracts. We believe our strategy of managing exposure to commodity price fluctuations will reduce somewhat the volatility of our results.

Corn procurement and hedging strategy. We employ the following corn procurement methods and related hedging strategies:


	•	we purchase corn through spot cash, fixed-price forward and delayed pricing contracts; and

	•	we use hedging positions in the corn futures market to manage the risk of excessive corn price fluctuations for a portion of our corn requirements.

For our spot purchases, we post daily corn bids so that corn producers can sell to us on a spot basis. Our fixed-price forward contracts specify the amount of corn, the price and the time period over which the corn is to be delivered. These forward contracts are at fixed prices based on Chicago Board of Trade, or CBOT, prices. Our corn requirements can be contracted for up to a year in advance on fixed-price forward contracts. The parameters of these contracts are based on the local supply and demand situation and the seasonality of the price. For delayed pricing contracts, producers will deliver corn to the plant, but the pricing for that corn and the related payment will occur at a later date.

We buy futures positions on the CBOT to hedge a portion of our exposure to corn price risk. In addition, our facilities have significant corn storage capacity. To help protect against potential supply disruptions, we generally maintain inventories of corn at each of our facilities. This corn inventory ranges generally from 10 to 30 days of supply, depending on the time of year, the current market price for corn and other factors.

Natural gas procurement and hedging strategy. We are subject to market risk with respect to our supply of natural gas that is consumed in the ethanol production process and has historically been subject to volatile market conditions. Natural gas prices and availability are affected by weather and overall economic conditions. Accordingly, we hedge a portion of our exposure to natural gas price risk from time to time by using fixed price or indexed exchange-traded futures contracts.

Unleaded gasoline hedging strategy. Because some of our contracts to sell ethanol are priced based on the price of unleaded gasoline, we establish from time to time an unleaded gasoline hedge position using exchange-traded futures to reduce our exposure to unleaded gasoline price risk.

Marketing Arrangements

Ethanol marketing. We had agreements with Aventine Renewable Energy, Inc., or Aventine, for the marketing, billing, receipt of payment and other administrative services for substantially all of the ethanol that we produce at our two facilities. We believe our ethanol constituted over 35% of the ethanol pool that Aventine managed during 2006, which made us the largest contributor to the pool. Under the terms of the agreements, we sold our ethanol to Aventine for the price at which Aventine resold the ethanol, less costs of distribution and a sales commission.

On February 15, 2006, we notified Aventine that we were terminating these agreements as of March 31, 2007. Accordingly, we are in the process of marketing and selling our ethanol directly to blenders, refiners and other end users. We believe our business has become large enough for us to market ethanol directly to customers, giving us the benefits of direct customer contact and control of contract negotiations.

In connection with this activity, we have established our own marketing, distribution, transportation and storage infrastructure. We lease 900 ethanol tanker railcars and have contracted with storage depots near our customers and other strategic locations to ensure efficient delivery of our finished ethanol product. We have also hired a marketing and sales force, as well as logistical and other operational personnel to staff our distribution activities. In addition, our senior management will devote a larger portion of its time to sales, marketing and distribution activities.

We are also marketing our VE85^tm fuel through arrangements with gas distributors and retailers. We provide the retailers with an array of services, including signage, employee training and other marketing support to assist in this process.

Distillers grains marketing. We market our distillers grains both nationally and locally through our sales force. Our DDGS is primarily marketed nationally and our WDGS is sold locally to livestock customers for use as animal feed. These sales are made pursuant to agreements typically lasting from six to twelve months. We sell more DDGS than WDGS due to the limited markets for WDGS, which cannot be economically transported long distances. Our sales of DDGS accounted for 85.4% of our co-product sales for 2006, and our sales of WDGS accounted for 14.6% of our co-product sales for 2006.

Competition

The ethanol market is highly competitive. According to the RFA, world ethanol production rose to 12 billion gallons in 2006. Fuel ethanol accounted for 73% of world production. The U.S. and Brazil are the world’s largest producers of ethanol. As of February 25, 2007, industry capacity in the U.S. approximated 5.6 BGY, with an additional 6.2 BGY of capacity under construction. The ethanol industry in the U.S. consists of more than 100 production facilities and is primarily corn based, while the Brazilian ethanol production is primarily sugar cane based.

We compete with Archer Daniels Midland Company, which has approximately 19% of the ethanol production capacity in the U.S., as well as other large producers such as US BioEnergy Corporation and Hawkeye Renewables, LLC, each of which has about 4% of the U.S. production capacity, and Aventine, which has about 3% of the U.S. production capacity. The industry is otherwise highly fragmented, with many small, independent firms and farmer-owned cooperatives constituting the rest of the market. We compete on a national basis for the sale of ethanol.

We believe that our ability to compete successfully in the ethanol production industry depends on many factors, including the following principal competitive factors:


	•	price;

	•	reliability of our production processes and delivery; and

	•	volume of ethanol produced and sold.

With respect to distillers grains, we compete with other ethanol producers, as well as with a number of large and smaller suppliers of competing animal feed. We believe the principal competitive factors for sales of distillers grains are price, proximity to purchasers and product quality.

Legislation

Energy Policy Act. The Energy Policy Act of 2005 established minimum annual volumes of renewable fuel to be used by petroleum refiners in the fuel supply. The annual requirement grows to 7.5 BGY by 2012. The Energy Policy Act removed the oxygenate requirements for reformulated gasoline that were put in place by the Clean Air Act. The Energy Policy Act also included anti-backsliding provisions, however, that require refiners to maintain emissions quality standards in the fuels that they produce, thus providing a source for continued need for ethanol.

The federal blenders’ credit. First implemented in 1979, the federal excise tax incentive program allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax rate reduction of $0.51 per gallon of ethanol. The incentive program is scheduled to expire in 2010.

The federal Clean Air Act. The use of ethanol as an oxygenate is driven, in part, by environmental regulations. The federal Clean Air Act requires the use of oxygenated gasoline during winter months in areas with unhealthy levels of carbon monoxide.

Federal tariff on imported ethanol. In 1980, Congress imposed a tariff on foreign produced ethanol to encourage the development of a domestic, corn-derived ethanol supply. This tariff was designed to prevent the federal tax incentive from benefiting non-U.S. producers of ethanol. The $0.54 per gallon tariff was scheduled to expire in 2007, but was extended in late 2006 until January 1, 2009. Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempt from the tariff under the

Caribbean Basin Initiative, which provides that specified nations may export an aggregate of 7.0% of U.S. ethanol production per year into the U.S., with additional exemptions from ethanol produced from feedstock in the Caribbean region over the 7.0% limit. As a result of new plants under development in the Caribbean region, we believe imports from there will continue, subject to the limited nature of the exemption.

In addition, there is a flat 2.5% ad valorem tariff on all imported ethanol.

State incentives. We receive an incentive payment from the State of South Dakota to produce ethanol, based on gallons of ethanol produced. This payment was not material to our results in 2006.

Environmental Matters

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. These laws, regulations and permits also can 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 damage, criminal sanctions, permit revocations and/or facility shutdowns. We do not anticipate a material adverse effect on our business or financial condition as a result of our efforts to comply with these requirements. Although we include significant pollution control equipment in our production facilities, our estimated capital expenditures for environmental controls in 2006 were not material, and we do not expect material expenditures for environmental controls in 2007. Our business is nonetheless subject to risks associated with environmental and other regulations and associated costs. See Item 1A “Risk Factors — We may be adversely affected by environmental, health and safety laws, regulations and liabilities.”

Employees

As of December 31, 2006, we had approximately 195 full time employees, including approximately 125 in operations and 70 who are responsible for companywide management, marketing, project management, logistics and administration. All of these employees are located in the U.S. None of our employees are covered by a collective bargaining agreement. We have had no labor-related work stoppages, and we believe we have positive relations with our employees.


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 47.5% of our total cost of goods sold for the year ended December 31, 2006, compared to 49.5% for the year ended December 31, 2005. Over the ten-year period from 1997 through 2006, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel on August 11, 2000 to a high of $3.90 per bushel on December 29, 2006, with prices averaging $2.32 per bushel during this period. At March 15, 2007, the CBOT price per bushel of corn was $3.98 for the May delivery contract.

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 2002 to 2006, 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 $3.98 per gallon, averaging $1.70 per gallon during this period. For the year ended December 31, 2006, ethanol prices averaged $2.53 per gallon, reaching a high of $3.98 per gallon and a low of $1.72 per gallon (based on the daily closing prices from Bloomberg). In early 2006, the spread between ethanol and corn prices was at historically high levels, driven in large part by oil companies removing a competitive product, MTBE, from the fuel stream and replacing it with ethanol in a relatively short time period. However, this spread has fluctuated widely and has narrowed significantly. 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 15.9% of our cost of goods sold for the year ended December 31, 2006, compared to 18.5% for the year ended December 31, 2005. The price fluctuations in natural gas prices over the seven-year period from December 31, 1999 through December 31, 2006, based on the NYMEX daily futures data, has ranged from a low of $1.83 per million British Thermal Units or, MMBTU, on September 26, 2001 to a high of $15.38 per MMBTU on December 23, 2005, averaging $5.63 per MMBTU during this period. At March 15, 2007, the NYMEX price of natural gas was $7.09 per MMBTU.

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

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

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

Our business is subject to seasonal fluctuations.

Our operating results are influenced by seasonal fluctuations in the price of our primary operating inputs, corn and natural gas, and the price of our primary product, ethanol. The spot price of corn tends to rise during the spring planting season in May and June and tends to decrease during the fall harvest in October and November. The price for natural gas, however, tends to move opposite that of corn and tends to be lower in the spring and summer and higher in the fall and winter. In addition, our ethanol prices are substantially correlated with the price of unleaded gasoline especially in connection with any indexed, gas-plus sales contracts we may have. The price of unleaded gasoline tends to rise during each of the summer and winter. Given our limited history, 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 and we may not be able to renew this insurance on commercially reasonable terms or at all.

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

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

We may need additional financing to implement our expansion strategy and we may not have access to the funding required for the expansion of our business or such funding may not be available to us on acceptable terms. We may finance the expansion of our business with additional indebtedness or by issuing additional equity securities. We could face financial risks associated with incurring additional indebtedness, such as reducing our liquidity and access to financial markets and increasing the amount of cash flow required to service such indebtedness, 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 Hartley 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. Our construction contracts with respect to the construction of our Hartley and Welcome facilities do not limit our exposure to higher costs. Contractors, engineering firms, construction firms and equipment suppliers also receive requests and orders from other ethanol companies and, therefore, we may not be able to secure their services or products on a timely basis or on acceptable financial terms. We may suffer significant delays or cost overruns as a result of a variety of factors, such as shortages of workers or materials, transportation constraints, adverse weather, unforeseen difficulties or labor issues, any of which could prevent us from commencing operations as expected at our facilities.

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

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

Potential future acquisitions could be difficult to find and integrate, divert the attention of key personnel, disrupt our business, 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, periodic amortization, or both 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.

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

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


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

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

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

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

	•	government regulation; and

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

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:


	•	rail capacity;

	•	storage facilities for ethanol;

	•	truck fleets capable of transporting ethanol within localized markets;

	•	refining and blending facilities to handle ethanol;

	•	service stations equipped to handle ethanol fuels; and

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

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

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

We began our business in 2001 and commenced commercial operations at our Aurora facility in December 2003 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;

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

	•	recruit and retain key personnel;

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

	•	manage rapid growth in personnel and operations;

	•	develop new products that complement our existing business; and

	•	successfully address the other risks described throughout this report.

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

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

According to the RFA, domestic ethanol production capacity has increased from 1.9 BGY as of January 2001 to an estimated 5.6 BGY at February 25, 2007. The RFA estimates that, as of February 25, 2007, approximately 6.2 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 114 production facilities. Excess capacity in the ethanol industry would

have an adverse effect on our results of operations, cash flows and financial position. In a manufacturing industry with excess capacity, producers have an incentive to manufacture additional products for so long as the price exceeds the marginal cost of production (i.e., the cost of producing only the next unit, without regard for interest, overhead or fixed costs). This incentive can result in the reduction of the market price of ethanol to a level that is inadequate to generate sufficient cash flow to cover costs.

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

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

In the U.S., we compete with other corn processors, ethanol producers and refiners, including Archer Daniels Midland Company, US BioEnergy Corporation, Hawkeye Renewables, LLC, Aventine, and Cargill, Inc. As of February 25, 2007, the top five producers accounted for approximately 35% of the ethanol production capacity in the U.S. according to the RFA. A number of our competitors are divisions of substantially larger enterprises and have substantially greater financial resources than we do. Smaller competitors also pose a threat. Farmer-owned cooperatives and independent firms consisting of groups of individual farmers and investors have been able to compete successfully in the ethanol industry. These smaller competitors operate smaller facilities that do not affect the local price of corn grown in the proximity 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 January 1, 2009) 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 we cannot achieve results comparable to those achieved by marketing through Aventine once we begin marketing and selling our ethanol directly to customers.

On February 15, 2006, we notified Aventine that we were terminating our agreements with it as of March 31, 2007. Accordingly, we are in the process of marketing and selling 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. Our financial results in 2007 also may be adversely affected by our need to establish inventory in storage locations to facilitate this transition.

Operations at our Charles City facility 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. Although the $0.54 per gallon tariff has been extended through December 31, 2008, bills were previously introduced in both the U.S. House of Representatives and U.S. Senate to repeal the tariff. We do not know the extent to which the volume of imports would increase or the effect on U.S. prices for ethanol if the tariff is not renewed beyond its current expiration. Any changes in the tariff or exemption from the tariff could have a material adverse effect on our results of operations and financial position. In addition, the North America Free Trade Agreement, or NAFTA, which entered into force on January 1, 1994, allows Canada and Mexico to export ethanol to the United States duty-free or at a reduced rate. Canada is exempt from duty under the current NAFTA guidelines, while Mexico’s duty rate is $0.10 per gallon.

The effect of the RFS in the recent Energy Policy Act is uncertain. The Acts eliminated the mandated use of oxygenates and established minimum nationwide levels of renewable fuels (ethanol, biodiesel or any other liquid fuel produced from biomass or biogas) to be included in gasoline. The elimination of the

oxygenate requirement for reformulated gasoline may result in a decline in ethanol consumption, which in turn could have a material adverse effect on our results of operations and financial condition. The legislation also included provisions for trading of credits for use of renewable fuels and authorized potential reductions in the RFS minimum by action of a governmental administrator. As the rules for implementation of the RFS and the energy bill are still under development, the impact of legislation is still uncertain.

The legislation did not include MTBE liability protection sought by refiners, which resulted in accelerated removal of MTBE and increased demand for ethanol. However, refineries may use other possible replacement additives, such as iso-octane, iso-octene or alkylate. Accordingly, the demand for ethanol could decrease. In addition, the mandated minimum level of use of renewable fuels in the RFS is significantly below projected ethanol production levels. Excess production capacity in our industry would negatively affect our results of operations, financial position and cash flows. See “New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry.”

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

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

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

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

In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional significant expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our production facilities. Present and future environmental laws and regulations (and interpretations thereof) applicable to our operations, more

vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial position.

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

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

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

Our competitive position, financial position and results of operations may be adversely affected by technological advances.

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 December 31, 2006, our total debt was $210.0 million, before unaccreted discount of $1.1 million. In addition, we had total borrowing capacity of approximately $30 million under a credit agreement. See Note 6 to our Consolidated Financial Statements under Item 8 of this Form 10-K. Letters of credit in an aggregate amount of $3.7 million have been issued under our credit agreement, leaving $26.3 million of remaining borrowing capacity at December 31, 2006. Our debt service requirements for 2007, based on our outstanding indebtedness as of December 31, 2006, total approximately $20.8 million, which includes interest payments on our senior secured notes and commitment fees under our credit agreement. Our substantial indebtedness could have important consequences for our shareholders 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 no later than December 31, 2007. Section 404 requires annual management assessment of the effectiveness of our internal controls over financial reporting and a report by our independent auditors addressing these assessments. These reporting and other obligations will increasingly place significant demands on our management, administrative, operational, internal audit 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 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.

Insiders effectively control a majority of our common stock and could sell shares.

Our executive officers and directors as a group beneficially own approximately 48% of our outstanding common stock, including Donald L. Endres, our Chief Executive Officer, who beneficially owns approximately 43% of our outstanding common stock. As a result, if acting together, they effectively can control matters requiring shareholder approval without the cooperation of other shareholders. The interests of these shareholders may not always coincide with our interests as a company or the interests of other shareholders. Shares held by our executive officers and directors became available for resale on December 11, 2006, subject to the requirements of, and the rules under, the Securities Act of 1933. The sale or prospect of the sale of a substantial number of these shares could have an adverse effect on the market price of our common stock.


ITEM 1B.	*UNRESOLVED STAFF COMMENTS*

Not applicable.


ITEM 2.	*PROPERTIES*

The table below provides an overview of our ethanol plants that were in operation or under construction, as of December 31, 2006.


	Aurora Facility	Fort Dodge Facility	Charles City Facility(1)

Location	Aurora, South Dakota	Fort Dodge, Iowa	Charles City, Iowa
Year completed or scheduled to be completed	2003 (expansion 2005)(2)	2005	2007
Annual ethanol capacity (in millions of gallons)	120	110	110(3)
Ownership	100%	100%	100%
Production process	Dry-Milling(4)	Dry-Milling(4)	Dry-Milling(4)
Primary energy source	Natural Gas	Natural Gas	Natural Gas

	Welcome Facility(5)	Hartley Facility(6)

Location	Welcome, Minnesota	Hartley, Iowa
Year completed or scheduled to be completed	2008	2008
Annual ethanol capacity (in millions of gallons)	110(3)	110(3)
Ownership	100%	100%
Production process	Dry-Milling(4)	Dry-Milling(4)
Primary energy source	Natural Gas	Natural Gas


(1)		Construction of our Charles City facility commenced in 2006 and is being funded primarily with $125.0 million of the net proceeds from the sale of senior secured notes in December 2005.

(2)		In June 2005, our Aurora facility was expanded from a production capacity of 100 MMGY to 120 MMGY.

(3)		Estimated upon completion of construction.

(4)		Our facilities use dry-milling technology, a production process that results in increased ethanol yield and reduced capital costs compared to wet-milling technology. See Item 1 — “Business — Supply of Ethanol.”

(5)		Construction of our Welcome facility began in late November 2006.

(6)		Construction of our Hartley facility began in late November 2006.


ITEM 3.	*LEGAL PROCEEDINGS*

From time to time in our normal course of business, we are a party to various legal claims, actions and complaints. Currently, we do not have any pending litigation that we consider material.


ITEM 4.	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*

Not applicable.


ITEM 4A.	*EXECUTIVE OFFICERS OF THE REGISTRANT*

The following table sets out the names and ages of, and positions and offices held by, each of our executive officers, followed by a description of their business experience. Executive officers are appointed annually by the Board of Directors.


Name	Age		Position	Officer Since

Donald L. Endres		46	Chief Executive Officer, President and Director		2001
Robert L. Antoine, Jr.		50	Senior Vice President, Human Resources		2006
Paul J. Caudill		53	Senior Vice President, Operations		2006
Danny C. Herron		52	Senior Vice President and Chief Financial Officer		2006
William L. Honnef		40	Senior Vice President, Sales and Marketing		2001
Barry P. Schaps		54	Senior Vice President, Logistics		2007
John M. Schweitzer		62	Senior Vice President, General Counsel and Secretary		2005
Peter A. Atkins		47	Vice President, Mergers and Acquisitions		2006
Matthew K.R. Janes		50	Vice President, Technology		2002

Donald L. Endres has served as our Chief Executive Officer and a director since 2001, and has served as President since March 2007. He has more than 20 years of experience in investing in, building, operating and managing successful businesses.

Mr. Endres serves on the board of directors and on the executive committee of the Renewable Fuels Association and was awarded the 2005 Ernst & Young Entrepreneur of the Year Award for the Minnesota, South Dakota and North Dakota region. In 2000, he co-founded and served as vice-chairman of Glacial Lakes Energy, an ethanol producer in Watertown South Dakota, and he is an investor in and former board member of Badger State Ethanol, an ethanol producer in Monroe, Wisconsin.

Mr. Endres earned a bachelor of science degree in animal science with minors in computer science and economics from South Dakota State University. He was recognized by South Dakota State University’s College of Engineering as “Entrepreneur of the Year” in 2000.

Robert L. Antoine, Jr. serves as Senior Vice President, Human Resources and joined VeraSun August 2006. Mr. Antoine has more than 25 years of experience in human resources positions. Most recently, Mr. Antoine was head of human resources for Forward Air Corporation from 2002 to 2006. Previously, he served as Vice President of Human Resources for Laidlaw Transit Services, Inc, from 1995 to 2002.

Mr. Antoine graduated from the University of Kansas with a Bachelor of Science in Journalism.

Paul J. Caudill serves as Senior Vice President, Operations and joined VeraSun in late February 2006. He has over 25 years experience in architecture and engineering design, procurement and construction project management and has held senior-level positions with electric utilities in power generation plant operations. Prior to joining VeraSun, Mr. Caudill held a management position with Nebraska Public Power District from 1997 to 2006, where he was responsible for the company’s entry into the ethanol plant energy services market.

Mr. Caudill earned a bachelor of science degree in public management from the University of Arizona and in 2004 graduated from Northwestern University’s Kellogg Graduate School of Management with a masters of business administration.

Danny C. Herron serves as our Senior Vice President and Chief Financial Officer, and joined VeraSun in March 2006. Before joining the Company, Mr. Herron was executive vice president and chief financial officer of Swift & Company (an HM Capital Partners LLC portfolio company), a processor of fresh beef and pork products headquartered in Greeley, Colorado, from 2002 to 2006. He previously served as vice president and

senior financial officer of Conagra Beef Company, a beef products manufacturer headquartered in Greeley, Colorado, from 1998 to 2002.

Mr. Herron earned a masters degree in business administration from New Hampshire College and a bachelor of science degree in business administration and accounting from Valdosta State College.

William L. Honnef is one of our founders and serves as Senior Vice President, Sales and Marketing. He was president and co-founder of ExpressGold.com, Inc. until it merged with CyberSource Corporation in January 2000. Mr. Honnef served as sales director of CyberSource Corporation until leaving to start VeraSun in 2001. Mr. Honnef serves on the boards of directors of the American Coalition for Ethanol.

Mr. Honnef graduated from Indiana University of Pennsylvania with a bachelor of arts degree in information systems in 1988 and was recognized by the University as the “Eberly School of Business and Information 2000 Entrepreneur of the Year.”

Barry P. Schaps serves as Senior Vice President, Logistics and joined VeraSun in February 2007. Prior to joining VeraSun, he was General Manager, Planning and Portfolio Strategy of Motiva Enterprises, LLC, a joint venture company between affiliates of Shell Oil Company and Saudi Aramco from 2005 to 2007. Prior to that, he worked in roles of increasing responsibility with Motiva and Shell Oil Company, including as Manager Retail Logistics and Supply, Assistant to the CEO, Manager Marketing Ventures. Mr. Schaps has over 27 years experience in the petroleum industry with areas of focus in strategic planning, refining, retail marketing, supply and trading, risk management and logistics.

Mr. Schaps earned a BBA degree from the Bernard M. Baruch College of the City University of New York in 1975 majoring in accounting and an MBA in finance from Long Island University in 1980.

John M. Schweitzer serves as Senior Vice President, General Counsel and Secretary. Prior to joining VeraSun in September 2005, he had been a partner at Stoel Rives LLP for more than 25 years, where he acted as counsel to VeraSun since its organization in 2001.

Mr. Schweitzer earned a bachelor of arts degree in business administration from the University of Wisconsin — Milwaukee and masters and juris doctorate degrees from the University of Wisconsin — Madison.

Peter A. Atkins serves as Vice President, Mergers & Acquisitions and joined VeraSun July 2006. Mr. Atkins has over 25 years of regional banking and agriculture experience. Prior to joining VeraSun, Mr. Atkins was the Community Banking President/District President at Wells Fargo Bank from 2004 to 2006. Mr. Atkins managed multiple full-service locations in South Dakota and was a member of Wells Fargo’s corporate agriculture steering committee.

Mr. Atkins earned a degree in Animal Science from South Dakota State University.

Matthew K.R. Janes served as our Chief Operating Officer from January 2002 through September 2004 when he became Vice President, Technology. Mr. Janes served as a director from January 2003 to January 2005. Prior to joining VeraSun, Mr. Janes worked for 11 years with Commercial Alcohols Inc., or CAI, a manufacturer of industrial-grade alcohol and fuel-grade ethanol in Canada. He was CAI’s Vice President of Operations and Technology and was responsible for the design and start up of CAI’s 40 MMGY plant in Chatham, Ontario. Mr. Janes has also served as vice president of the Canadian Renewable Fuels Association and as a director of Agri-Development Kent, an advisory committee of the local municipal government.

Mr. Janes earned a bachelor of science degree in applied chemistry from the University of Waterloo and holds a diploma in business administration from Wilfred Laurier University. Mr. Janes has also completed both an Operations Management Program and a Financial Analysis for Executives Program at the Richard Ivey School of Business at the University of Western Ontario.

PART II


ITEM 5.	*MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.*

Market Information

We completed an initial public offering, or “IPO”, of shares of our common stock in June, 2006. Our common stock trades on the New York Stock Exchange under the symbol “VSE.” The following table sets forth the high and low closing prices for the common stock as reported on the New York Stock Exchange for the quarterly periods since our IPO. These prices do not include retail markups, markdowns or commissions.


	Low		High

Year ended December 31, 2006
Third Quarter	$	15.870	$	28.100
Fourth Quarter		15.080		25.880

On March 13, 2007, the closing price of our common stock was $16.89. As of March 13, 2007, there were approximately 582 shareholders of record of our common stock. We believe the number of beneficial owners is substantially greater than the number of record holders because a large portion of our outstanding common stock is held of record in broker “street names” for the benefit of individual investors. As of March 13, 2007, there were 76,181,326 shares outstanding.

Dividend Policy

The payment of dividends is within the discretion of our Board of Directors and will depend upon our earnings, capital requirements and operating and financial position, among other factors. We expect to retain all of our earnings to finance the expansion and development of our business, and we have not paid, and we currently have no plans to pay, cash dividends to our shareholders. The indenture underlying our senior secured notes limits, and our future debt agreements may restrict, our ability to pay dividends.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information about compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance to employees or non-employees (such as directors and consultants), at December 31, 2006.

Number of Securities

Remaining Available

for Future Issuance

Number of Securities to

Weighted-Average

Under Equity

be Issued Upon Exercise

Exercise Price of

Compensation Plans

of Outstanding Options,

Outstanding Options,

(Excluding Securities

Plan Category

Warrants and Rights

Reflected in Column a)

(a)

(b)

(c)

Equity compensation plans approved by security holders:

Stock Incentive Plan

5,291,502

7.50

3,797,530

Founders Warrants

548,258

0.52

—

Equity compensation plans not approved by security holders:

None

—

TOTAL

5,839,760

6.84

3,797,530

Use of Proceeds from Registered Securities

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 of our shares 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. We 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 us relating to the IPO were $2.8 million.

As of December 31, 2006, we had applied the $233.0 million of net proceeds we received from the IPO of our shares as follows (dollars in millions):


Construction of facilities	$	34.3
Purchase of real estate		2.6
Temporary investments		196.1

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.

Performance Graph

The following graph compares the percentage change in our cumulative total shareholder return (as measured by dividing (1) the sum of the cumulative amount of dividends for the measurement period, if any, assuming dividend reinvestment, and the difference between our share price at the end and the beginning of the measurement period by (2) the share price at the beginning of the period) with the Russell 2000 Index and VSE Peer Group as defined below. The graph assumes a $100 investment at the closing price of our stock on June 30, 2006, the last trading day of the quarter in which we completed our initial public offering. The other data points are September 29, 2006, the last trading day in our third fiscal quarter, and December 29, 2006, the last trading day in 2006. The stock performance presented below covers only a six and one-half month period; historical stock performance may not be indicative of future performance.


	6/30/06						9/29/2006									12/29/2006
	Price		% Change		Investment		Price		% Change			Investment		Price		% Change			Investment
VeraSun Energy Corporation	$	26.24		N/A	$	100.00	$	16.05		(38.8	)%	$	61.17	$	19.75		(24.7	)%	$	75.27
Peer Group*		33.07		N/A		100.00		18.57		(43.1	)		56.15		20.42		(37.5	)		61.75
Russell 2000		724.67		N/A		100.00		725.59		0.1			100.13		787.66		8.7			108.69


*		The VSE Peer Group is comprised of: Pacific Ethanol, Inc. (“PEIX”) and Aventine Renewable Energy Holdings, Inc. (“AVR”).


ITEM 6.	*SELECTED FINANCIAL DATA*

The following table presents selected consolidated financial and operating data as of the dates and for the periods indicated. The selected consolidated balance sheet financial data as of December 31, 2004, 2003 and 2002 and the selected consolidated income statement data and other financial data for the years ended December 31, 2003 and 2002 have been derived from our audited consolidated financial statements that are not included in this Form 10-K. The selected consolidated balance sheet financial data as of December 31, 2006 and 2005 and the selected consolidated income statement data and other financial data for each of the three years in the period ended December 31, 2006 have been derived from the audited Consolidated Financial Statements included elsewhere in this Form 10-K. You should read the following table in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following consolidated financial data.


	Years Ended December 31,
	2006			2005			2004			2003			2002
	(dollars in thousands, except per share data)

Income Statement data:(1)
Net sales	$	553,989		$	235,440		$	186,029		$	10,884		$	—
Other revenues, incentive income		3,828			919			7,723			1,776			—

Total revenues		557,817			236,359			193,752			12,660			—
Cost of goods sold		365,139			200,823			154,022			8,450			—

Gross profit		192,678			35,536			39,730			4,210			—
Selling, general and administrative expenses		41,060			11,874			6,140			2,233			1,226

Operating income (loss)		151,618			23,662			33,590			1,977			(1,226	)

Other income (expense):
Interest expense(2)		(37,871	)		(7,609	)		(8,892	)		(839	)		—
Other interest expense, loss on extinguishment of debt		—			(15,744	)		—			—			—
Interest income		13,618			448			182			11			5
Other		2,712			17			33			14			6

		(21,541	)		(22,888	)		(8,677	)		(814	)		11

Income (loss) before income taxes and minority interest		130,077			774			24,913			1,163			(1,215	)
Income tax expense		54,350			582			10,242			571			—

Income (loss) before minority interest		75,727			192			14,671			592			(1,215	)
Minority interest in net loss of subsidiary		—			61			100			—			—

Net income (loss)	$	75,727		$	253		$	14,771		$	592		$	(1,215	)

Earnings (loss) per common share
Basic	$	1.09		$	0.01		$	0.40		$	0.02		$	(1.21	)
Diluted		1.03			0.01			0.39			0.02			(1.21	)
Shares used in per common share calculations
Basic		69,328,436			44,810,490			36,738,191			30,380,082			1,000,076
Diluted		73,779,268			47,578,869			37,908,751			30,577,961			1,000,076
Other financial data:
EBITDA(3)	$	177,615		$	29,880		$	37,831		$	2,350			NM	(7)
Working capital (deficit)		384,067			61,551			9,779			(35,182	)		1,526
Capital expenditures(4)		131,329			87,095			25,215			63,974			5,295
Net cash provided by (used in) operating activities		97,264			(2,515	)		20,858			(10,641	)		(653	)
Net cash used in investing activities		(42,615	)		(212,049	)		(25,214	)		(63,974	)		(5,294	)
Net cash provided by financing activities		233,686			233,982			14,621			70,381			10,201
Operating data:
Ethanol sold (gallons)		224,520,662			126,346,295			101,370,470			6,459,804			—
Average gross price of ethanol sold
(dollars per gallon)(5)	$	2.18		$	1.59		$	1.50		$	1.28		$	—
Average corn cost per bushel		2.16			2.12			2.50			2.17			—
Average natural gas cost per MMBTU		8.39			9.12			6.16			—			—
Average dry distillers grains price per ton		86			87			111			—			—


	As of December 31,
	2006		2005		2004		2003		2002
	(in thousands)

Balance sheet data:
Cash and cash equivalents	$	318,049	$	29,714	$	10,296	$	31	$	4,264
Restricted cash		44,267		124,750		—		—		—
Property and equipment, net		301,720		179,683		106,753		76,882		6,223
Total assets		794,497		405,129		150,328		96,479		11,907
Total debt(6)		210,000		210,000		58,381		58,503		—
Total equity		506,431		144,918		44,476		17,594		8,567


(1)		Income statement data reflects the financial impact of operations of our Aurora facility, which commenced operations in December 2003, and our Fort Dodge facility, which commenced operations in October 2005.

(2)		Interest expense includes changes in the fair value of a put warrant of $19,670 for the year ended December 31, 2006, $2,809 for the year ended December 31, 2005, $3,481 for the year ended December 31, 2004, and $566 for the year ended December 31, 2003. The put warrant is described under Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Put warrant.”

(3)		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. EBITDA is not a measure of financial performance under Generally Accepted Accounting Principles 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 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. Management uses EBITDA as a measure of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.

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


	Year Ended December 31,
	2006		2005		2004		2003

Net income	$	75,727	$	253	$	14,771	$	592
Depreciation		9,667		5,692		3,926		348
Interest expense		37,871		23,353		8,892		839
Income tax expense		54,350		582		10,242		571

EBITDA	$	177,615	$	29,880	$	37,831	$	2,350


(4)		2006 capital expenditures includes $88.4 million spent from escrowed cash (including interest income) for construction of our Charles City, Iowa facility.

(5)		Average gross price of ethanol sold (dollars per gallon) does not include freight, commissions or other related costs, but does include related hedging gains or losses.

(6)		Total debt at December 31, 2006 and December 31, 2005 is shown before unaccreted discount of $1.1 million and $1.3 million, respectively.

(7)		NM — Not Meaningful


ITEM 7.	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*

The following discussion should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and accompanying notes included elsewhere in this Form 10-K. All references to years relate to the calendar year ended December 31 of the particular year.

Business Overview

We are one of the largest “pure-play” ethanol producers, with approximately 4% of the total production capacity in the United States, according to the RFA. We own and operate two of the largest ethanol production facilities in the United States, located in Aurora, South Dakota and Fort Dodge, Iowa, with a combined ethanol production capacity of 230 MMGY, and were the first to develop large-scale greenfield dry mill ethanol plants that exceed 100 MMGY of capacity. We were the first to create a branded E85 fuel, VE85^tm, and to enter into strategic relationships with Ford Motor Company and General Motors Corporation to increase awareness of E85 and flexible fuel vehicles. We have continued to develop new partnerships to market VE85^tm and have expanded to over 80 retail locations at the end of 2006, primarily throughout the Midwest.

We are developing and constructing additional facilities in Charles City, Iowa; Hartley, Iowa; and Welcome, Minnesota. We believe that we have adequate cash to completely fund these projects and expect to have an aggregate production capacity of 340 MMGY by the end of April 2007 and 560 MMGY by the end of the first quarter of 2008. We are also considering additional opportunities for growing our production capacity through the expansion of one or more of our existing facilities and through potential acquisitions.

We plan to continue to improve our operating efficiencies, customer and supplier relationships, as well as product and brand recognition. Our demonstrated capabilities in constructing, starting-up and operating large-scale ethanol production facilities, as well as continued study of new technologies, are expected to help drive long-term growth. We believe that our focused approach to our business and the value we bring to our customers and consumers will allow us to maintain an industry leadership position in a highly dynamic and competitive environment.

As announced in November 2006, we are developing a process to extract corn oil from distillers grains. The oil can be converted into biodiesel, thereby creating two biofuels from a single feedstock. We have also filed a provisional patent application for the extraction process. We are considering the sale of the extracted oil to others for feed or for biodiesel production. We are also considering the construction of our own biodiesel production facility.

Our financial strategy will continue to focus on maintaining strong earnings and cash flow. We believe our strategy of being a large and low-cost producer should sustain our growth and strong cash flows. We remain committed to building value for our shareholders through reinvesting in our business and continued focus on new technologies.

Executive Summary

Highlights for 2006 are as follows:


	•	Total revenues increased 136.0% or $321.5 million compared to 2005.

	•	Cash flows provided by operating activities were $97.3 million.

	•	Earnings per diluted share increased from $0.01 for 2005 to $1.03 for 2006.

These improvements in our financial results were primarily driven by a 77.7% increase in ethanol gallons sold and a 37.1% increase in the net realized price per gallon for 2006 compared to 2005.

The following are significant factors affecting our financial results for 2006:


	•	The IPO triggered accelerated vesting of stock-based compensation awards, and we issued stock awards to non-management employees. The aggregate charge for these awards was $18.2 million, or $12.8 million after tax or $0.17 per diluted share.

	•	The increased value of a warrant resulted in a charge of $19.7 million to interest expense, or $0.27 per diluted share.

	•	We received aggregate proceeds from an insurance settlement of $2.5 million, or $1.5 million after tax or $0.02 per diluted share.

Results of Operations

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


	Years Ended December 31,															Three Months Ended December 31,
	2006					2005					2004					2006				2005
																(Unaudited)				(Unaudited)

Total revenues	$	557,817		100.0	%	$	236,359		100.0	%	$	193,752		100.0	%	$	146,498	100.0	%	$	100,107		100.0	%
Cost of goods sold		365,139		65.5			200,823		85.0			154,022		79.5			105,697	72.1			75,892		75.8

Gross profit		192,678		34.5			35,536		15.0			39,730		20.5			40,801	27.9			24,215		24.2
Selling, general and administrative expenses		41,060		7.4			11,874		5.0			6,140		3.2			7,454	5.1			3,744		3.7

Operating income		151,618		27.1			23,662		10.0			33,590		17.3			33,347	22.8			20,471		20.5
Other income (expense), net		(21,541	)	(3.9	)		(22,888	)	(9.7	)		(8,677	)	(4.4	)		1,325	0.9			(17,945	)	(17.9	)

Income before income taxes and minority interest		130,077		23.2			774		0.3			24,913		12.9			34,672	23.7			2,526		2.6
Income tax expense (benefit)		54,350		9.7			582		0.2			10,242		5.3			13,233	9.0			(808	)	(0.8	)

Income before minority interest		75,727		13.5			192		0.1			14,671		7.6			21,439	14.7			3,334		3.4
Minority interest in net loss (income) of subsidiary		—		—			61		—			100		—			—	—			(652	)	(0.7	)

Net income	$	75,727		13.5	%	$	253		0.1	%	$	14,771		7.6	%	$	21,439	14.7	%	$	2,682		2.7	%

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


	Year Ended
	December 31,							Three Months Ended December 31,
	2006		2005			2004		2006			2005

Operating data:
Ethanol sold (gallons)(1)		224,520		126,346			101,370		58,103			51,277
Average gross price of ethanol sold per gallon	$	2.18	$	1.59		$	1.50	$	2.17		$	1.70
Average corn cost per bushel		2.16		2.12			2.50		2.52			1.72
Average natural gas cost per MMBTU		8.39		9.12			6.16		8.51			11.65
Average dry distillers grains gross price per ton		86		87			111		95			79

								(Unaudited)



Other financial data:
EBITDA(2)	$	177,615	$	29,880		$	37,831	$	40,537		$	22,520
Net cash flows provided by (used in) operating activities		97,264		(2,515	)		20,858		(20,108	)		(1,668	)


(1)		Includes gallons produced and used in VE85^tm sales.

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

Non-GAAP Financial Measures

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, includes financial information prepared in accordance with GAAP, as well as another financial measure, EBITDA, which is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of EBITDA information is intended to supplement an investor’s understanding of our operating performance and liquidity. Furthermore, this measure is not intended to replace net income, or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as a measure of liquidity.

We believe that EBITDA is useful to investors and management in evaluating our operating performance in relation to other companies in our industry because the calculation of EBITDA generally eliminates the effects of financings and income taxes, which items may vary for different companies for reasons unrelated to overall operating performance. EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our financial results as reported under GAAP. Some of the limitations of EBITDA are:


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

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

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

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

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

Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to us to service our debt or to invest in the growth of our business. We compensate for these limitations by relying on our GAAP results, as well as on our EBITDA.

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


	Year Ended December 31,						Three Months Ended December 31,
	2006		2005		2004		2006		2005
							(Unaudited)		(Unaudited)

Net income	$	75,727	$	253	$	14,771	$	21,439	$	2,682
Depreciation		9,667		5,692		3,926		2,502		2,375
Interest expense		37,871		23,353		8,892		3,363		18,271
Income tax expense (benefit)		54,350		582		10,242		13,233		(808	)

EBITDA	$	177,615	$	29,880	$	37,831	$	40,537	$	22,520

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Total revenues. Total revenues increased by $321.5 million, or 136.0%, to $557.8 million from $236.4 million. The increase in total revenues was primarily the result of a 77.7% increase in ethanol volume sold and an increase in average ethanol prices of $0.59 per gallon, or 37.1%, compared to 2005. The additional ethanol sales volume was due to the Fort Dodge facility being operational for all of 2006 but for only three months in 2005. With the addition of our Fort Dodge facility, we produced a total of 226.2 million gallons of fuel ethanol in 2006, compared to 128.0 million gallons in 2005.

Net sales from ethanol increased $288.3 million, or 144.4%, to $488.0 million for 2006 from $199.7 million for 2005. The average price of ethanol sold was $2.18 per gallon for 2006, compared to $1.59 per gallon for 2005. Prices improved in 2006 primarily due to increased demand for ethanol as oil companies replaced a competitive product, MTBE, from the fuel stream in a relatively short time. We expect that ethanol prices may be lower in 2007 as a result of increases in production capacity during the year.

The net gain from derivatives included in net sales was $2.4 million for 2006, compared to a net loss of $3.9 million for 2005. See “Critical Accounting Policies and Estimates — Derivative instruments and hedging activities.”

Net sales from co-products increased $23.3 million, or 66.6%, to $58.3 million for 2006 from $35.0 million for 2005. Co-product sales increased primarily as a result of the additional production volume from the Fort Dodge facility, partially offset by a decrease in the average price per ton in 2006.

Net sales of VE85^TM increased $6.8 million to $7.6 million for 2006 from $756,000 for 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 $157.1 million to $192.7 million for 2006 from $35.5 million for 2005. The increase was the result of the additional gallons sold and the higher average net realized price per gallon of ethanol for 2006 compared to 2005. Ethanol production increased by 98.2 million gallons, or 76.7% primarily as a result of the Fort Dodge facility being operational for all of 2006 and the completion of the Aurora facility expansion project at the end of June 2005.

Corn costs increased $74.1 million to $173.5 million for 2006 from $99.4 million for 2005. Corn costs represented 47.5% of our cost of goods sold before taking into account our co-product sales and 31.5% of our cost of goods sold after taking into account co-product sales for 2006, compared to 49.5% 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 2005. The increase in total corn costs was primarily the result of increased production volume from the Fort Dodge facility and the Aurora facility expansion, along with an increase in the average price per bushel of corn in the 2006 period. Corn prices have increased significantly in 2007, which is expected to have an adverse effect on our margins during the

year. See Item 1A “Risk Factors — Our business is highly sensitive to corn prices and we generally cannot pass on increases in corn prices to our customers.”

Natural gas costs increased $21.1 million to $58.2 million for 2006 from $37.1 million for 2005, and accounted for 15.9% of our cost of goods sold for 2006 compared to 18.5% of our cost of goods sold for 2005. The increase in natural gas costs was attributable to the 76.7% increase in production compared to the same period in 2005, which was offset in part by a reduction in the average natural gas prices per MMBTU in 2006.

Transportation expense increased $29.2 million to $58.5 million for 2006 from $29.3 million for 2005, primarily due to the additional volume of ethanol and co-products shipped, along with increased rail rates for 2006. Transportation expense accounted for 16.0% of our cost of goods sold for 2006 compared to 14.6% of our cost of goods sold for 2005.

Labor and manufacturing overhead costs increased $14.6 million to $32.3 million for 2006 from $17.7 million for 2005. The increase was primarily due to the Fort Dodge facility being operational in 2006 as well as $1.1 million of charges for a non-management stock grant and $770,000 of charges 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 $3.9 million for 2006, compared to a net loss of $7.9 million for 2005.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $29.2 million to $41.1 million for 2006 from $11.9 million for 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 $4.3 million was due to other charges to expense related to stock-based compensation awards. The remaining increase was primarily the result of increased management and administrative personnel over 2005 levels due to the expansion of our business, as well as expenses associated with being a public reporting company in 2006.

Other income (expense). Net other expense decreased $1.3 million to $21.5 million for 2006 from $22.9 million for 2005. The decrease was primarily due to additional interest income and $2.5 million of business interruption insurance proceeds with respect to damage to the thermal oxidizer system at the Fort Dodge facility that occurred in 2005, partially offset by increased interest expense relating to the change in the estimated fair value of a put warrant. The charges relating to the change in the estimated fair value of the put warrant were $19.7 million for 2006, compared to $2.8 million for 2005. The put warrant was exercised on June 8, 2006 and the underlying shares were sold in the IPO. The remaining increase in interest expense was attributable to higher debt levels due to the financing for the construction of the Fort Dodge and Charles City facilities. The increase in interest income related to cash and cash equivalents and restricted cash to be expended on construction.

Income taxes. The provision for income tax expense was $54.4 million and $0.6 million for 2006 and 2005, respectively. The effective tax rate for 2006 was 41.8%, compared to 75.2% for 2005. The unusual effective tax rate in 2005 was primarily the result of nondeductible expenses for the increase in value of the put warrant, partially offset by income from non-taxable consolidated subsidiaries prior to a business reorganization in 2005. In addition, 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 increased the effective tax rate in 2006.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Total revenues. Net sales increased by $49.4 million, or 26.6%, to $235.4 million for 2005 from $186.0 million for 2004. The increase in net sales was primarily the result of a 24.6% increase in the total gallons of fuel ethanol that we sold. Although nameplate capacity for our Aurora facility increased to 120 MMGY from 100 MMGY in June 2005, fuel ethanol production for 2005 for our Aurora facility was only slightly higher compared to 2004, primarily as a result of the loss of 17 production days in June 2005 during the plant expansion project. With our Fort Dodge facility commencing operations in October 2005,

however, total fuel ethanol production increased 27.4 million gallons for 2005. We produced a total of 128.0 million gallons of fuel ethanol, compared to 100.6 million gallons for 2004.

In early 2005, ethanol prices significantly decreased due to a perceived over-supply of ethanol, which had a negative effect on our operating results in the second quarter of the year. Since that time, ethanol prices have recovered significantly due to increased gasoline prices, legislative changes and continued oil refining capacity shortages, resulting in an average realized price for 2005 that is $0.10 per gallon higher than the prior year period. The CBOT spot ethanol price rose from $1.19 per gallon in May 2005 to $2.08 per gallon as of December 31, 2005. The weighted average price realized on our sales of ethanol increased to $1.59 per gallon, or 5.3%, for 2005 from $1.51 per gallon for 2004. Accordingly, net sales from ethanol increased $48.6 million, or 32.1%, to $199.7 million for 2005 from $151.1 million for 2004.

The net loss from derivatives included in net sales was $3.9 million for 2005, compared to a loss of $4.3 million for 2004.

Net sales from co-products increased $100,000, or 0.3%, to $35.0 million for 2005 from $34.9 million for 2004. Co-product sales remained largely unchanged because decreased prices resulting from lower corn prices were offset by an increase in our production volumes.

Our net sales of VE85^TM increased $702,000 to $755,000 for 2005 from $53,000 for 2004. The increase was primarily the result of an increase in the number of service stations selling our product.

Incentive income from government programs decreased $6.8 million, or 88.1%, to $0.9 million for 2005 from $7.7 million for 2004. These incentive payments are based primarily on increases in production levels from period to period, and our production did not increase for 2005 compared to 2004 because our Aurora facility was in operation for both years. Accordingly, the incentive income received for 2004 was considerably higher than 2005 due to a substantial increase in ethanol production from 2003 to 2004, and only a minor increase from 2004 to 2005. The existing federal incentive income program will terminate on June 30, 2006. In addition, government funding has been limited to $1.275 million per producer.

Cost of goods sold and gross profit. Gross profit decreased $4.2 million, or 10.6%, to $35.5 million for 2005 from $39.7 million for 2004. The decrease was primarily the result of a $2.6 million loss on disposal of equipment, decreased incentive income and higher natural gas and maintenance costs, partially offset by lower corn costs. Our average cost per bushel of corn decreased 14.9% in 2005.

Corn costs increased $9.8 million, or 10.9%, to $99.4 million for 2005 from $89.7 million in 2004. Corn costs represented 49.5% 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 2005 compared to 58.2% of our cost of goods sold before taking into account our co-product sales and 35.6% of our cost of goods sold after taking into account co-product sales for 2004. During the second quarter of 2005, the spread between ethanol and corn prices was historically narrow, primarily as a result of low ethanol prices due to concern over excess capacity arising when various markets did not require the blending of ethanol in gasoline as early as expected. In the third quarter of 2005, corn prices continued to decline and the ethanol market improved following the signing into law of the Energy Policy Act and continued oil refinery shortage concerns, resulting in historically wide spreads between ethanol and corn prices.

Natural gas costs increased $18.0 million, or 93.9%, to $37.1 million and accounted for 18.5% of our cost of goods sold for 2005 from $19.1 million and accounted for 12.4% of our cost of goods sold for 2004. The increased cost of natural gas as a percentage of our cost of goods sold was primarily attributable to increased natural gas prices during the year. The average price for natural gas increased 48.1% for 2005, as a result of colder than average weather conditions and overall economic conditions.

Transportation expense increased $6.3 million, or 27.4%, to $29.1 million for 2005 from $22.9 million for 2004, primarily as a result of an increase in our fleet of leased rail cars for our Fort Dodge facility, increased rail rates for 2005 and increased shipments as a result of higher ethanol production. Transportation expense represented 14.6% of our costs of goods sold in 2005.

Labor and manufacturing overhead costs increased $9.8 million, or 124.2%, to $17.7 million for 2005 from $7.9 million for 2004. The increase was primarily a result of the additional maintenance cost associated with the Aurora facility expansion project, annual maintenance at our Aurora facility, increased depreciation expenses and the disposal of our Aurora facility thermal oxidizer systems. The majority of the maintenance costs for our Aurora facility were covered under warranty for 2004. Labor and manufacturing overhead costs represented 8.8% of our cost of goods sold in 2005.

The net loss from derivatives included in cost of goods sold was $7.9 million for 2005, compared to a gain of $5.1 million for 2004.

The loss on disposal of equipment of approximately $2.6 million that was included in cost of goods sold in 2005 was the result of the disposal of thermal oxidizer systems that were replaced as part of the plant expansion at our Aurora facility in June 2005.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $5.7 million, or 93.4%, to $11.9 million for 2005 from $6.1 million for 2004. The increase was primarily the result of more than doubling our management and administrative staff over the prior period in anticipation of the expansion of our business due to construction of our Fort Dodge facility. Administrative salaries and benefits increased $2.8 million, or 90.8%, to $5.9 million for 2005 from $3.1 million for 2004, and operations labor increased $1.2 million, or 64.7%, to $3.0 million for 2005 from $1.8 million for 2004. Each of these increases was attributable to the construction of our Fort Dodge facility for 2005.

Expense related to stock-based compensation increased $427,000, or 59.7%, to $1.1 million for 2005 from $715,000 for 2004. The increase was primarily the result of recognizing the vesting of performance based stock options at an increased intrinsic value based on the increase in the valuation of our common stock.

Other income (expense). Net other expense increased $14.2 million, or 163.8%, to $22.9 million for 2005 from $8.7 million for 2004. The increase was primarily the result of a loss on extinguishment of debt of $15.7 million offset partially by lower expense attributable to the change in fair value of an outstanding put warrant.

Income taxes. The provision for income taxes decreased to $582,000 for 2005 from $10.2 million for 2004. The decrease was primarily the result of lower income before income taxes. The income tax provision of $582,000 for 2005 differs from the computed expected tax expense of $271,000 determined by applying the U.S. federal income tax rate to pretax income, as a result of the increase in income taxes relating largely to nondeductible expenses for the increase in value of the put warrant. This increase was partially offset by the effect of income from nontaxable consolidated subsidiaries. As a result of a business reorganization in 2005, taxable gains and losses of our consolidated subsidiaries are now taken into account by us rather than by other members.

Minority interest. Minority interest in the loss of a subsidiary decreased $39,000, or 39%, to $61,000 for 2005 from $100,000 for 2004. The decrease related to the minority interest portion of start up expenses of our Fort Dodge facility.

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 net proceeds of $233.2 million. Combined with the cash generated from operations in 2006, we had approximately $318.0 million of unrestricted cash and cash equivalents at December 31, 2006. We also had approximately

$44.3 million of cash remaining in escrow for the construction of the Charles City facility at December 31, 2006.

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


	Years Ended December 31,									Three Months Ended December 31,
	2006			2005			2004			2006			2005
										(Unaudited)			(Unaudited)

Net cash provided by (used in) operating activities	$	97,264		$	(2,515	)	$	20,858		$	(20,108	)	$	(1,668	)
Net cash used in investing activities		(42,615	)		(212,049	)		(25,214	)		(26,196	)		(139,564	)
Net cash provided by financing activities		233,686			233,982			14,621			1,707			166,101

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

We financed our operations during 2006 primarily through cash flows from operating activities. At December 31, 2006, we had total unrestricted cash and cash equivalents of $318.0 million compared to $29.7 million at December 31, 2005. Cash provided by operating activities was $97.3 million for 2006, compared to $2.5 million used by operating activities for 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.

Cash used in investing activities was $42.6 million for 2006 compared to cash used of $212.0 million in 2005, including $125.0 million deposited in escrow for the Charles City facility in 2005. The decrease was due to the completion of construction of the Fort Dodge facility in October 2005, along with completion of financing for the Charles City facility.

Cash provided by financing activities for 2006 was $233.7 million, compared to $234.0 million provided by financing activities for 2005. In 2005 we refinanced the project debt of the Fort Dodge facility and financed the construction of the Charles City facility, while 2006 included the net proceeds from our IPO.

As of December 31, 2006, we had total debt of $210.0 million, before $1.1 million of unaccreted debt discount. In addition, we had total borrowing capacity of $30.0 million under our credit agreement. Letters of credit in an aggregate amount of $3.7 million have been issued under our credit agreement, leaving $26.3 million of remaining borrowing capacity at December 31, 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, Hartley and Welcome facilities, we may also consider additional opportunities for growing our production capacity, including the expansion of one or more of our existing facilities and the development of sites acquired under our agreement with American Milling, LLP, or American Milling, a grain processing and transportation company. The agreement provides

for the acquisition from time to time of rights to purchase or lease real property sites suitable for future construction and operation of ethanol production facilities. American Milling has identified a number of potential sites and has acquired or is in the process of acquiring rights either to purchase or lease them.

On March 1, 2007, we agreed to accept an American Milling site located near Reynolds, Indiana. As consideration for the site, we are obligated to issue 300,000 shares of our Common Stock, of which 150,000 shares were issued to American Milling on March 15, 2007. The remaining 150,000 shares will be issued upon receipt of the required construction permits for the proposed ethanol facility, but no later than March 15, 2008.

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. In 2007, we expect to spend between $400 million and $450 million for the construction of our Charles City, Hartley and Welcome ethanol production facilities, the development of alternative technologies, facility maintenance, operational improvements and further development of possible ethanol facility sites.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations

The following summarizes our contractual obligations as of December 31, 2006. Our obligations are likely to increase significantly as we enter into agreements in connection with the construction of our Hartley and Welcome facilities (in thousands).


Types of Obligations	2007		2008		2009		2010		2011		Thereafter		Total

Long-term debt obligations(1)	$	20,813	$	20,813	$	20,738	$	20,738	$	20,738	$	230,738	$	334,578
Operating lease obligations		10,241		24,228		25,404		25,404		25,404		89,106		199,787
Purchase obligations(2)		4,783		6,336		5,993		5,908		5,388		29,886		58,294
Other purchase obligations(3)		115,978		6,774		612		—		—		—		123,364

Total contractual obligations	$	151,815	$	58,151	$	52,747	$	52,050	$	51,530	$	349,730	$	716,023


(1)		Amounts represent principal and interest payments due on the senior secured notes and unused commitment fees under our credit agreement.

(2)		Purchase obligations include estimated payments for electricity and water supply agreements and natural gas purchase contracts.

(3)		Other purchase obligations include corn contracts and a multi-year corn purchase agreement under which we expect to take delivery. To quantify the purchase obligation under certain of our corn contracts and our multi-year corn purchase agreement, we have used our December 31, 2006 published bid prices for corn.

Critical Accounting Policies and Estimates

Our MD&A is based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements requires the use of estimates and

assumptions which are based upon management’s current judgment. The process used by management encompasses its knowledge and experience about past and current events and certain assumptions on future events. The judgments and estimates regard the effects of matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We consider an accounting estimate to be critical if:


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

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

Management has discussed the development and selection of critical accounting policies and estimates with the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the foregoing disclosures. In addition, there are other items within our financial statements that require estimation, but are not deemed critical, as defined above.

Revenue recognition. Revenue from the production of ethanol and its co-products is recorded when title transfers to customers. Ethanol and its co-products have generally been shipped FOB our plants. Shipping and handling charges to customers are included in revenues. In accordance with our marketing agreement with Aventine, sales were recorded net of commissions retained by Aventine at the time payment is remitted. Commencing April 1, 2007, we will sell our ethanol directly to customers. We expect that our sales of ethanol will generally occur upon delivery to our customers at terminals or other locations, rather than upon shipment from our plants.

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

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

When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with subsequent changes in its fair value recognized in current-period income. Effective September 1, 2005, we de-designated hedge accounting for all of our exchange traded futures contracts related to our corn positions.

Put warrant. The value of the warrant was adjusted periodically to the formula-based put value of the warrant. Changes in the value of the warrant were recognized on the balance sheet in the period of change and included in our statement of income as interest expense. Upon the closing of our IPO, cumulative interest expense of $19.7 million was recorded to adjust the outstanding put warrant to the

initial public offering price of our Common Stock. The put feature terminated upon the exercise of the warrant and sale of the shares underlying the warrant in the IPO. Upon completion of the IPO, the long-term liability associated with the put warrant, increased as described above, was reclassified into shareholders’ equity so that the net impact on our shareholders’ equity was an increase of $7.5 million.

Stock-based compensation. Effective January 1, 2006, we adopted FASB Statement No. 123R, using the modified prospective application method. Prior to the adoption of FASB Statement No. 123R, we accounted for stock-based compensation in accordance with Accounting Principles Board or, “APB”, Opinion No. 25, and related interpretations (the intrinsic value method), and, no stock-based employee compensation was recognized for grants under fixed stock option awards for those awards that had an exercise price equal to the market value of the underlying common stock on the date of the grant and, accordingly, stock-based compensation was only recognized in connection with the issuance of variable performance-based stock options and restricted stock. FASB Statement No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the statement of operations based on their fair values.

The Company uses the Black-Scholes single option pricing model to determine the fair value for employee stock options, which can be affected by the Company’s stock price and several subjective assumptions, including:


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

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

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

If our estimates to calculate the fair value for employee stock options are not consistent with actual results, we may be exposed to gains or losses that could be material. See Note 12 of our Consolidated Financial Statements.

Property and equipment: Property and equipment are stated at cost. Depreciation is computed by the straight-line method over the following estimated useful lives:


	Years

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

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

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

Goodwill: Goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to identified tangible and intangible assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually or more frequently if certain impairment conditions arise.


ITEM 7A.	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*

In addition to risks inherent in our operations, we are exposed to various market risks. As a commodity-based business, we are subject to a variety of market factors, including the price relationship between ethanol and corn. During 2006, we experienced strong ethanol demand due to the phase-out of MTBE, leading to tightened ethanol supply and favorable ethanol prices. In 2006, we experienced historically wide spreads between the price of ethanol and the price of corn, as shown in the following graph:

Ethanol and Corn Price Comparison


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

We consider market risk to be the potential loss arising from adverse changes in market rates and prices. We are subject to significant market risk with respect to the price of ethanol, our principal product, and the price and availability of corn, the principal commodity used in our ethanol production process. In general, ethanol prices are influenced by the supply and demand for gasoline, the availability of substitutes and the effect of laws and regulations. Higher corn costs result in lower profit margins and, therefore, represent unfavorable market conditions. Traditionally, we have not been able to pass along increased corn costs to our ethanol customers. The availability and price of corn are subject to wide fluctuations due to unpredictable factors such as weather conditions during the corn growing season, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture and international supply and demand. Corn costs represented approximately 47.5% of our total cost of goods sold for 2006, compared to 49.5% for 2005. Over the ten-year period from 1997 through 2006, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $3.90 per bushel in 2006, with prices averaging $2.32 per bushel during this period. At December 31, 2006, the CBOT price per bushel of corn was $3.90.

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 15.9% of our cost of goods sold for 2006, compared to 18.5% for 2005. The price fluctuation in natural gas prices over the six-year period from December 31, 2000 through December 31, 2006, based on the NYMEX daily futures data, has ranged from a low of $1.83 per MMBTU in 2001 to a high of $15.38 per MMBTU in 2005, averaging $5.86 per MMBTU during this period. At December 31, 2006, the NYMEX price of natural gas was $6.30 per MMBTU.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our corn and natural gas requirements, ethanol contracts and the related exchange-traded contracts for 2006. Market risk related to these factors is estimated as the potential change in pre-tax income, resulting from a hypothetical 10% adverse change in the fair value of our corn and natural gas requirements and ethanol contracts (based on average prices for 2006) net of the corn and natural gas forward and futures contracts used to hedge our market risk with respect to our corn and natural gas requirements. The results of this analysis, which may differ from actual results, are as follows:


								Change in
	Volume				Hypothetical Adverse			Annual
	Requirements		Units		Change in Price			Pre-Tax Income
	(In millions)							(In millions)

Ethanol		224.5		gallons		10	%	$	(48.9	)
Corn		80.4		bushels		10			(17.4	)
Natural gas		6.9		MMBTU		10			(5.8	)

As of December 31, 2006, approximately 3.2% of our estimated ethanol sales for the next twelve months was subject to fixed price contracts. In addition, we had contracted forward on a fixed price basis the following quantities of corn and natural gas, which represent the indicated percentages of our estimated requirements for these inputs for the next twelve months:


	Three Months			Three Months			Three Months			Three Months			Twelve Months
	Ended			Ended			Ended			Ended			Ended
	March 31,			June 30,			September 30,			December 31,			December 31,
	2007			2007			2007			2007			2007

Corn (thousands of bushels)(1)		1,474			919			0			72			2,440
Percentage of estimated requirements		7	%		3	%		—	%		0.2	%		2	%

Natural Gas (MMBTU)		720,000			—			—			—			720,000
Percentage of estimated requirements		43	%		—	%		—	%		—	%		8	%


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

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

Report of Independent Registered Public Accounting Firm

To the Board of Directors

VeraSun Energy Corporation

Brookings, South Dakota

We have audited the consolidated balance sheets of VeraSun Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity and comprehensive income and cash flows for each of the years in the three year period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of VeraSun Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2006 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Statement No. 123(R) Share-Based Payment in 2006.

/s/ McGladrey & Pullen, LLP

Sioux Falls, South Dakota

March 27, 2007

VERASUN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31, 2006 and 2005


	2006			2005
	(dollars in thousands, except per share data)

ASSETS (Note 7)
Current Assets
Cash and cash equivalents	$	318,049		$	29,714
Receivables (Notes 3, 6, 11, and 14)		62,549			28,663
Inventories (Notes 4 and 6)		39,049			19,291
Prepaid expenses		4,187			4,611
Derivative financial instruments (Note 11)		12,382			—
Deferred income taxes (Note 9)		—			5,839

Total current assets		436,216			88,118

Other Assets
Restricted cash held in escrow (Note 7)		44,267			124,750
Debt issuance costs, net of accumulated amortization of $994 in 2006 and $39 in 2005 (Note 7)		5,685			6,449
Goodwill		6,129			6,129
Deposits		480			—

		56,561			137,328

Property and Equipment, net (Note 5)		301,720			179,683

	$	794,497		$	405,129


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Current portion of deferred revenues (Note 10)	$	96		$	95
Accounts payable		36,391			20,055
Accrued expenses		2,961			1,991
Derivative financial instruments (Note 11)		11,331			4,426
Deferred income taxes (Note 9)		1,370			—

Total current liabilities		52,149			26,567

Long-Term Liabilities
Long-term debt (Note 7)		208,905			208,719
Deferred revenues, less current portion (Note 10)		1,613			1,710
Convertible put warrant (Note 8)		—			7,458
Deferred income taxes (Note 9)		25,399			15,757

		235,917			233,644

Commitments and Contingencies (Notes 11, 13 and 14)
Shareholders’ Equity (Notes 2, 8, 9, 11 and 12)
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; 75,463,640 and 62,492,722 shares issued and outstanding in 2006 and 2005, respectively		755			625
Additional paid-in capital		417,049			132,848
Retained earnings		89,589			13,862
Deferred compensation		—			(107	)
Accumulated other comprehensive loss		(962	)		(2,310	)

		506,431			144,918

	$	794,497		$	405,129

See Notes to Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, 2006, 2005 and 2004


	2006			2005			2004
	(dollars in thousands, except per share data)

Revenues:
Net sales (Notes 11 and 14)	$	553,989		$	235,440		$	186,029
Other revenues, incentive income		3,828			919			7,723

Total revenues		557,817			236,359			193,752

Cost of goods sold:
Costs and expenses of production (Note 11)		365,036			198,183			154,021
Loss on disposal of equipment (Note 5)		103			2,640			1

Total cost of goods sold		365,139			200,823			154,022

Gross profit		192,678			35,536			39,730
Selling, general and administrative expenses		41,060			11,874			6,140

Operating income		151,618			23,662			33,590

Other income (expense):
Interest expense, including change in fair value of convertible put warrant of $19,670 in 2006, $2,809 in 2005 and $3,481 in 2004 (Notes 6, 7 and 8)		(37,871	)		(7,609	)		(8,892	)
Other interest expense, loss on extinguishment of debt (Note 7)		—			(15,744	)		—
Interest income		13,618			448			182
Other (Note 15)		2,712			17			33

		(21,541	)		(22,888	)		(8,677	)

Income before income taxes and minority interest		130,077			774			24,913
Income tax expense (Note 9)		54,350			582			10,242

Income before minority interest		75,727			192			14,671
Minority interest in net loss of subsidiary		—			61			100

Net income	$	75,727		$	253		$	14,771

Earnings per common share:
Basic	$	1.09		$	0.01		$	0.40
Diluted		1.03			0.01			0.39
Weighted average shares outstanding:
Basic		69,328,436			44,810,490			36,738,191
Diluted		73,779,278			47,578,869			37,908,751
Pro forma amounts as if all subsidiaries were taxable for entire period (Note 1) (unaudited):
Pro forma income tax expense	$	54,350		$	1,839		$	9,862
Pro forma net income (loss)		75,727			(1,004	)		15,151
Pro forma earnings (loss) per common share:
Basic	$	1.09		$	(0.02	)	$	0.41
Diluted		1.03			(0.02	)		0.40

See Notes to Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME

Years Ended December 31, 2006, 2005 and 2004


													Accumulated
				Additional			Retained						Other
	Common			Paid-In			Earnings			Deferred			Comprehensive
	Stock			Capital			(Deficit)			Compensation			Loss			Total
	(dollars in thousands)

Balance, December 31, 2003	$	310		$	18,669		$	(1,162	)	$	—		$	(223	)	$	17,594
Issuance of 12,093,106 shares of common stock		121			13,303			—			—			—			13,424
Issuance of restricted stock (Note 12)		2			178			—			(180	)		—			—
Stock-based compensation (Note 12)		—			678			—			—			—			678
Amortization of deferred compensation		—			—			—			37			—			37
Purchase of treasury stock		(3	)		(210	)		—			—			—			(213	)
Reissuance of treasury stock		3			210			—			—			—			213
Comprehensive income:
Net income		—			—			14,771			—			—
Unrealized loss on hedging activities (Note 11)		—			—			—			—			(2,028	)
Comprehensive income																	12,743

Balance, December 31, 2004		433			32,828			13,609			(143	)		(2,251	)		44,476
Issuance of 19,238,183 shares of common stock		192			98,914			—			—			—			99,106
Stock-based compensation (Note 12)		—			1,106			—			—			—			1,106
Amortization of deferred compensation		—			—			—			36			—			36
Comprehensive income:
Net income		—			—			253			—			—
Unrealized loss on hedging activities (Note 11)		—			—			—			—			(59	)
Comprehensive income																	194

Balance, December 31, 2005		625			132,848			13,862			(107	)		(2,310	)		144,918
Issuance of 11,000,000 shares of common stock (Note 2)		110			233,057			—			—			—			233,167
Issuance of restricted stock (Note 12)		3			—			—			—			—			3
Stock-based compensation (Note 12)		—			22,345			—			107			—			22,452
Exercise of stock options and warrants (Note 12)		17			351			—			—			—			368
Excess tax benefits from share-based payment arrangements (Note 12)		—			1,320			—			—			—			1,320
Extinguishment of convertible put warrant liability (Note 8)		—			27,128			—			—			—			27,128
Comprehensive income:
Net income		—			—			75,727			—			—
Unrealized gain on hedging activities (Note 11)		—			—			—			—			1,348
Comprehensive income		—			—			—			—			—			77,075

Balance, December 31, 2006	$	755		$	417,049		$	89,589		$	—		$	(962	)	$	506,431

See Notes to Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2006, 2005 and 2004


	2006			2005			2004
	(dollars in thousands)

Cash Flows from Operating Activities
Net income	$	75,727		$	253		$	14,771
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		9,667			5,692			3,926
Amortization of debt issuance costs and debt discount		1,141			325			171
Accretion of deferred revenue		(96	)		(96	)		(95	)
Minority interest in net loss of subsidiary		—			(61	)		(100	)
Debt issuance costs and debt discount expensed on extinguishment of debt		—			2,387			—
Change in fair value of convertible put warrant		19,670			2,809			3,481
Change in derivative financial instruments		(3,402	)		615			1,011
Deferred income taxes		16,124			410			10,127
Loss on disposal of equipment		103			2,640			1
Stock-based compensation		22,452			1,142			715
Excess tax benefits from share-based payment arrangements		(1,320	)		—			—
Changes in current assets and liabilities:
(Increase) decrease in:
Receivables		(33,886	)		(13,915	)		(4,532	)
Inventories		(19,758	)		(6,843	)		(7,070	)
Prepaid expenses		424			(3,655	)		(338	)
Increase (decrease) in:
Accounts payable		9,448			5,020			(1,761	)
Accrued expenses		970			762			551

Net cash provided by (used in) operating activities		97,264			(2,515	)		20,858

Cash Flows from Investing Activities
Investment in restricted cash		—			(125,000	)		—
Proceeds from sale of equipment		838			46			1
Purchases of property and equipment		(42,973	)		(87,095	)		(25,215	)
Payments of deposits		(480	)		—			—

Net cash used in investing activities		(42,615	)		(212,049	)		(25,214	)

Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			—			(738	)
Proceeds from long-term debt		—			208,711			27,626
Principal payments on long-term debt		—			(58,890	)		(27,822	)
Net borrowings on notes payable		—			—			1,000
Net proceeds from issuance of common stock		233,170			90,138			12,493
Net proceeds from the issuance of stock options and warrants		368			—			—
Proceeds from issuance of minority interest in subsidiary		—			—			3,000
Excess tax benefits from share-based payment arrangements		1,320			—			—
Debt issuance costs paid		(1,172	)		(5,977	)		(938	)

Net cash provided by financing activities		233,686			233,982			14,621

Net increase in cash and cash equivalents		288,335			19,418			10,265
Cash and Cash Equivalents
Beginning		29,714			10,296			31

Ending	$	318,049		$	29,714		$	10,296

See Note 18 for supplemental disclosures of cash flow information.

See Notes to Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except per share data)


Note 1.	Nature of Business and Significant Accounting Policies

Nature of business: VeraSun Energy Corporation (“VEC” or “Parent”) is the parent corporation of the following wholly owned subsidiaries as of December 31, 2006: VeraSun Aurora Corporation (“VAC”), VeraSun Fort Dodge, LLC (“VFD”), VeraSun Marketing, LLC (“VM”), VeraSun Charles City, LLC (“VCC”), VeraSun Welcome, LLC (“VW”), VeraSun Hartley, LLC (“VH”), VeraSun Reynolds, LLC (“VRL”), VeraSun Granite City (“VGC”) and VeraSun BioDiesel, LLC (“VBD”).

VAC owns and operates an ethanol plant located near Aurora, South Dakota with an annual capacity of 120 million gallons. VFD owns and operates an ethanol plant located near Fort Dodge, Iowa with an annual capacity of 110 million gallons. VM markets and distributes E85 (an alternative fuel comprised of a blend of 85% ethanol and 15% gasoline) to gasoline retailers. VCC, VW and VH are development stage companies that are constructing ethanol plants near Charles City, Iowa; Welcome, Minnesota; and Hartley, Iowa; respectively, each with planned annual capacity of 110 million gallons. VH was formed in the second quarter of 2006. VRL and VGC were formed in the fourth quarter of 2006 and are development stage companies with no operations. VBD is also a development stage company that is researching the extraction of corn oil as an additional co-product in the ethanol production process. VEC and its subsidiaries are collectively referred to as the “Company”.

A summary of the Company’s significant accounting policies follows:

Principles of consolidation: The accompanying consolidated financial statements include the accounts of the Parent and its subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue recognition: Revenues from the production of ethanol and related products are recorded when title transfers to customers. Ethanol and related products are generally shipped FOB shipping point. Shipping and handling charges to customers are included in revenues.

The Company receives incentives to produce ethanol from state and federal entities. In accordance with the terms of these arrangements, incentive income is recorded in revenues based on the production of ethanol or blending of E85.

In accordance with the Company’s agreements for the marketing and sale of ethanol and related products, commissions due to the marketers are deducted from the gross sales price at the time payment is remitted to the Company. Ethanol sales are recorded net of commissions of $981, $1,037 and $1,001 in 2006, 2005 and 2004, respectively.

Cost of goods sold primarily includes costs for raw material, inbound freight charges, purchasing and receiving costs, inspection costs, shipping costs, other distribution expenses, warehousing costs, plant management, certain compensation costs, and general facility overhead charges.

Selling, general, and administrative expenses consists primarily of salaries and expenses for employees located at the Company’s corporate headquarters, as well as fees paid to outside service providers such as legal, audit and consulting firms.

Cash and cash equivalents: For the purposes of reporting cash flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents,

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

except cash restricted for the construction of property and equipment. Cash and cash equivalents as of December 31, 2006, includes $324,889, which is not federally insured. Of these amounts, $19,825 is held by one commercial bank and $305,064 by several investment banks. Cash equivalents consist of commercial paper and money market mutual funds, among other short-term instruments.

Receivables: Receivables are carried at original invoice amount less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer’s financial condition, credit history and current economic conditions. Receivables are written off when deemed uncollectible. Recoveries of receivables previously written off are recorded when received. A receivable is considered to be past due if any portion of the receivable balance is outstanding for more than 90 days.

Inventories: Corn, chemicals, supplies and work in process inventories are stated at the lower of cost or market on the first-in first-out method. Ethanol and distillers grains are stated at the lower of average cost (determined quarterly) or market.

Derivatives and hedging activities: Derivatives are recognized on the balance sheet at their fair value and are included in the accompanying balance sheets as “derivative financial instruments”. On the date the derivative contract is entered into, the Company may designate the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (“cash flow” hedge). Changes in the fair value of a derivative that is highly effective and that is designated and qualifies 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). Changes in the fair value of undesignated derivative instruments are reported in current period earnings. The Company may elect to create a hedging relationship for forward purchase contracts by selling an exchange traded futures contract as an offsetting position. In this situation, the forward purchase contract may be designated to be valued at market price until delivery is made against the contract. For the statement of cash flows, the Company categorizes the cash flows relating to hedging activities in the same category as the item being hedged.

The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedged transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

The Company discontinues hedge accounting prospectively when (1) it is determined that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item (including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; or (3) the derivative is de-designated as a hedge instrument because it is unlikely that a forecasted transaction will occur or when management determines that designation of the derivative as a hedge instrument is no longer appropriate.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Company’s derivative positions related to corn are undesignated instruments where changes in the fair value of these economic hedges are included in cost of goods sold in the income statements. The Company designates exchange traded futures transactions related to its position in unleaded gasoline and natural gas as cash flow hedges. Income statement effects of unleaded gasoline futures contracts and natural gas futures contracts are included in net sales and cost of goods sold, respectively.

Income taxes: VeraSun, LLC (“VSL”) and VFD’s operations were taxed as partnerships under the provisions of the Internal Revenue Code through September 30, 2005 and December 31, 2005, respectively. Under these provisions, their net income (loss) was reported on the individual income tax returns of their members. Accordingly, no provision/benefit or asset/liability for income taxes was reflected in these financial statements relative to the income or loss of VSL or VFD through those dates for interests in those activities held by members other than VAC. VSL was dissolved in December 2005. Effective with the Company’s reorganization in 2005, income taxes payable to (refundable from) the Internal Revenue Service are calculated based on the consolidated income of the Parent and all its subsidiaries. Prior to the reorganization, the income tax provision only related to the income of VAC.

Deferred taxes are provided on an asset and liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carryforwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Debt issuance costs: Debt issuance costs are stated at cost, less accumulated amortization. Debt issuance costs are amortized over the term of the related debt by a method which approximates the interest method. Amortization of debt issuance costs was $955, $278 and $97 during 2006, 2005 and 2004, respectively. Future amortization of debt issuance costs, based on debt outstanding as of December 31, 2006, is expected to be approximately $954 for each upcoming year until 2012. The amounts outstanding in relation to the existing debt at the time of the refinancing in December 2005 of $1,917 were fully expensed in 2005 as part of loss on extinguishment of debt in the statement of income.

Property and equipment: Property and equipment are stated at cost. Depreciation is computed by the straight-line method over the following estimated useful lives:


	Years

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

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

Construction in progress as of December 31, 2006 primarily relates to the VCC facility and will be depreciated upon the commencement of operations of the Charles City ethanol plant, which is expected to occur in 2007.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Goodwill: Goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually or more frequently if certain impairment conditions arise.

Long-lived assets: The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amounts of those assets.

Convertible put warrant: The value of the convertible warrant was adjusted to the formula based put value. Changes in the put price were recognized on the balance sheet in the period of change and were included in the Company’s statements of income as interest expense. The put warrant was exercised and the related shares were sold during 2006 (Note 8).

Deferred revenue: Proceeds received from the issuance of tax increment bonds are recorded as deferred revenue and are being amortized into income over the life of the related property and equipment, which is 21 years.

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

A reconciliation of the common stock share amounts used in the calculation of basic and diluted EPS is as follows for the years ended December 31:


			Weighted
			Average
	Net		Shares		Per Share
	Income		Outstanding		Amount

2006:
Basic EPS	$	75,727		69,328,436	$	1.09
Effects of dilutive securities:
Exercise of stock options and warrants		—		4,450,842		(0.06	)

Diluted EPS	$	75,727		73,779,278	$	1.03

2005:
Basic EPS	$	253		44,810,490	$	0.01
Effects of dilutive securities:
Exercise of stock options and warrants		—		2,768,379		—

Diluted EPS	$	253		47,578,869	$	0.01

2004:
Basic EPS	$	14,771		36,738,191	$	0.40
Effects of dilutive securities:
Exercise of stock options and warrants		—		1,170,560		(0.01	)

Diluted EPS	$	14,771		37,908,751	$	0.39

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Stock option awards outstanding for 1,426,640 shares of common stock at a weighted average exercise price of $23.04 were not included in diluted earnings per common share in 2006 as the awards were antidilutive.

Warrants outstanding for 1,475,681 shares of common stock at an exercise price of $0.52 were not included in the computation of diluted earnings per common share for the years ended December 31, 2005 and 2004, because the related performance conditions had not been met.

Performance stock option awards of 972,785 shares of common stock at a weighted average exercise price of $1.02 during 2004 and performance stock option awards of 912,078 shares of common stock at a weighted average exercise price of $1.94 during 2005 were not included in diluted earnings per common share since the accounting “grant date” had not yet occurred.

Stock-based compensation: Effective January 1, 2006, the Company adopted Financial Accounting Standards Board (“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).

For periods prior to January 1, 2006 under APB Opinion No. 25, no stock-based employee compensation was recognized for grants under fixed stock option awards for those awards that had an exercise price equal to the market value of the underlying common stock on the date of grant and, accordingly, stock-based compensation was only recognized in connection with the issuance of variable performance-based stock options and restricted stock. The Company recognizes compensation expense for awards with graded vesting using the straight line method over the entire vesting period for those awards.

The following table illustrates the pro forma effect on net income and per common share information had the Company accounted for stock-based compensation in accordance with FASB Statement No. 123R for the years ended December 31, 2005 and 2004:


	Years Ended December 31,
	2005			2004

Net income, as reported	$	253		$	14,771
Add actual employee stock-based compensation expense related to stock options and restricted stock included in reported net income, net of related tax effects		754			472
Deduct proforma employee stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		(1,713	)		(670	)

Pro forma net income (loss)	$	(706	)	$	14,573

Basic EPS:
As reported	$	0.01		$	0.40
Pro forma		(0.02	)		0.40
Diluted EPS:
As reported		0.01			0.39
Pro forma		(0.02	)		0.38

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Recent accounting pronouncements: In July 2006, the 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 tax positions 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 relating to tax positions taken.

The provisions of FIN 48 are effective as of the beginning of the Company’s 2007 fiscal year, 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, but does not expect the adoption of this statement to be significant to the Company’s consolidated financial statements.

In September 2006, the Securities and Exchange Commission (“SEC”) staff issued Staff Accounting Bulletin 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 requires that public companies utilize a “dual-approach” to assessing the quantitative effects of financial misstatements. This dual approach includes both an income statement focused assessment and a balance sheet focused assessment. The Company adopted SAB 108 in the quarter ended December 31, 2006 without any impact on the Company’s consolidated financial statements.

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements. FASB Statement No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. Specifically, it sets forth a definition of fair value, and establishes a hierarchy prioritizing the inputs to valuation techniques, giving the highest priority to quoted prices in active markets for identical assets and liabilities and the lowest priority to unobservable inputs. The provisions of FASB Statement No. 157 are generally required to be applied on a prospective basis, except to certain financial instruments accounted for under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, for which the provisions of FASB Statement No. 157 should be applied retrospectively. The Company will adopt FASB Statement No. 157 in the first quarter of 2008 and is evaluating the effect, if any, on its financial position or results of operations.

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115, which provides all entities, including not-for-profit organizations, with an option to report selected financial assets and liabilities at fair value. The Company will adopt FASB Statement No. 159 in the first quarter of 2008 and is evaluating the effect, if any, on its financial position or results of operations.

Advertising costs: Advertising and promotion costs are expensed when incurred. Advertising costs during 2006, 2005 and 2004 were $1,250, $468 and $240, respectively.

Research and development costs: Research and development costs are expensed as incurred. Total research and development costs incurred in connection with the research of extracting corn oil as an additional co-product in the ethanol process were charged to selling, general and administrative expenses and were $657, $217 and $11 for 2006, 2005 and 2004, respectively.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Fair value of financial instruments: The following methods and assumptions were used by the Company in estimating the fair value of its financial instruments:

Cash and cash equivalents: The carrying value of cash and cash equivalents was $318,049 and $29,714 at December 31, 2006 and 2005, respectively. The carrying amounts approximate fair values due to the relatively short maturity of these instruments.

Restricted cash held in escrow: The carrying value of restricted cash was $44,267 and $124,750 at December 31, 2006 and 2005, respectively. The carrying amounts approximate fair value due to the relatively short maturity of the instruments.

Long-term debt: The carrying value and fair value of long-term debt were $208,905 and $222,075, respectively, at December 31, 2006. The carrying value and fair value of long-term debt were $208,719 and $213,150, respectively, at December 31, 2005. The fair value of the Company’s long-term debt at December 31, 2006 and 2005 was estimated based on quoted market prices.

Derivatives and warrant: The carrying values of commodity derivatives were assets of $12,382 and liabilities of $11,331 at December 31, 2006 and assets of $1,382 and liabilities of $5,808 at December 31, 2005. The carrying values of the convertible put warrant were $0 and ($7,458), respectively, at December 31, 2006 and 2005. These instruments are recorded at fair value on the accompanying balance sheets, with such fair value determined based on quoted market prices or formula value.

Segment reporting: Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company’s operating segments are aggregated into the “Ethanol Production” and “All Other” reportable segments because the long-term financial performance of these reportable segments is affected by similar economic conditions. See Note 16.


Note 2.	Initial Public Offering

On June 13, 2006, the Company’s Form S-1 filed with the SEC 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.

The IPO price was $23 per share. The Company and the selling shareholders received total proceeds of $235,923 and $214,207, respectively, after the deduction of underwriting discounts of $17,077 and $15,506, respectively. Net proceeds to the Company were $233,167, after the deduction of costs of raising capital of $2,756.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Note 3. Receivables

A summary of receivables at December 31 is as follows:


	2006		2005

Trade, less allowance for doubtful accounts of $65 and $10 for 2006 and 2005, respectively	$	32,194	$	19,575
Broker — FCStone, LLC		15,390		7,385
Income taxes		12,380		—
Other		2,585		1,703

	$	62,549	$	28,663


Note 4.	Inventories

A summary of inventories at December 31 is as follows:


	2006		2005

Corn	$	24,492	$	9,023
Supplies		7,084		3,890
Chemicals		1,214		1,231
Work in process		2,489		1,150
Distillers grains		431		396
Ethanol		3,339		3,601

	$	39,049	$	19,291


Note 5.	Property and Equipment

A summary of property and equipment at December 31 is as follows:


	2006		2005

Land and land improvements	$	17,229	$	10,351
Construction in progress		117,217		991
Buildings and improvements		4,072		3,721
Machinery and equipment		179,855		172,688
Office furniture and equipment		2,638		1,681

		321,011		189,432
Less accumulated depreciation		19,291		9,749

	$	301,720	$	179,683

The Company incurred a loss on disposal of equipment during 2005 of $2,640 attributable to the VAC plant expansion.


Note 6.	Notes Payable

Credit facility: On December 21, 2005, the Company entered into a bank agreement for a $30,000 revolving credit agreement with a $10,000 sublimit for letters of credit. Loan advances under the agreement have a borrowing base limitation based on a percentage of eligible receivables and

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

outstanding inventory. As of December 31, 2006, funds of $30,000 were available to be drawn as computed under the borrowing base limitation, of which $3,679 in irrevocable stand-by letters of credit were outstanding, leaving $26,321 remaining unused borrowing capacity. The agreement bears interest at LIBOR plus the applicable margin of 2.5% as of December 31, 2006, for a total rate of 7.83%. The agreement has an expiration date of December 31, 2008 and is secured by a first priority lien on all of the Parent’s and certain of its subsidiaries’ accounts receivable, inventories and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which such proceeds are deposited). The agreement contains restrictive covenants relating to certain financial measurements and ongoing financial reporting requirements to the lender. In addition, the agreement provides for an unused commitment fee ranging from 0.15% to 0.25% (based on working capital levels) of the average unused portion of the $30,000 commitment, after deducting any letters of credit outstanding under the agreement, and a letter of credit fee equal to 2.25% of the amount of outstanding letters of credit. As of December 31, 2006 and 2005, no loans were outstanding under the agreement.

Related party notes: On July 28, 2005, the Company entered into a line of credit agreement of $1,000 with its Chief Executive Officer. On November 14, 2005, the Company issued a secured promissory note of $1,300 to its Chief Executive Officer. On November 14, 2005, the Company also issued an unsecured promissory note of $800 to its Chief Executive Officer. All of these notes were paid in full by December 2005. Total interest incurred under the notes was $24 during 2005.

During 2004, the Company entered into a $1,000 unsecured line of credit promissory note and an unsecured term note with its Chief Executive Officer. These notes were paid in full in 2004. Total interest incurred under the notes was $32 during 2004.

During 2004, a related party loaned the Company $1,000. This loan was converted into shares of common stock during 2004. Total interest incurred under the loan was $22 during 2004.


Note 7.	Long-Term Debt and Restricted Cash

Long-term debt at December 31 consists of:


	2006		2005

9.875% Senior secured notes, due in semi-annual interest only payments for seven years commencing June 15, 2006, collateralized by a first priority lien on an initial $125,000 escrow and substantially all the assets of the Company except for assets pledged as security for the revolving credit agreement(a)	$	208,905	$	208,719
Less current maturities		—		—

	$	208,905	$	208,719


(a)		On December 21, 2005, the Company issued $210,000 of senior secured notes. The notes bear interest at a fixed rate of 9.875% and are net of unamortized debt discount of $1,095 and $1,281 at December 31, 2006 and 2005, respectively. Debt discount amortization recognized during 2006 and 2005 was $186 and $8, respectively. The notes mature in full on December 15, 2012 and may be prepaid prior thereto with a penalty. Interest is paid on a semi-annual basis in the amount of $10,369 on June 15 and December 15 of each year. The proceeds of the debt offering were used to refinance a portion of the Company’s existing debt and $125,000 was placed in escrow for the purpose of constructing a 110 million gallon per year ethanol plant near Charles City, Iowa. The indenture relating to the notes contains a number of restrictive covenants that limit the ability of the Parent and its subsidiaries to, among other things, incur additional indebtedness, pay dividends, make investments, and enter into

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

transactions with affiliates and other restrictions. The notes are collateralized by substantially all the assets of the Parent and certain of its subsidiaries, except for accounts receivable, inventory, commodities accounts and the cash proceeds therefrom and subject to various other exceptions. Certain registration rights were granted related to the notes and the notes were registered with the SEC in 2006. VAC, VFD, VM, VCC, VW, VH, VRL and VGC are all guarantors of the notes and each is a 100% wholly owned subsidiary of VEC.

The $44,267 restricted cash held in escrow as of December 31, 2006 consists of cash proceeds in one bank from the senior notes held for the construction of the VCC facility. The bank began releasing escrow funds upon the commencement of construction on the VCC facility in 2006.

In December 2005, the Company extinguished certain long-term debt with proceeds from the senior secured notes. The Company incurred prepayment penalties of $13,357 and expensed unamortized debt issuance costs and debt discount of $2,387, which are included as other interest expense, loss on extinguishment of debt, in the accompanying statement of income.


Note 8.	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 (Note 7). To induce the subordinated note holder (“SNH”) to enter into the note purchase agreement and to make extensions of credit hereunder, the Company granted warrants to acquire 1,180,000 shares of common stock 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 liability related to the warrant of $27,128 at the time of the IPO was reclassified to additional paid-in capital in 2006. During 2006, 2005 and 2004, the change in the computed value of the warrant included in interest expense in the accompanying statements of income was $19,670, $2,809 and $3,481, respectively.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Note 9. Income Tax Matters

Net deferred tax liabilities consist of the following components as of December 31, 2006 and 2005:


	2006			2005

Deferred tax assets:
Net operating loss carryforward	$	—		$	6,096
Derivative financial instruments		—			1,261
Organizational expenses		2,579			2,509
Compensation expense		6,196			446
Other		318			350

		9,093			10,662

Deferred tax liabilities:
Property and equipment		(34,061	)		(19,640	)
Prepaid expenses		(1,111	)		(898	)
Derivative financial instruments		(690	)		—
Other		—			(42	)

		(35,862	)		(20,580	)

Net deferred tax liabilities	$	(26,769	)	$	(9,918	)

The components giving rise to the net deferred tax liabilities described above have been included in the accompanying balance sheets as of December 31 as follows:


	2006			2005

Current assets	$	—		$	5,839
Current liabilities		(1,370	)		—
Noncurrent liabilities		(25,399	)		(15,757	)

	$	(26,769	)	$	(9,918	)

The provision for income taxes charged to operations for the years ended December 31, 2006, 2005 and 2004 consists of the following:


	2006		2005		2004

Current:
Federal	$	37,526	$	172	$	115
State		700		—		—

		38,226		172		115

Deferred:
Federal		14,383		410		10,127
State		1,741		—		—

		16,124		410		10,127

Net income tax expense	$	54,350	$	582	$	10,242

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

The income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to pretax income for the years ended December 31, 2006, 2005 and 2004, due to the following:


	2006			2005			2004

Computed “expected” federal tax expense	$	45,527		$	271		$	8,720
Increase (decrease) in income taxes resulting from:
Convertible put warrant		7,180			983			1,218
Stock-based compensation		1,883			167			74
State taxes, net of federal benefit		1,541			—			—
Tax exempt interest		(684	)		—			—
Domestic manufacturing deduction		(1,175	)		—			—
Credits		(131	)		—			—
Effect of lower tax rates		—			260			(260	)
Loss (income) from nontaxable subsidiaries, including the initial recognition of deferred taxes as of the dates of reorganization in 2005		—			(1,257	)		380
Other, net		209			158			110

	$	54,350		$	582		$	10,242


Note 10.	Tax Increment Financing

During the year ended December 31, 2003, the Company received a grant of $2,004 from the proceeds of tax increment financing bonds issued by Brookings County, South Dakota. Under South Dakota law, proceeds from tax increment financing are not a liability of the Company, but are an obligation of the taxing district issuing the bonds. The grant was provided to fund improvements to the property owned by the Company and the bonds will be repaid by Brookings County from the incremental increase in property taxes related to the improvement of the Company’s real property. The proceeds of the financing have been recorded as deferred revenue and are being amortized at approximately $96 per year into income, with such amortization amount based on the life of the related property and equipment. During 2006, 2005 and 2004, $96, $96 and $95, respectively, of amortization was included in income in the accompanying statements of income.


Note 11.	Risk Management

The Company’s activities expose it to a variety of market risks, including the effects of changes in commodity prices and interest rates. These financial exposures are monitored and managed by the Company as an integral part of its overall risk-management program. The Company’s risk-management program focuses on the unpredictability of financial and commodities markets and seeks to reduce the potentially adverse effects that the volatility of these markets may have on its operating results.

The manufacturing of the Company’s products requires substantial purchases of corn and natural gas. Price fluctuations in commodities cause firm commitments to purchase the commodities to develop unrealized appreciation or depreciation when compared with current commodity prices and actual cash outlays for the purchase of the commodities differ from anticipated cash outlays.

The Company seeks to mitigate its exposure to commodity price fluctuations by purchasing forward a portion of its corn requirements on a fixed price basis and by purchasing corn and natural gas futures

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

contracts. To mitigate ethanol price risk, the Company sells a portion of its production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract, such as unleaded gasoline on the NYMEX, and the Company may hedge a portion of the price risk associated with index contracts by selling exchange-traded unleaded gasoline contracts. The Company believes its strategy of managing exposure to commodity price fluctuations will reduce somewhat the volatility of its results, but will also reduce its ability to benefit from favorable changes in prices.

Exchange-traded futures contracts are valued at market price. Changes in market price are recorded in other comprehensive income, net of tax, until earnings are affected by the variability of cash flows for those highly effective contracts designated and that qualify as cash flow hedges. At December 31, 2006, the Company had hedged a portion of its exposure with forward and futures contracts through 2009. 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 the Company’s financial statements. The Company may elect to create a hedging relationship for forward purchase contracts by selling an exchange traded futures contract as an offsetting position. In this situation, the forward purchase contract may be designated to be valued at market price until delivery is made against the contract. The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether its commodity hedges are highly effective in offsetting changes in cash flows of the hedged item.

The Company uses futures contracts to fix the purchase price of anticipated volumes of commodities to be purchased and processed in a future month, including the Company’s anticipated natural gas requirements for its production facilities. The Company hedges its exposure to natural gas price changes for up to six months. Accumulated other comprehensive loss as of December 31, 2006 and 2005 was $962 and $2,310, respectively, net of tax, relating to derivative financial instruments. The gains and losses arising from cash flow hedges will be recognized in the statement of income within the next 12 months. Hedging gains (losses) included in the statements of income consist of the following for the years ended December 31, 2006, 2005 and 2004:


	2006			2005			2004

Undesignated	$	4,959		$	387		$	—
Designated cash flow hedges		(7,879	)		(5,063	)		6,053
Ineffectiveness on cash flow hedges		(943	)		(3,231	)		(918	)

Total amounts included in cost of goods sold	$	(3,863	)	$	(7,907	)	$	5,135

Designated cash flow hedges included in net sales	$	2,380		$	(3,862	)	$	(4,324	)

By using derivative financial instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the risk of failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk for the Company. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, it does not have repayment risk. The Company reduces the credit (or repayment) risk in derivative instruments by entering into transactions with high-quality counterparties. Derivative contracts entered into by the Company are governed by an International Swap Dealers Association Master Agreement.

Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices. The market risk associated with commodity-price contracts is managed by the establishment and monitoring of parameters that limit the types and degree of market risk that may be undertaken.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

The components of other comprehensive income (loss) on hedging activities for the years ended December 31 are as follows:


	2006			2005			2004

Unrealized holding (loss) arising during the year, net	$	(4,368	)	$	(12,341	)	$	(2,731	)
Less reclassification adjustment for net gains (losses) realized in net income		(6,442	)		(12,251	)		343

Net change in unrealized gain (loss) before income taxes		2,074			(90	)		(3,074	)
Income taxes benefit (expense)		(726	)		31			1,046

Other comprehensive income (loss)	$	1,348		$	(59	)	$	(2,028	)


Note 12.	Stock-Based Compensation and Equity-Based Awards

The Company has a Stock Incentive Plan (“Plan”), under which 4,791,811 common shares as of December 31, 2005, were 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. In 2006, the Company’s Board of Directors authorized, subject to shareholder approval, an additional 5,208,189 of common shares to be included in the Plan, for an aggregate of 10,000,000 awards authorized, which also includes a long-term incentive plan that was formed during 2006 and which provides for the grant of restricted stock awards and stock options to certain employees at a ratio of 25% restricted stock and 75% stock options of the total award. Such amounts vest 10% at the end of year one, 15% at the end of year two, 20% at the end of year three, 25% at the end of year four and 30% at the end of year five. As of December 31, 2006, there were 3,797,530 shares available to be awarded under the Plan. 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 $22,452, $1,142 and $715 for the years ended December 31, 2006, 2005 and 2004, respectively, of which $20,571, $1,142 and $715, respectively, was charged to selling, general and administrative expenses and the remainder was charged to cost of goods sold. As a result of the Company’s IPO during 2006, options and warrants covering 3,516,338 shares and restricted stock covering 99,211 shares immediately vested due to accelerated vesting provisions within those instruments. In addition, performance-based awards for 620,041 shares for which a grant date had not occurred prior to the IPO immediately were “granted” for accounting purposes, vested and resulted in the recognition of stock-based compensation expense. Stock-based compensation expense was also recognized for a stock bonus to non-management employees that management awarded concurrently with the offering. Agreements for awards to two employees were modified during 2006 to shorten the vesting period from five years to three years for the related awards. The total incremental compensation cost related to such modifications was not significant. The total income tax benefit recognized in the consolidated statement of income for grants under the Plan was $6,155, $182 and $114 for the years ended December 31, 2006, 2005 and 2004, respectively. No compensation expense was capitalized during the three years ended December 31, 2006.

Net cash received from the exercise of options and awards under the Plan was $368, $0 and $0 for the years ended December 31, 2006, 2005 and 2004, respectively. The Company recognized an excess tax benefit of $1,320 in connection with related exercises in 2006 and no significant tax benefits were recognized in 2004 and 2005.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

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 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 Statement No. 123R. Prior periods were not restated to reflect the impact of adopting the new standard.

As a result of adopting 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 year ended December 31, 2006 were higher (lower) by $3,679, $2,868, ($1,320), $1,320, ($0.04) and ($0.04), respectively, than if the Company had continued to account for stock-based compensation under APB Opinion No. 25 for awards under the Plan.

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 ten year contractual terms. These awards can only be exercised if the holder of the award is still employed or in the service of the Company at the time of exercise and for a specified period after termination of employment. Certain Service Awards granted under the Plan provide for accelerated vesting if there is a change in control as defined in the Plan.

The fair value of each Service Award is estimated on the date of grant using the Black-Scholes single option pricing model with the weighted average assumptions described below for the periods presented. Expected volatility was based on the stock volatility for a comparable publicly traded company for the period prior to the Company’s IPO and is based on the Company’s stock activity from the IPO date to December 31, 2006, considered collectively for the expected term of the award. The Company uses historical activity to estimate option exercise, forfeiture and employee termination assumptions within the valuation model. The expected term of options granted is generally derived using the mid-point between the date options become exercisable (generally five years) and the date at which they expire (generally ten years). The risk-free interest rate for periods within the contractual life of the Service Award is based on the U.S. Treasury yield curve in effect at the time of grant.

Years Ended December 31,

2006

2005

2004

Expected volatility

58%

30%

Expected dividend yield

None

Expected term

8 - 10 years

5 - 10 years

Risk-free interest rate

4.5% - 5.1%

4.4%

3.7% - 3.8%

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

The following table lists Service Award activity under the Plan for the year ended December 31, 2006:


				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Service Awards	Shares			Price		Term		Value

Outstanding at January 1, 2006		2,869,651		$	1.99
Granted		1,556,642			21.55
Forfeited		(87,362	)		11.56
Exercised		(305,726	)		1.92

Outstanding at December 31, 2006		4,033,205		$	9.33		8.2	$	46,597

Vested or expected to vest as of December 31, 2006		3,988,222		$	9.20		8.1	$	46,538

Exercisable at December 31, 2006		2,533,784		$	2.16		7.5	$	44,629

The Company applied a forfeiture rate of 3% when calculating the amount of options expected to vest as of December 31, 2006. This rate is based on historical activity and will be revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. The weighted average grant date fair value of options granted during the years ended December 31, 2006, 2005 and 2004 was $14.35, $3.38 and $0.49 per share, respectively. The total intrinsic value of options exercised during the years ended December 2006, 2005 and 2004 was $4,854, $0 and $0, respectively.

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

The following table shows the status of the Company’s nonvested Restricted Stock as of December 31, 2006 and changes during the year ended December 31, 2006:


				Weighted
				Average
				Grant Date
Restricted Stock	Shares			Fair Value

Nonvested at January 1, 2006		108,328		$	0.99
Granted		340,896			22.69
Vested		(108,328	)		0.99

Nonvested at December, 2006		340,896		$	22.69

As of December 31, 2006, there was $24,299 of total unrecognized compensation expense related to nonvested Service Awards and Restricted Stock granted under the Plan. This expense is expected to be recognized over a weighted average period of 2.5 years. The total fair value of service-based shares vested during the years ended December 31, 2006, 2005 and 2004 was $2,928, $386 and $10, respectively. The grant date fair value of nonvested shares was determined using the value of the Company’s common stock sold on or 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

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

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 ten year contractual terms. These awards can only be exercised if the holder of the award is still employed or in the service of the Company at the time of exercise and for a specified period after termination of employment. Certain 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%. If such goals are not met, or are met at a rate less than 97%, 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, estimated forfeitures 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 years ended December 31, 2006, 2005 and 2004 was eight, eight - ten, and five - eight years, respectively.

The following table lists Performance Award activity under the Plan for the year ended December 31, 2006:


						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Performance Awards	Shares			Price		Term		Value

Outstanding at January 1, 2006		453,251		$	1.02
Granted		889,409			1.95
Forfeited		(667	)		5.16
Exercised		(83,696	)		1.55

Outstanding at December 31, 2006		1,258,297		$	1.64		7.3	$	22,791

Vested or expected to vest as of December 31, 2006		1,258,297		$	1.64		7.3	$	22,791

Exercisable at December 31, 2006		1,258,297		$	1.64		7.3	$	22,791

The weighted average grant date fair value of Performance Awards granted was $16.61, $3.39 and $0.44 per share for the years ended December 31, 2006, 2005 and 2004, respectively. The aggregate intrinsic value of Performance Awards exercised during the years ended December 31, 2006, 2005 and 2004 was $1,347, $0 and $0, respectively. The total fair value of Performance Awards vested during the years ended December 31, 2006, 2005 and 2004 was $14,770, $997 and $665, respectively. As of December 31, 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.

Other Share-Based Awards

Service-Based Awards: In connection with its service agreement with a third party financial advisor (“Advisor”), the Company granted a warrant to the Advisor to purchase 96,376 shares of common stock. The warrant was fully vested at December 27, 2002. The warrant has an exercise price of $0.52 per share and expires February 25, 2008. The warrant is not transferable, except to officers of the Advisor. The aggregate intrinsic value of this warrant as of December 31, 2006 was $1,853. Through December 31,

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

2006, no shares have been issued under the warrant and no expense had 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 December 31, 2006, warrants for 455,733 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. As of December 31, 2006 30,000 shares have been issued under the warrants. For the years ended December 31, 2006, 2005 and 2004, compensation expense of $20, $0 and $0 was recognized by the Company in connection with these warrants. As of December 31, 2006, there was $9 of unrecognized compensation expense related to these warrants and the aggregate intrinsic value of the outstanding warrants was $10,543.

Performance- and Market-Based Awards: In 2002, the Company granted “claw back” warrants to purchase 1,475,681 shares of common stock to the Company’s initial common shareholders, who were also employees of the Company. The warrants were fully exercisable as of December 31, 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 expense in the year ended December 31, 2006, when the performance conditions were met upon the completion of the IPO. The aggregate intrinsic value of these warrants as of December 31, 2006 was $28,377.

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


Note 13.	Employee Benefit Plan

The Company has a 401(k) plan. Employees who are at least 18 years of age are eligible to participate in the plan. Eligible employees may make elective deferral contributions to the plan. The Company’s matching contribution is 100% of the employee elective deferrals, not to exceed 3% of the employee’s eligible wages. During 2006, 2005 and 2004, the Company contributed approximately $289, $136 and $96, respectively, to the plan.


Note 14.	Commitments and Contingencies

The Company has entered into various contracts and agreements.

The Company leases railroad cars with terms ranging from 36 to 120 months following the receipt of the railroad cars. The total lease expense included in the statements of income for the years ended December 31, 2006, 2005 and 2004 relating to these leases is $3,351, $2,476 and $1,052, respectively. Future minimum lease payments on the railroad cars are as follows:


Years Ending December 31,	Amount

2007	$	10,241
2008		24,228
2009		25,404
2010		25,404
2011		25,404
Thereafter		89,106

Total	$	199,787

The Company accrues an estimate for repair expenses on railroad cars for damages in excess of normal wear and tear as provided by the lease agreement. As of December 31, 2006 and 2005, $448 and

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

$142, respectively, was included in accrued expenses in the accompanying balance sheets and $306, $142 and $0 was included in the accompanying statements of income during the years ended December 31, 2006, 2005 and 2004, respectively.

The Company has entered into agreements for the purchase of corn, electricity, natural gas, water and railroad transportation as follows:

Corn — Corn purchase obligations include corn commitments to purchase approximately 32.6 million bushels of corn under forward contracts, in which the related commodity had not been delivered, and a multi-year corn purchase agreement. To quantify the purchase obligations under certain of the Company’s corn contracts and its multi-year corn purchase agreement, the Company has used its December 31, 2006 published bid prices for corn.

Natural Gas — The agreements provide the Company with fixed rates for natural gas through various dates through 2019 from one vendor at each plant. The rates are based upon transportation rates or demand charges for the various agreements plus minimum monthly administrative charges. The agreements require varying annual minimum purchases of up to 3,000,000 MMBtu of natural gas at each plant.

Electricity — The agreements provide the Company with a fixed rate for electric service through various dates through 2012 from one vendor at each plant. The agreements require varying minimum purchases of up to 10,000 kilowatts of electricity each month plus a monthly facilities charge at each plant.

Water — The agreements provide the Company with fixed rates for water through various dates to 2009 from one vendor at each plant. The agreements require varying minimum purchases of up to 350 million gallons of water per year through 2019 at each plant.

Railroad transportation — The agreements provide the Company with a transportation route for outbound ethanol and distillers grain shipments and inbound corn shipments. These agreements are with one or two vendors per plant. The rates per the agreements are fixed, subject to semi-annual adjustment based on a national index of rail costs. These contracts do not have stated minimums and terminate on various dates through 2018, or upon notice.

Expenses related to the agreements for the purchase of natural gas, electricity, water and railroad transportation totaled $72,700, $48,107 and $24,392 for the years ended December 31, 2006, 2005 and 2004, respectively.

Minimum purchase amounts under these contracts are as follows:


			Natural Gas,
			Electricity,
Years Ending December 31,	Corn		Water

2007	$	115,978	$	4,783
2008		6,774		6,336
2009		612		5,993
2010		—		5,908
2011		—		5,388
Thereafter		—		29,886

Total	$	123,364	$	58,294

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

The Company has agreements with Aventine Renewable Energy, Inc. (“Aventine”) for the marketing, billing, receipt of payment and other administrative services for substantially all ethanol produced by the Company. The Company pays fees that vary based on the number of gallons sold. In February 2006, formal notice was provided to terminate the Company’s agreements with Aventine on March 31, 2007. Sales to Aventine are recorded net of fees and such sales were $485,678, $203,550 and $155,439 for the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006 and 2005, $25,496 and $12,272, respectively, was due from Aventine and is included in receivables in the accompanying balance sheets. Management does not expect any significant adverse affects from the termination of these marketing agreements. A marketing department has been established to facilitate marketing ethanol directly to oil companies.

In March 2006, the Company entered into agreements for construction and engineering of the VCC plant. 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. In the event that the sum of the cost of the work and the flat fee under the agreement exceed the contracted cash amount for construction of the VCC plant, the Company has the option to pay the contractor any excess by either a payment of cash or by tendering to the contractor common stock of the Company with a value equal to the amount owed (valued at the time of issuance).

In September 2006, the Company entered into agreements for the construction and engineering of 110 million gallons per year facilities for VW and VH, as well as a third unspecified location that will begin construction in 2007. The Company began construction of the VW and VH facilities during the fourth quarter of 2006. The Company anticipates that the cash on hand will be adequate to pay amounts due for the construction of two of the plants and that the third plant will be funded from future cash flows.

In 2006, an agreement was entered into for the storage of ethanol effective April 1, 2007 with a monthly commitment of approximately $368 through March 2008.

The Company has an agreement with American Milling, LLP, a grain processing and transportation company, for the acquisition from time to time of rights to purchase or lease real property sites suitable for future construction and operation of 110 million gallons per year nameplate ethanol production facilities. American Milling has identified a number of potential sites and has acquired or is in the process of acquiring rights either to purchase or lease them. At the time it designates a site, American Milling will provide documentation about the site and the related property rights to assist the Company in deciding whether to accept it. Upon any acceptance, American Milling may elect to receive cash or shares of the Company’s common stock for the property rights. As of December 31, 2006, there was no liability to American Milling for accepted sites. On March 1, 2007, the Company agreed to accept a site located near Reynolds, Indiana. As consideration for the site, the Company is obligated to issue 300,000 shares of its common stock, of which 150,000 shares were issued to American Milling on March 15, 2007. The remaining 150,000 shares will be issued upon receipt of the required construction permits for the proposed ethanol facility, but no later than March 15, 2008.

The Company’s operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdiction in which it operates. These laws require the Company to investigate and remediate the effects of the release or disposal of material at its locations. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, occupational health, and the production, handling, storage and use of hazardous materials to prevent environmental or other damage, and to limit the financial liability which could result from such events. Environmental liabilities are recorded when the Company’s liability is probable and the costs can be reasonably estimated. No such liabilities were recorded at December 31, 2006.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)


Note 15.	Insurance Proceeds

Other income for the year ended December 31, 2006 includes $2,475 of business interruption insurance proceeds with respect to a malfunction of a key piece of equipment in 2005 at VFD’s facility. In addition, insurance proceeds of $500 were recognized in the year ended December 31, 2005 which were included primarily in cost of goods sold as an offset to repair expenses incurred.


Note 16.	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 and VFD and ethanol plants under construction or in development of VCC, VW, VH, VRL and VGC. The Company’s remaining operations, including activities by the Parent corporation, are aggregated and classified as “All Other”. Financial performance is evaluated based on earnings before interest, taxes, depreciation and amortization (“EBITDA”), 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 distillers grains and E85.


	2006
	Ethanol		All
	Production		Other			Totals

Revenue from external customers	$	546,445	$	7,544		$	553,989
Intersegment revenue		4,595		—			4,595
Interest revenue		2		13,616			13,618
Intersegment interest revenue		2,171		13,878			16,049
Interest expense*		—		37,871			37,871
Intersegment interest expense		10,039		6,010			16,049
Depreciation		9,600		67			9,667
Segment profit (loss) — EBITDA		193,026		(15,411	)		177,615
Segment assets		404,716		389,781			794,497
Intersegment assets		5,268		327,073			332,341
Capital expenditures for segment assets		39,343		3,630			42,973


	2005
	Ethanol		All
	Production		Other		Totals

Revenue from external customers	$	235,435	$	5	$	235,440
Interest revenue		238		210		448
Intersegment interest revenue		10		796		806
Interest expense*		21,266		2,087		23,353
Intersegment interest expense		796		10		806
Depreciation		5,675		17		5,692
Segment profit — EBITDA		29,167		713		29,880
Segment assets		233,071		172,058		405,129
Intersegment assets		15,214		208,087		223,301
Capital expenditures for segment assets		86,052		1,043		87,095

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

2004

Ethanol
All

Production Other Totals

Revenue from external customers
$ 186,029 $ — $ 186,029

Interest revenue
181 1 182

Interest expense*
8,892 — 8,892

Depreciation
3,926 — 3,926

Segment profit — EBITDA
37,786 45 37,831

Segment assets
150,010 318 150,328

Intersegment assets
4,925 572 5,497

Capital expenditures for segment assets
25,215 — 25,215

The following schedule is presented to reconcile EBITDA to income before income taxes and minority interest:


	2006			2005			2004

Segment profit — EBITDA	$	177,615		$	29,880		$	37,831
Depreciation		(9,667	)		(5,692	)		(3,926	)
Interest expense*		(37,871	)		(23,353	)		(8,892	)
Minority interest in net loss of subsidiary		—			(61	)		(100	)

Income before income taxes and minority interest	$	130,077		$	774		$	24,913


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

The components of revenues are as follows for the years ended December 31:


	2006		2005		2004

Revenues from external customers:
Ethanol	$	488,049	$	199,677	$	151,103
Distillers grains		58,332		34,966		34,866
E85		7,608		755		53
Other		—		42		7

	$	553,989	$	235,440	$	186,029

Revenue from one customer of the Ethanol Production segment was $485,678, $203,550 and $155,439 during the years ended December 31, 2006, 2005 and 2004, respectively. See Note 14.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)


Note 17.	Quarterly Financial Data (Unaudited)

The following table presents summarized quarterly financial data for the year ended December 31, 2006:


Year Ended December 31, 2006	1st Quarter		2nd Quarter			3rd Quarter			4th Quarter

Total revenues	$	110,704	$	153,066		$	147,549		$	146,498
Gross profit		29,346		62,936			59,595			40,801
Net income		2,735		19,553	(a)		32,000	(b)		21,439
Basic EPS		0.04		0.30			0.43			0.29
Diluted EPS		0.04		0.29			0.40			0.27


(a)		Includes $18,147 of stock-based compensation related to accelerated vesting and other stock-based compensation issued in connection with the IPO (Note 12)

(b)		Includes business interruption insurance proceeds of $2,475 (Note 15)


Year Ended December 31, 2005	1st Quarter		2nd Quarter			3rd Quarter			4th Quarter

Total revenues	$	44,852	$	34,410		$	56,990		$	100,107
Gross profit (loss)		6,171		(1,516	)(a)		6,666			24,215
Net income (loss)		1,686		(3,910	)		(205	)		2,682	(b)
Basic EPS		0.04		(0.09	)		—			0.05
Diluted EPS		0.04		(0.09	)		—			0.05


(a)		Includes loss on disposal of equipment of $2,640 (Note 5)

(b)		Includes loss on extinguishment of debt of $15,744 (Note 7)

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

Note 18. Supplemental Cash Flow Information


	2006			2005			2004

Supplemental Disclosures of Cash Flow Information
Cash payments for interest, of which $3,622, $3,534 and $11 was capitalized in 2006, 2005 and 2004, respectively	$	20,392		$	8,721		$	4,772
Cash payments for (receipts of) income taxes, net		49,252			(50	)		200
Supplemental Schedule of Noncash Investing and Financing Activities
Property and equipment acquired through accounts payable	$	11, 736		$	2,547		$	8,584
Construction loan paid in full through issuance of term loans		—			—			60,000
Change in unrealized gain/loss on interest rate swap		—			94			(430	)
Tax effect on unrealized gain/loss on interest rate swap		—			(32	)		145
Change in unrealized gain/loss on derivative financial instruments		(2,074	)		(4	)		3,504
Tax effect on unrealized gain/loss on derivative financial instruments		726			1			(1,191	)
Debt issuance costs included in accounts payable		—			981			470
Minority interest in subsidiary acquired through issuance of common stock		—			2,839			—
Goodwill acquired through issuance of common stock for minority interest in subsidiary		—			6,129			—
Conversion of note payable to common stock		—			—			1,000
Deferred financing costs reclassified against proceeds from issuance of common stock		—			—			69
Property and equipment acquired with restricted cash		80,483			250			—
Extinguishment and reclassification of convertible put warrant to additional paid-in capital		27,128			—			—


Note 19.	Guarantors/Non-guarantors 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, VM, VH, VCC, VRL, VGC and VW are combined as guarantors, each of which is a 100% wholly owned subsidiary of VEC. Prior to 2005, VEC had no independent assets or operations and the non-guarantor subsidiaries were minor. Accordingly, consolidating financial information is not presented for periods prior to 2005.

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2006

ASSETS


	Issuer (VEC)		Guarantors		Non-Guarantors			Eliminations			Consolidated

Current Assets
Cash and cash equivalents	$	324,146	$	—	$	2		$	(6,099	)	$	318,049
Receivables		4,326		64,503		(60	)		(6,220	)		62,549
Inventories		—		39,103		—			(54	)		39,049
Prepaid expenses		450		3,737		—			—			4,187
Derivative financial instruments		—		12,382		—			—			12,382

Total current assets		328,922		119,725		(58	)		(12,373	)		436,216

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

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

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

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


LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY (DEFICIT)


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

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

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

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

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

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

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

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

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the Year Ended December 31, 2006


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Total revenues	$	—		$	562,412		$	—		$	(4,595	)	$	557,817
Cost of goods sold		1,014			368,653			13			(4,541	)		365,139

Gross profit		(1,014	)		193,759			(13	)		(54	)		192,678
Selling, general and administrative expenses		23,999			16,648			413			—			41,060

Operating income (loss)		(25,013	)		177,111			(426	)		(54	)		151,618

Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(43,663	)		(10,107	)		(150	)		16,049			(37,871	)
Interest income		27,492			2,175			—			(16,049	)		13,618
Equity in earnings of subsidiaries		110,788			—			—			(110,788	)		—
Other income		187			2,525			—			—			2,712

		94,804			(5,407	)		(150	)		(110,788	)		(21,541	)

Income (loss) before income taxes		69,791			171,704			(576	)		(110,842	)		130,077
Income tax expense (benefit)		(5,936	)		60,504			(218	)		—			54,350

Income (loss) before minority interest		75,727			111,200			(358	)		(110,842	)		75,727
Minority interest in net loss of subsidiary		—			—			—			—			—

Net income (loss)	$	75,727		$	111,200		$	(358	)	$	(110,842	)	$	75,727

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2006


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	(8,912	)	$	104,064		$	2,112		$	—		$	97,264

Cash Flows from Investing Activities
Proceeds from sale of equipment		—			—			838			—			838
Purchases of property and equipment with restricted cash held in escrow		80,483			(80,483	)		—			—			—
Disbursements on notes receivable		(13,050	)		—			—			13,050			—
Purchases of property and equipment		(686	)		(39,339	)		(2,948	)		—			(42,973	)
Payments of deposits		(280	)		(200	)		—			—			(480	)

Net cash provided by (used in) investing activities		66,467			(120,022	)		(2,110	)		13,050			(42,615	)

Cash Flows from Financing Activities
Change in outstanding checks in excess of bank balance		—			2,908			—			(2,908	)		—
Net borrowings on long-term debt		—			13,050			—			(13,050	)		—
Net proceeds from issuance of common stock		233,170			—			—			—			233,170
Net proceeds from the issuance of stock options and warrants		368			—			—			—			368
Excess tax benefits from share-based payment arrangements		1,320			—			—			—			1,320
Debt issuance costs paid		(1,172	)		—			—			—			(1,172	)

Net cash provided by financing activities		233,686			15,958			—			(15,958	)		233,686

Net increase in cash and cash equivalents		291,241			—			2			(2,908	)		288,335
Cash and cash equivalents, beginning of period		32,905			—			—			(3,191	)		29,714

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

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2005

ASSETS


	Issuer (VEC)		Guarantors		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

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


December 31, 2005 LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY (DEFICIT)


	Issuer (VEC)			Guarantors			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 Member’s Equity (Deficit)
Preferred stock		—			—			—			—			—
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
Member’s 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 CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the Year Ended December 31, 2005


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Total revenues	$	—		$	236,359		$	—		$	—		$	236,359
Cost of goods sold		—			200,823			—			—			200,823

Gross profit		—			35,536			—			—			35,536
Selling, general and administrative expenses		372			11,153			349			—			11,874

Operating income (loss)		(372	)		24,383			(349	)		—			23,662

Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(2,069	)		(6,319	)		(27	)		806			(7,609	)
Other interest expense, loss on extinguishment of debt		—			(15,744	)		—			—			(15,744	)
Interest income		1,004			248			2			(806	)		448
Equity in earnings of subsidiaries		1,345			—			—			(1,345	)		—
Other income		—			17			—			—			17

		280			(21,798	)		(25	)		(1,345	)		(22,888	)

Income (loss) before income taxes and minority interest		(92	)		2,585			(374	)		(1,345	)		774
Income tax expense (benefit)		(345	)		1,062			(135	)		—			582

Income (loss) before minority interest		253			1,523			(239	)		(1,345	)		192
Minority interest in net loss of subsidiary		—			—			—			61			61

Net income (loss)	$	253		$	1,523		$	(239	)	$	(1,284	)	$	253

VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2005


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	3,220		$	(4,936	)	$	(799	)	$	—		$	(2,515	)

Cash Flows from Investing Activities
Investment in restricted cash		(125,000	)		—			—			—			(125,000	)
Advances on notes receivable		(147,536	)		(15,214	)		—			162,750			—
Capital contribution to subsidiary		(5,920	)		—			—			5,920			—
Proceeds from sale of equipment		—			46			—			—			46
Purchases of property and equipment		(10	)		(86,035	)		(1,050	)		—			(87,095	)

Net cash (used in) investing activities		(278,466	)		(101,203	)		(1,050	)		168,670			(212,049	)

Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			3,191			—			(3,191	)		—
Proceeds from long-term debt		223,520			146,388			1,553			(162,750	)		208,711
Principal payments on long-term debt		—			(58,890	)		—			—			(58,890	)
Net proceeds from issuance of common stock		90,138			—			—			—			90,138
Capital contribution from parent		—			5,920			—			(5,920	)		—
Debt issuance costs paid		(5,507	)		(470	)		—			—			(5,977	)

Net cash provided by financing activities		308,151			96,139			1,553			(171,861	)		233,982

Net increase (decrease) in cash and cash equivalents		32,905			(10,000	)		(296	)		(3,191	)		19,418
Cash and cash equivalents, beginning of period		—			10,000			296			—			10,296

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


ITEM 9.	*CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE*

None


ITEM 9A.	*CONTROLS AND PROCEDURES*

Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.

As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon such evaluation as of December 31, 2006, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective because of the material weaknesses discussed below. To address those weaknesses, the Company preformed additional analyses and other post-closing procedures to ensure that our consolidated financial statements are prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

The aforementioned evaluation identified the following weaknesses:

1. Our post-closing processes discovered certain issues with respect to the accounting for derivative financial instruments and income taxes among certain other items, resulting in significant adjustments to our financial statements.

2. We also concluded that there were deficiencies in our financial closing process, the monitoring of accounting recognition matters and the calculation of certain estimates.

As noted above, the issues that resulted from these weaknesses were properly addressed before the completion of our consolidated financial statements. In addition, our management is working with our Audit Committee to identify and implement corrective actions where required to improve our internal controls, including the enhancement of our systems and procedures to assure that the weaknesses noted above are corrected.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fiscal quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except as described above.


ITEM 9B.	*OTHER INFORMATION*

None

PART III


ITEM 10.	*DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT*

Information with respect to directors of the Company is incorporated herein by reference to the section entitled “Election of Directors” in our proxy statement for our 2007 Annual Meeting of Shareholders (the “2007 Proxy Statement”), to be filed no later than 120 days after the end of the fiscal year ended December 31, 2006. Information with respect to our executive officers is set forth under Item 4A in Part I of this report.

Information with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference to our 2007 Proxy Statement.

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. The Company has posted this Code of Business Conduct and Ethics on the VeraSun Energy Corporation website at www.verasun.com.


ITEM 11.	*EXECUTIVE COMPENSATION*

Information regarding Executive Compensation, our Compensation Committee and the Compensation Committee Report are incorporated herein by reference to our 2007 Proxy Statement.


ITEM 12.	*SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS*

The section of our 2007 Proxy Statement entitled “Security Ownership of Certain Beneficial Owners and Management” is incorporated herein by reference. Information regarding our equity compensation plan is included in Item 5 of this Annual Report on Form 10-K.


ITEM 13.	*CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE*

Information with respect to certain relationships and related transactions and director independence is incorporated herein by reference to our 2007 Proxy Statement.


ITEM 14.	*PRINCIPAL ACCOUNTING FEES AND SERVICES*

Information with respect to principal accounting fees and services is incorporated herein by reference to our 2007 Proxy Statement.

EXHIBIT INDEX


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	First Supplemental Indenture, dated May 4, 2006, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Marketing, LLC and VeraSun Welcome, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee.*
4	.3	Second Supplemental Indenture, dated August 21, 2006, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, and VeraSun Welcome, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee. (Incorporated by reference to Exhibit 10.1 to VeraSun Energy Corporation’s quarterly report on Form 10-Q for the period ended September 30, 2006).
4	.4	Third Supplemental Indenture, dated February 9, 2007, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, VeraSun Welcome, LLC, VeraSun Granite City, LLC, and VeraSun Reynolds, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee.
4	.5	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.*
10	.1	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 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) (Incorporated by reference to Exhibit 10.1 to VeraSun Energy Corporation’s Quarterly Report on Form 10-Q for the period ended June 30, 2006).
10	.3	Ethanol Marketing Agreement, dated February 22, 2005, between Aventine Renewable Energy, Inc. and VeraSun Fort Dodge, LLC.(CTR)*
10	.4	Amendment, effective June 18, 2006, to Ethanol Marketing Agreement, dated February 22, 2005, between Aventine Renewable Energy, Inc. and VeraSun Fort Dodge, LLC. (CTR). (Incorporated by reference to Exhibit 10.1 to VeraSun Energy Corporation’s Quarterly Report on Form 10-Q for the period ended June 30, 2006).
10	.5	VeraSun Energy Corporation Stock Incentive Plan, as amended.*+
10	.6	Form of Incentive Stock Option Agreement, as amended. (Incorporated by reference to Exhibit 99.1 to VeraSun Energy Corporation’s current report on Form 8-K dated September 15, 2006).+
10	.7	Form of Non-Statutory Stock Option Agreement, as amended. (Incorporated by reference to Exhibit 99.2 to VeraSun Energy Corporation’s Current Report on Form 8-K dated September 15, 2006).+
10	.8	Form of Restricted Stock Agreement, as amended. (Incorporated by reference to Exhibit 99.3 to VeraSun Energy Corporation’s Current Report on Form 8-K dated September 15, 2006).+
10	.9	Site Acquisition Agreement, dated May 22, 2006, between VeraSun Energy Corporation and American Milling, LP. (CTR)*
10	.10	Stock Transfer Restriction Agreement and Amendments to Site Acquisition Agreement, dated June 14, 2006, among the Company, American Milling, LP and the other parties named therein. (Incorporated by reference to Exhibit 10.4 to VeraSun Energy Corporation’s Current Report on Form 8-K dated June 14, 2006).
12	.1	Computation of Ratio of Earnings to Fixed Charges.
21	.1	Subsidiaries of VeraSun Energy Corporation.
23	.1	Consent of Independent Registered Public Accounting Firm.

POWER OF ATTORNEY

KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints, jointly and severally, Donald L. Endres and Danny C. Herron, and each of them, attorneys-in-fact for the undersigned, each with the power of substitution, for the undersigned in any and all capacities to sign any and all amendments to this Annual Report on Form 10-K for the year ended December 31, 2006, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated as of March 28, 2007.


Signature				Title

/s/ Donald L. Endres Donald L. Endres				Chief Executive Officer, President and Director (Principal Executive Officer)

/s/ Danny C. Herron Danny C. Herron				Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

/s/ Mark L. First Mark L. First				Director

/s/ D. Duane Gilliam D. Duane Gilliam				Director

/s/ T. Jack Huggins III T. Jack Huggins III				Director

/s/ Bruce A. Jamerson Bruce A. Jamerson				Director

/s/ Steven T. Kirby Steven T. Kirby				Director

/s/ Paul A. Schock Paul A. Schock				Director

POWER OF ATTORNEY

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the subsidiary registrants and in the capacities indicated as of March 28, 2007.


Signature				Title

/s/ Donald L. Endres Donald L. Endres				Chief Executive Officer and President of the subsidiary registrants and Director of VeraSun Aurora Corporation (Principal Executive Officer)

/s/ Danny C. Herron Danny C. Herron				Senior Vice President and Chief Financial Officer of the subsidiary registrants (Principal Financial Officer and Principal Accounting Officer)

/s/ John M. Schweitzer John M. Schweitzer				Director of VeraSun Aurora Corporation


			Page

PART I				1
	ITEM 1.	BUSINESS		1
	ITEM 1A.	RISK FACTORS		7
	ITEM 1B.	UNRESOLVED STAFF COMMENTS		18
	ITEM 2.	PROPERTIES		19
	ITEM 3.	LEGAL PROCEEDINGS		19
	ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		19
	ITEM 4A.	EXECUTIVE OFFICERS		20

PART II				22
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		22
	ITEM 6.	SELECTED FINANCIAL DATA		25
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		27
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		38
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		40
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		76
	ITEM 9A.	CONTROLS AND PROCEDURES		76
	ITEM 9B.	OTHER INFORMATION		76
PART III				77
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		77
	ITEM 11.	EXECUTIVE COMPENSATION		77
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		77
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		77
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		77
PART IV				78
	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		78
Signatures				83
Third Supplemental Indenture
Computation of Earnings to Fixed Charges
Subsidiaries
Consent of Independent Registered Public Accounting Firm
302 Certification of Chief Executive Officer
302 Certification of Chief Financial Officer
906 Certification of Chief Executive Officer
906 Certification of Chief Financial Officer


ITEM 8.	*FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA*


	Page

Report of Independent Registered Public Accounting Firm		41
Consolidated balance sheets at December 31, 2006 and 2005		42
Consolidated statements of income for each of the three years in the period ended December 31, 2006		43
Consolidated statements of shareholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2006		44
Consolidated statements of cash flows for each of the three years in the period ended December 31, 2006		45
Notes to the consolidated financial statements		46


	Balance at
	Beginning		Additions-charged				Balance at
	of Year		to expense		Deductions(1)		End of Year
	(in thousands)

Allowance for doubtful accounts
2004	$	—	$	5	$	—	$	5
2005		5		5		—		10
2006		10		64		9		65


	(b)	See Exhibit Index beginning on page 81 for a description of the documents that are filed as Exhibits to this Annual Report on Form 10-K or incorporated herein by reference.


24	.1	Powers of Attorney (included on signature page).
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).
+		Indicates a management contract or compensatory plan or arrangement.


VERASUN ENERGY CORPORATION, as Issuer
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer



By:	/s/ Bruce A. Jamerson
	Name:	Bruce A. Jamerson
	Title:	President


VERASUN AURORA CORPORATION, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN FORT DODGE, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN CHARLES CITY, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN MARKETING, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN WELCOME, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN HARTLEY, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN GRANITE CITY, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


VERASUN REYNOLDS, LLC, as Guarantor
By:	/s/ Donald L. Endres
	Name:	Donald L. Endres
	Title:	Chief Executive Officer


WELLS FARGO BANK, N.A., as Trustee
By:	/s/ Timothy P. Mowdy
	Name:	Timothy P. Mowdy
	Title:	Vice President


(1)		For the purpose of determining the ratio of earnings to fixed charges, earnings are defined as pretax income from continuing operations before adjustment for minority interest in consolidated subsidiary plus fixed charges and amortization of capitalized interest, less capitalized interest. Fixed charges consist of interest expense, which includes amortized debt issuance costs and capitalized interest.

(2)		The additional earnings needed to cover fixed charges in 2005 and 2003 were $2.6 million and $558,000, respectively.

*		Our earnings were inadequate to cover fixed charges for the year ended December 31, 2002. Earnings were $1.3 million less than fixed charges.

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

	b)		[Reserved]

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

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

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

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