10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

 

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

For the fiscal year ended December 31, 2007

or

 

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

For the transition period from              to             

Commission file number: 1-32913

 

 

VERASUN ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

South Dakota   20-3430241

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

100 22nd Avenue

Brookings, South Dakota

  57006
(Address of principal executive offices)   (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  ¨    No  x

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  ¨    No  x

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

Indicate by check mark 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.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨    Accelerated filer  x    Non-accelerated filer  ¨    Smaller reporting company  ¨

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

The aggregate market value of voting and non-voting stock held by non-affiliates of the Registrant as of June 30, 2007 was $673,446,743. 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 February 29, 2008

Common Stock, $0.01 par value per share   93,098,390 shares

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s definitive Proxy Statement for its 2008 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page

PART I

  

ITEM 1.

  

BUSINESS

   3

ITEM 1A.

  

RISK FACTORS

   11

ITEM 1B.

  

UNRESOLVED STAFF COMMENTS

   30

ITEM 2.

  

PROPERTIES

   30

ITEM 3.

  

LEGAL PROCEEDINGS

   30

ITEM 4.

  

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   30

PART II

  

ITEM 5.

  

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

   31

ITEM 6.

  

SELECTED FINANCIAL DATA

   33

ITEM 7.

  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   36

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   50

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   52

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   97

ITEM 9A.

  

CONTROLS AND PROCEDURES

   97

ITEM 9B.

  

OTHER INFORMATION

   99

PART III

  

ITEM 10.

  

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

   99

ITEM 11.

  

EXECUTIVE COMPENSATION

   99

ITEM 12.

  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

   99

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

   99

ITEM 14.

  

PRINCIPAL ACCOUNTANT FEES AND SERVICES

   99

PART IV

  

ITEM 15.

  

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   100

Signatures

   105

 

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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 :

 

Company

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

   333-13342-05    Delaware    20-5914827

VeraSun Welcome, LLC

      Delaware    20-4115888

VeraSun Litchfield, LLC

      Delaware    20-8621370

VeraSun Biodiesel, LLC

      Delaware    20-3790860

VeraSun Tilton, LLC

      Delaware    26-1539139

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. Except as specifically indicated below, all references to “VeraSun,” “we,” “our” and “us” refer to VeraSun Energy Corporation and its subsidiaries.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We make certain forward-looking statements in this Annual Report on Form 10-K and in the documents that are incorporated herein by reference. These forward-looking statements relate to our outlook or expectations for earnings, revenues, expenses, asset quality or other future financial or business performance, strategies or expectations, or the impact of legal, regulatory or supervisory matters on our business, results of operations or financial condition. Specifically, forward-looking statements may include:

 

   

statements preceded by, followed by or that include the words “estimate,” “plan,” “project,” “forecast,” “intend,” “expect,” “anticipate,” “believe,” “seek,” “target” or similar expressions.

These statements reflect our management’s judgment based on currently available information and involve a number of risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements.

Future performance cannot be ensured. Actual results may differ materially from those in the forward-looking statements. Some factors that could cause our actual results to differ include:

 

   

the completion and results of our pending merger with US BioEnergy Corporation (“US BioEnergy”);

 

   

the volatility and uncertainty of corn, natural gas, ethanol, unleaded gasoline and other commodities prices;

 

   

the results of our hedging transactions and other risk mitigation strategies;

 

   

operational disruptions at our facilities;

 

   

the effects of vigorous competition and excess capacity in the industries in which we operate;

 

   

the costs and business risks associated with developing new products and entering new markets;

 

   

our ability to locate and integrate potential future acquisitions;

 

   

our ability to develop a corn oil extraction business;

 

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the development of infrastructure related to the sale and distribution of ethanol;

 

   

the effects of other mergers and consolidations in the biofuels industry and unexpected announcements or developments from others in the biofuels industry;

 

   

the uncertainties related to our investments in ASA OpCo Holdings, LLC and other businesses;

 

   

the impact of new, emerging and competing technologies on our business;

 

   

the possibility of one or more of the markets in which we compete being impacted by political, legal and regulatory changes or other external factors over which they have no control;

 

   

changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices;

 

   

our reliance on key management personnel;

 

   

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 comply with Section 404 of the Sarbanes-Oxley Act, as amended; and

 

   

other risks referenced from time to time in our filings with the SEC and those factors listed in this Form 10K under Item 1A, “Risks Factors” beginning on page 11.

You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this Form 10K, or in the case of a document incorporated by reference, as of the date of that document. Except as required by law, we undertake no obligation to publicly update or release any revisions to these forward-looking statements to reflect any events or circumstances after the date of this Form 10-K or to reflect the occurrence of unanticipated events.

 

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PART I

 

ITEM 1. BUSINESS

Overview

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

Ethanol is a type of alcohol produced in the U.S. principally from corn. Ethanol is primarily used as a blend component in the U.S. gasoline fuel market, which approximated 142 billion gallons in 2007 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 2007. We believe the ethanol market will continue to grow as a result of ethanol’s cleaner burning characteristics, a shortage of domestic petroleum refining capacity, geopolitical concerns, and federally mandated renewable fuel usage. We also believe that E85, a fuel blend composed of 85% ethanol, may become increasingly important as an alternative to unleaded gasoline.

On August 17, 2007, we acquired all of the equity interests in ASA OpCo Holdings, LLC (“ASA Holdings”) from ASAlliances Biofuels, LLC. Through this transaction, which we refer to as the “ASA Acquistion”, we acquired ethanol production facilities in Linden, Indiana, Albion, Nebraska and Bloomingburg, Ohio.

We own and operate five of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 560 million gallons per year, or “MMGY.” As of March 4, 2008, our ethanol production capacity represented approximately 7% of the total ethanol production capacity in the U.S., according to the RFA.

Our facilities are designed to operate on a continuous basis and use current dry-milling technology, a production process that results in increased ethanol yield and reduced capital costs compared to wet-milling facilities. In addition to producing ethanol, we produce and sell wet and dry distillers grains as ethanol co-products, which serve to partially offset our corn costs. In 2007, we produced approximately 376.1 million gallons of fuel ethanol and 1.2 million tons of distillers grains.

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

On November 29, 2007, we entered into a merger agreement under which we will acquire US BioEnergy. US BioEnergy owns and operates four ethanol plants with total ethanol production capacity of 310 MMGY and is constructing four additional ethanol plants with expected total ethanol production capacity of 440 MMGY. We expect to issue approximately 64.8 million shares of our common stock in the transaction. Each company has scheduled a special meeting of shareholders on March 31, 2008 to approve the transaction, and we expect closing to occur in early April 2008.

 

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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 2007, according to the EIA, domestic demand has increased 17.7% 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 65.7% of the U.S. crude oil supply in 2007 and are estimated to rise by almost 10.0% 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 2007, world oil prices topped $100 a barrel at times and we expect oil prices to remain high. 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, (“RFS”), which eliminated the mandated use of oxygenates in reformulated gasoline and mandated annual use of 7.5 billion gallons per year, (“BGY”), of renewable fuels in the U.S. fuel supply by the year 2012. In December 2007, President Bush signed the Energy Independence and Security Act (the “2007 Act”), which increased the mandated minimum level of use of renewable fuels in the RFS to 9.0 billion gallons per year in 2008 (from 5.4 billion gallons under the RFS enacted in 2005), further increasing to 36 billion gallons per year in 2022. The 2007 Act also requires the increased use of “advanced” biofuels, which are alternative biofuels produced without using corn starch such as cellulosic ethanol and biomass-based diesel, with 21 billion gallons of the mandated 36 billion gallons of renewable fuel required to come from advanced biofuels by 2022. Required RFS volumes for both general and advanced renewable fuels in years to follow 2022 will be determined by a governmental administrator, in coordination with the U.S. Department of Energy and U.S Department of Agriculture.

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. The revised RFS minimum volumes and additional legislation that we believe affects the demand for ethanol, including the federal tax incentive program, are 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 more than 8.1 billion gallons in 2007. As of March 4, 2008, the top five producers accounted for approximately 41% of the ethanol production capacity in the U.S according to the RFA. The remaining production was generated by more than 125 smaller producers and farmer-owned cooperatives, many with production of 50 MMGY or less. Since a typical ethanol facility can be constructed in approximately 18-24 months from groundbreaking to operation, the industry is able to forecast capacity additions for up to 18 months in the future. As of March 4, 2008, the RFA estimated that ethanol facilities with capacity of an aggregate of an additional 5.3 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 the ethanol industry, which may cause the price of ethanol and/or distillers grains to decrease”.

 

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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, Indiana, Ohio, Missouri 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, 75% of the ethanol production capacity is generated from dry-mill facilities, with only 25% 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 (“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, (“WDGS”).

 

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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 have commenced installation of corn oil extraction equipment at our Aurora facility and are planning to install this equipment at two other facilities.

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 may 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.

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

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.

 

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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 may 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 may 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 may establish 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., (“Aventine”), for the marketing, billing, receipt of payment and other administrative services for substantially all of the ethanol that we produce at our Aurora and Fort Dodge facilities. We terminated these agreements as of March 31, 2007. Accordingly, with the exception of the long-term marketing agreement with Cargill acquired in the ASA Acquisition, we market and sell our ethanol directly to blenders, refiners and other end users.

In connection with this activity, we have our own marketing, distribution, transportation and storage infrastructure. As of February 29, 2008 we leased approximately 1,270 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 also have a marketing and sales force, as well as logistical and other operational personnel to staff our distribution activities. In addition, our senior management devote a larger portion of its time to sales, marketing and distribution activities.

We are also marketing our VE85 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.

Our ethanol customers include major refiners as well as small distributors. During 2007, sales to Cargill, Aventine, and Shell Trading Company US accounted for 14.3%, 14.2%, and 10.7%, respectively, of total sales. In 2006, we sold all of our ethanol to Aventine.

Distillers grains marketing. Except for the distillers grains produced at the facilities acquired in the ASA Acquisition, 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 85.5% of our co-product sales for 2007, and our sales of WDGS accounted for 14.5% of our co-product sales for 2007.

 

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ASA facilities: As part of the ASA Acquisition, we acquired the Linden, Albion and Bloomingburg facilities subject to long-term agreements with Cargill, under which Cargill is responsible for marketing all of the ethanol and distillers grains produced at the facilities. These agreements have ten year terms.

Competition

The ethanol market is highly competitive. According to the RFA, world ethanol production rose to 13.1 billion gallons in 2007. The U.S. and Brazil are the world’s largest producers of ethanol. As of March 4, 2008, industry capacity in the U.S. approximated 8.2 BGY, with an additional 5.3 BGY of capacity under construction. The ethanol industry in the U.S. consists of more than 140 production facilities and is primarily corn based, while the Brazilian ethanol production is primarily sugar cane based.

We compete with a number of large producers, including Archer Daniels Midland Company, US BioEnergy, POET, LLC, Hawkeye Renewables, LLC, Aventine Renewable Energy Holdings, Inc (“Aventine”), and Cargill. As of March 4, 2008, the top five producers accounted for approximately 41% of the ethanol production capacity in the U.S. according to the RFA. 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;

 

   

quality based on the 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.

 

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Legislation

Renewable Fuels Standard. The Energy Policy Act of 2005 established minimum annual volumes of renewable fuel to be used by petroleum refiners in the fuel supply. 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. In December 2007, President Bush signed the Energy Independence and Security Act (the “2007 Act”), which increased the mandated minimum level of use of renewable fuels in the RFS to 9 billion gallons per year in 2008 (from 5.4 billion gallons under the RFS enacted in 2005), further increasing to 36 billion gallons per year in 2022. The 2007 Act also requires the increased use of “advanced” biofuels, which are alternative biofuels produced without using corn starch such as cellulosic ethanol and biomass-based diesel, with 21 billion gallons of the mandated 36 billion gallons of renewable fuel required to come from advanced biofuels by 2022. Below is the revised RFS schedule included in 2007 Act.

 

Year

   Schedule    Corn    Cellulosic    Biodiesel    Unspecified
Advanced
          (gallons in billions)          

2008

   9.0    9.0    —      —      —  

2009

   11.1    10.5    —      0.5    0.1

2010

   13.0    12.0    0.1    0.7    0.2

2011

   14.0    12.6    0.3    0.8    0.3

2012

   15.2    13.2    0.5    1.0    0.5

2013

   16.6    13.8    1.0    —      1.8

2014

   18.2    14.4    1.8    —      2.0

2015

   20.5    15.0    3.0    —      2.5

2016

   22.3    15.0    4.3    —      3.0

2017

   24.0    15.0    5.5    —      3.5

2018

   26.0    15.0    7.0    —      4.0

2019

   28.0    15.0    8.5    —      4.5

2020

   30.0    15.0    10.5    —      4.5

2021

   33.0    15.0    13.5    —      4.5

2022

   36.0    15.0    16.0    —      5.0

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 $0.51 per gallon incentive for ethanol is scheduled to be reduced to $0.46 per gallon in 2009 and 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 is scheduled to expire on 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.

 

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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 2007.

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 2007 were not material, and we do not expect material expenditures for environmental controls in 2008. 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, 2007, we had approximately 496 full time employees.

 

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ITEM 1A. RISK FACTORS

Our business is subject to a number of risks and uncertainties. If any of these events contemplated by the following risks actually occur, then our business, financial condition or results of operations could be materially adversely affected. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business, financial condition and results of operations. In addition, there are several risk factors relating to the proposed merger with US BioEnergy, as more fully set forth below. Solely for purposes of this Item 1A, all references to “our,” “we” and “us” refer both to VeraSun and, assuming completion of the contemplated merger with US BioEnergy, the combined company after giving effect to such transaction.

RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS

Our results of operations, financial position and business will be highly dependent on commodity prices, which are subject to significant volatility and uncertainty, and the availability of supplies, so our respective 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 of operations.”

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

Corn is the principal raw material used to produce ethanol and dry and wet distillers grains. As a result, changes in the price of corn can significantly affect our business. Rising corn prices result in higher cost of ethanol and distillers grains. 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 60.4% of our total cost of goods sold for the twelve months ended December 31, 2007, compared to 49.5% for the twelve months ended December 31, 2006. Over the ten-year period from 1998 through 2007, corn prices (based on the Chicago Board of Trade (the “CBOT”) daily futures data) have ranged from a low of $1.75 per bushel on August 11, 2000 to a high of $4.55 per bushel on December 31, 2007, with prices averaging $2.42 per bushel during this period.

The biofuels industry has experienced significantly higher corn prices commencing in the fourth quarter of 2006, which have remained in 2007 at substantially higher levels than in 2006. In the year ended December 31, 2007, CBOT corn prices have ranged from a low of $3.10 per bushel to a high of $4.55 per bushel, with prices averaging $3.73 per bushel. At February 29, 2008, the CBOT price per bushel of corn for March delivery was $5.46. If these higher corn prices continue, they may have a material adverse effect on our business, results of operations and financial position.

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. Increasing domestic ethanol capacity could boost the demand for corn

 

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and result in increased corn prices. In 2006, corn bought by ethanol plants represented approximately 18% of the total corn supply for that year according to results reported by the National Corn Growers Association, and this percentage is expected to increase as additional ethanol capacity comes online, rising to more than 30% of the total corn supply by 2009/2010 according to the United States Department of Agriculture or USDA. In addition, the price any of the companies pay for corn at a facility could increase if an additional ethanol production facility is built in the same general vicinity.

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

Our gross margin depends principally on the spread between ethanol and corn prices. During the five-year period from 2003 through 2007, ethanol prices (based on average U.S. ethanol rack prices from Bloomberg (“Bloomberg”)) have ranged from a low of $1.11 per gallon to a high of $3.98 per gallon, averaging $1.90 per gallon during this period. For the year ended December 31, 2007, ethanol prices averaged $2.12 per gallon, reaching a high of $2.50 per gallon and a low of $1.69 per gallon (based on the daily closing prices from Bloomberg). In early 2006, the spread between ethanol and corn prices was at historically high levels, driven in large part by oil companies removing a competitive product, MTBE, from the fuel stream and replacing it with ethanol in a relatively short time period. However, this spread has fluctuated widely and narrowed significantly during 2007. Fluctuations are likely to continue to occur. A sustained narrow spread or any further reduction in the spread between ethanol and corn prices, whether as a result of sustained high or increased corn prices or sustained low or decreased ethanol prices, would adversely affect our results of operations and financial position. Further, it is possible that ethanol prices could decline below our marginal cost of production, which could cause us to suspend production of ethanol at some or all of our plants.

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

We rely upon third parties for our supply of natural gas, which is consumed as fuel 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 weather conditions (including hurricanes), overall economic conditions and foreign and domestic governmental regulation and relations. Significant disruptions in the supply of natural gas could impair our ability to manufacture ethanol for our customers. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial position. Natural gas costs represented approximately 10.2% of our cost of goods sold for the twelve months ended December 31, 2007, compared to 15.9% for the twelve months ended December 31, 2006. The price fluctuations in natural gas prices over the eight-year period from 2000 through 2007, based on the New York Mercantile Exchange, or NYMEX, daily futures data, have ranged from a low of $1.83 per MMBTU on September 26, 2001 to a high of $15.38 per MMBTU on December 13, 2005, averaging $5.63 per MMBTU during this period. At February 29, 2008, the NYMEX price of natural gas for April delivery was $9.37 per MMBTU.

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

Ethanol is marketed both as an important fuel component to reduce vehicle emissions from gasoline and as an octane enhancer to improve the octane rating of gasoline with which it is blended. As a result, ethanol prices are influenced by the supply and demand for gasoline and our future 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.

 

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The price of distillers grains is affected by the price of other commodity products, such as soybeans, and decreases in the price of these commodities could decrease the price of distillers grains.

Distillers grains compete with other protein-based animal feed products. The price of distillers grains may decrease when the price of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the commodities from which they are derived. Downward pressure on commodity prices, such as soybeans, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers grains. Because the price of distillers grains is not tied to production costs, decreases in the price of distillers grains will result in our generating less revenue and lower profit margins.

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. In recent years, the spot price of corn tended to rise during the spring planting season in May and June and tended to decrease during the fall harvest in October and November. The price of natural gas, however, tends to move opposite of corn and tends to be lower in the spring and summer and higher in the fall and winter. In addition, ethanol prices are substantially correlated with the price of unleaded gasoline. The price of unleaded gasoline tends to rise during the summer. Given our limited history and the growth of the industry, it is unclear how these seasonal fluctuations will affect our results over time.

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

In an attempt to partially offset the effects of volatility of ethanol prices and corn and natural gas costs, we enter into contracts to supply a portion of our respective ethanol production or purchase a portion of our respective 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 received for ethanol under indexed contracts entered into by us. 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 price of the commodity underlying the hedging agreement and the actual prices paid or received by us for the physical commodity bought or sold. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. A hedge position is often settled in the same time frame as the physical commodity is either purchased (corn and natural gas) or sold (ethanol). Hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol. We also vary the amount of hedging or other risk mitigation strategies we undertake, and we may choose not to engage in hedging transactions at all. As a result, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol or unleaded gasoline.

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

We plan to grow our business by investing in new or existing plants and pursuing other business opportunities.

Additional financing may be necessary to implement these expansion strategies, which may not be accessible or may not be available on acceptable terms. Any expansion may be financed with additional indebtedness or by issuing additional equity securities, which would further dilute shareholders’ interests. In addition, as described below under “We may be adversely affected by environmental, health and safety laws,

 

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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. Any expansion plans may also result in other unanticipated adverse consequences, such as the diversion of management’s attention from existing operations.

Construction costs associated with expansion may also increase to levels that would make a new plant too expensive to complete or unprofitable to operate. Contractors, engineering firms, construction firms and equipment suppliers also receive requests and orders from other ethanol companies and, therefore, it may become hard or impossible 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 commencement of operations as expected at any new facilities.

The expansion strategies also depend on prevailing market conditions for the price of ethanol and the costs of corn and natural gas and expectations of future market conditions. In October 2007, we suspended construction of our Reynolds facility due to market conditions. If market conditions do not improve as anticipated, we could lose our investment in this facility and could incur additional costs associated with terminating various construction contracts. We also may not proceed with construction at other development sites and could incur losses associated with our investments in those sites.

The significant expansion of ethanol production capacity currently underway in the U.S. may also impede any expansion strategy. As a result of this expansion within the ethanol industry, we believe that there is increasing competition for suitable sites for ethanol plants, and we may not find suitable sites for construction of new plants or other suitable expansion opportunities. Even if suitable sites or opportunities are identified, we may not be able to secure the services and products from the contractors, engineering firms, construction firms and equipment suppliers necessary to build ethanol plants on a timely basis or on acceptable economic terms.

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

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

As part of our business strategy, we may consider acquisitions of building sites, production plants, storage or distribution facilities and selected infrastructure. In August 2007, we completed the acquisition of ASA OpCo Holdings, LLC (“ASA Acquisition”). It may be difficult to find additional suitable acquisition opportunities.

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

 

   

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

 

   

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

 

   

risks relating to environmental hazards on purchased sites;

 

   

risks relating to acquiring or developing the infrastructure needed for facilities or acquired sites, including access to rail networks;

 

   

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

 

   

diversion of financial and management resources from existing operations;

 

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the purchase price or other devoted resources may exceed the value realized, or the value we could have realized if the purchase price or other resources had been allocated to another opportunity;

 

   

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

 

   

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

 

   

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

 

   

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

We also may pursue acquisitions through joint ventures or partnerships. Partnerships and joint ventures typically involve restrictions on actions that the partnership or joint venture may take without the approval of the partners. These types of provisions may limit our ability to manage a partnership or joint venture in a manner that is in our best interest but is opposed by our other partner or partners.

Future acquisitions may involve the issuance of equity securities as payment or in connection with financing the business or assets acquired, and as a result, could dilute the ownership interests of you. In addition, additional debt and related interest expense may be necessary in order to consummate these transactions, as well as to assume unforeseen liabilities, all of which could have a material adverse effect on our business, results of operations and financial condition. The failure to successfully evaluate and execute acquisitions or joint ventures or otherwise adequately address the risks associated with acquisitions or joint ventures could have a material adverse effect on our business, results of operations and financial condition.

For risks relating to the proposed merger of VeraSun and US BioEnergy, see “Risk Factors Relating to the Proposed Merger with US BioEnergy” below.

Our goodwill could become impaired and write-downs on the value of such goodwill may be required.

The proposed merger of VeraSun and US BioEnergy will be accounted for by us using the purchase method of accounting. Under this method of accounting, the purchase price will be allocated to the fair value of the net assets acquired. The excess purchase price over the fair value of the tangible and identified intangible assets acquired will be allocated to goodwill. As a result of the merger, we expect to have significant goodwill, and as of December 31, 2007, we had goodwill of approximately $169.6 million resulting from prior transactions. Current accounting rules require that goodwill and indefinite life intangible assets be assessed for impairment annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If the carrying amount of a reporting unit exceeds its fair value, then a goodwill impairment test is performed to measure the amount of the impairment loss, if any. The goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as in a business combination. Determining the fair value of the implied goodwill is judgmental in nature and often involves the use of significant estimates and assumptions. These estimates and assumptions could have a significant impact on whether or not an impairment charge is recognized and also the magnitude of any such charge. Estimates of fair value are determined primarily using discounted cash flows and market comparisons. These approaches use significant estimates and assumptions, including projection and timing of future cash flows, discount rates reflecting the risk inherent in future cash flows, perpetual growth rates, determination of appropriate market comparables, and determination of whether a premium or discount should be applied to comparables. Therefore, changes in commodity prices or the price of our stock may impact the goodwill impairment analysis. If our actual results are worse than the plans and estimates used to assess the recoverability of the assets in connection with the proposed merger, or previous transactions entered into by us, or our plans and estimates are otherwise incorrect, we could incur impairment charges relating to the goodwill resulting from such transactions, including up to the full amount of such goodwill.

 

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

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

 

   

additional rail capacity;

 

   

additional storage facilities for ethanol;

 

   

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

 

   

expansion of refining and blending facilities to handle ethanol;

 

   

growth in service stations equipped to handle ethanol fuels; and

 

   

growth in the fleet of flexible fuel vehicles, or FFVs, capable of using E85 fuel.

The rapid expansion of the ethanol industry currently underway compounds the issues presented by the need to develop and expand ethanol related infrastructure, as the lack of infrastructure prevents the use of ethanol in certain areas where there might otherwise be demand and results in excess ethanol supply in areas with more established ethanol infrastructure, depressing ethanol prices in those areas.

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 by us in making the changes to or expansion of infrastructure could hurt the demand or prices for products, impede delivery of products, impose additional costs or otherwise have a material adverse effect on 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 may not achieve anticipated operating results and our financial position may be adversely affected if we do not successfully develop a corn oil extraction business.

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

government regulation; and

 

   

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

 

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We have a limited operating history and business may not be as successful as envisioned.

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

Some of these risks relate to our potential inability to:

 

   

effectively manage business and operations;

 

   

successfully execute plans to sell ethanol directly to customers;

 

   

recruit and retain key personnel;

 

   

successfully maintain a low-cost structure through the expansion of scale in business;

 

   

manage rapid growth in personnel and operations;

 

   

develop new products that complement existing business; and

 

   

successfully address the other risks described throughout this Annual Report on form 10-K.

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

New plants under construction or decreases in the demand for ethanol may result in excess production capacity in the ethanol industry, which may cause the price of ethanol and/or distillers grains to decrease.

According to the RFA, domestic ethanol production capacity has increased from 1.8 billion gallons per year (“BGY”) as of January 2001 to approximately 8.2 BGY as of March 4, 2008. The RFA estimates that, as of March 4, 2008, approximately 5.3 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 140 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 could 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 or acquire hybrid vehicles.

In addition, because ethanol production produces distillers grains as a co-product, increased ethanol production will also lead to increased supplies of distillers grains. An increase in the supply of distillers grains, without corresponding increases in demand, could lead to lower prices or an inability to sell our distillers grains production. A decline in the price of distillers grains or the distillers grains market generally could have a material adverse effect on our business, results of operations and financial condition.

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

In the U.S., there is competition with other corn processors, ethanol producers and refiners, including Archer Daniels Midland Company, US BioEnergy, POET, LLC, Hawkeye Renewables, LLC, Aventine Renewable Energy Holdings, Inc. (“Aventine”), and Cargill . As of March 1, 2008, the top five producers accounted for approximately 41% of the ethanol production capacity in the U.S. according to the RFA. A number

 

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of our competitors are divisions of substantially larger enterprises and have substantially greater financial resources than we do. Smaller competitors also pose a threat. Farmer-owned cooperatives and independent firms consisting of groups of individual farmers and investors have been able to compete successfully in the ethanol industry. These smaller competitors operate smaller facilities that do not affect the local price of corn grown in the proximity of the facility as much as larger facilities 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. Most new ethanol plants under development across the country are individually owned.

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

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

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

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

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

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

In addition, alternative fuels, additives and oxygenates are continually under development. Alternative fuel additives that can replace ethanol may be developed, which may decrease the demand for ethanol. It is also possible that technological advances in engine and exhaust system design and performance could reduce the use of oxygenates, which would lower the demand for ethanol, and our business, results of operations and financial condition may be materially adversely affected.

 

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

The elimination or significant reduction in the blenders’ credit could have a material adverse effect on our results of operations and financial position. The cost of production of ethanol is made significantly more competitive with regular gasoline by federal tax incentives. The federal excise tax incentive program currently allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax rate reduction for each blended gallon they sell. If the fuel is blended with 10% ethanol, the refiner/marketer pays $0.051 per gallon less tax, which equates to an incentive of $0.51 per gallon of ethanol. The $0.51 per gallon incentive for ethanol is scheduled to be reduced to $0.46 per gallon in 2009 and to expire in 2010. The blenders’ credits could be eliminated or reduced at any time through an act of Congress and may not be renewed in 2010 or may be renewed on different terms. In addition, the blenders’ credits, as well as other federal and state programs benefiting ethanol (such as tariffs), generally are subject to U.S. government obligations under international trade agreements, including those under the World Trade Organization Agreement on Subsidies and Countervailing Measures, and might be the subject of challenges thereunder, in whole or in part.

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 that is 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 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 our 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 renewable fuel standard (“RFS”) program in the Energy Independence and Security Act signed into law on December 19, 2007 (the “2007 Act”) is uncertain. The mandated minimum level of use of renewable fuels in the RFS under the 2007 Act increased to 9 billion gallons per year in 2008 (from 5.4 billion gallons under the RFS enacted in 2005), further increasing to 36 billion gallons per year in 2022. The 2007 Act also requires the increased use of “advanced” biofuels, which are alternative biofuels produced without using corn starch such as cellulosic ethanol and biomass-based diesel, with 21 billion gallons of the mandated 36 billion gallons of renewable fuel required to come from advanced biofuels by 2022. Required RFS volumes for both general and advanced renewable fuels in years to follow 2022 will be determined by a governmental administrator, in coordination with the U.S. Department of Energy and U.S. Department of Agriculture. Increased competition from other types of biofuels could have a material adverse effect on our results of operations and our financial position. See “Our competitive position, financial position and results of operations may be adversely affected by technological advances and efforts to anticipate and employ such technological advances may prove unsuccessful.”

The RFS program and the 2007 Act also include provisions allowing “credits” to be granted to fuel producers who blend in their fuel more than the required percentage of renewable fuels in a given year. These credits may be used in subsequent years to satisfy RFS production percentage and volume standards and may be

 

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traded to other parties. The accumulation of excess credits could further reduce the impact of the RFS mandate schedule and result in a lower ethanol price or could result in greater fluctuations in demand for ethanol from year to year, both of which could have a material adverse effect on our results of operations and our financial condition.

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 RFS as passed as part of the Energy Policy Act of 2005, the U.S. Environmental Protection Agency, 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 “EPA”, determines upon the petition of one or more states 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. In addition, the Energy Independence and Security Act of 2007 allows any other person subject to the requirements of the RFS or the EPA Administrator to file a petition for such a waiver. Any waiver of the RFS with respect to one or more states could adversely offset demand for ethanol and could have a material adverse effect on our results of operations and our financial condition.

Various studies have criticized the efficiency of ethanol, in general, and corn-based ethanol in particular, which could lead to the reduction or repeal of incentives and tariffs that promote the use and domestic production of ethanol or otherwise negatively impact public perception and acceptance of ethanol as an alternative fuel.

Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels and as potentially depleting water resources. Other studies have suggested that corn-based ethanol is less efficient than ethanol produced from switchgrass or wheat grain and that it negatively impacts consumers by causing prices for dairy, meat and other foodstuffs from livestock that consume corn to increase. If these views gain acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of these measures. These views could also negatively impact public perception of the ethanol industry and acceptance of ethanol as an alternative fuel.

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 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 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 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.

 

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In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require 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 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, losses could be sustained 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 our financial position.

We are dependent on our respective production facilities, and any operational disruption may result in a reduction of sales volumes, which could cause substantial losses.

Our revenues are derived from the sale of ethanol and the related co-products produced at our facilities. A major accident or damage by severe weather or other natural disasters may cause significant interruptions at such facilities. In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other operational hazards inherent in the ethanol 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 such insurance may not be renewable on commercially reasonable terms or at all. Moreover, the operation of our plants is subject to various uncertainties, including uncertainties relating to the effectiveness of process improvements designed to achieve increased production capacities. As a result, our plants may not produce ethanol and distillers grains at the levels we expect and our business, results of operations and financial condition may be materially adversely affected.

Disruptions to infrastructure, or in the supply of fuel, natural gas or water, could materially and adversely affect our business.

Our business depends on the continuing availability of rail, road, port, storage and distribution infrastructure. Any disruptions in this infrastructure network, whether caused by labor difficulties, earthquakes, storms, other natural disasters, human error or malfeasance or other reasons, could have a material adverse effect on our business. We rely upon third-parties to maintain the rail lines from their plants to the national rail network, and any failure on these third parties’ part to maintain the lines could impede the delivery of products, impose additional costs and could have a material adverse effect on our business, results of operations and financial condition.

We also depend on the continuing availability of raw materials, including fuel and natural gas. The production of ethanol, from the planting of corn to the distribution of ethanol to refiners, is highly energy-intensive. Significant amounts of fuel and natural gas are required for the growing, fertilizing and harvesting of corn, as well as for the fermentation, distillation and transportation of ethanol and the drying of distillers grains. A serious disruption in supplies of fuel or natural gas, including as a result of delivery curtailments to industrial customers due to extremely cold weather, or significant increases in the prices of fuel or natural gas, could significantly reduce the availability of raw materials at our plants, increase production costs and could have a material adverse effect on our business, results of operations and financial condition.

 

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Our ethanol plants also require a significant and uninterrupted supply of water of suitable quality to operate. If there is an interruption in the supply of water for any reason, one or more plants may be required to halt production. If production is halted at one or more of these plants for an extended period of time, it could have a material adverse effect on our business, results of operations and financial condition.

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

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

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

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 expansion strategy and execution of our business plan. The loss of any of these officers could have a material adverse effect upon our results of operations and our 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 respective officers. The loss of any of these officers could delay or prevent the achievement of our business objectives.

Competition for qualified personnel in the ethanol industry is intense and we may not be able to hire and retain qualified personnel to operate our ethanol plants.

Our success depends, in part, on our ability to attract and retain competent personnel. For each of our plants, qualified managers, engineers, operations and other personnel must be hired, which can be challenging in a rural community. Competition for both managers and plant employees in the ethanol industry is intense, and we may not be able to attract and retain qualified personnel. If we are unable to hire and retain productive and competent personnel, our expansion strategy may be adversely affected, the amount of ethanol we produce may decrease and we may not be able to efficiently operate our ethanol plants and execute our business strategy.

Operations at our new facilities and additional planned facilities are subject to various uncertainties, which may cause them to not achieve results comparable to existing operational plants.

New plants and 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 failures of key equipment. Such a failure during test operations delayed the startup process at our Fort Dodge facility, which is now operating at full capacity, in the fall of 2005. Due to these uncertainties, the results of new facilities or additional planned facilities may not be comparable to those of existing operational plants.

 

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

As of December 31, 2007, our total debt was $905.5 million (net of unaccreted discount of $3.0 million). Under agreements governing our debt, we may be able to incur a significant amount of additional debt from time to time. If we do so, the risks related to high levels of debt could increase. In addition, if we complete our acquisition of US BioEnergy, our consolidated total outstanding debt would be increased because US BioEnergy’s debt would remain outstanding after the acquisition. Specifically, our high level of debt could have significant consequences to our shareholders, including the following:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

being at a competitive disadvantage against less leveraged competitors;

 

   

being vulnerable to increases in prevailing interest rates;

 

   

subjecting all or substantially all of our assets to liens, which means that there may be no assets left for shareholders in the event of a liquidation; and

 

   

limiting our ability to make business and operational decisions regarding our business and subsidiaries, including, among other things, limiting our ability to pay dividends to our respective shareholders, make capital improvements, sell or purchase assets or engage in transactions deemed appropriate and in our best interest.

Some of our debt bears interest at variable rates, which creates exposure to interest rate risk. If interest rates increase, our debt service obligations with respect to the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

We are a holding company, and there are limitations on our ability to receive distributions from our subsidiaries.

We conduct all of our operations through subsidiaries and are dependent upon dividends or other intercompany transfers of funds from our subsidiaries to meet our obligations. Moreover, some of our subsidiaries are currently, or are expected in the future to be, limited in their ability to pay dividends or make distributions to us by the terms of their financing agreements.

Actions of third parties may result in a default or mandatory prepayments under the ASA Senior Credit Facility.

The ASA Senior Credit Facility contains customary events of default and also includes events of default based on certain actions by Fagen, Inc., the design-builder of the Linden, Albion and Bloomingburg facilities controlled by Ron Fagen, the beneficial owner of approximately 19% of US BioEnergy’s common stock, Cargill, and other third parties that provide goods and services to the facilities, including actions that are unrelated to the construction and operation of the facilities. In particular, the material breach by any such third parties of their agreements relating to the facilities, the failure of any such third parties to pay their indebtedness, including trade payables, and the entry of material judgments or the occurrence of an insolvency event with respect to any such third party would constitute an event of default under the Senior Credit Facility. The parties to the ASA Senior

 

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Credit Facility have no control over such third parties and could experience an event of default with no ability to cure the default. In that event, the lenders could demand payment of all indebtedness outstanding under the Senior Credit Facility under circumstances where alternative financing may be unavailable or available on unfavorable terms. If the parties to the ASA Senior Credit Facility were unable to obtain alternative financing to pay the Senior Credit Facility, the lenders could foreclose on the Linden, Albion, and Bloomingburg facilities and VeraSun’s and the combined company’s investment in those facilities could be lost. The parties to the ASA Senior Credit Facility also may be required to make mandatory prepayments under this credit agreement if the Volumetric Ethanol Excise Tax Credit expires or is scheduled to expire less than eighteen months after July 1, 2009.

Certain of our shareholders exert significant influence over us. Their interests may not coincide with ours or the interests of our other shareholders, and these certain shareholders may make decisions with which we or our other shareholders may disagree.

Our executive officers and directors as a group beneficially own approximately 38.5% of our outstanding common stock, including Donald L. Endres, our chief executive officer, who beneficially owns approximately 35.1% of our outstanding common stock. In addition, Gordon W. Ommen, US BioEnergy’s chief executive officer, Ron Fagen and CHS Inc. beneficially own approximately 8.2%, 18.3% and 19.9% of US BioEnergy’s common stock, respectively, and US BioEnergy’s executive officers, directors and principal shareholders, i.e., shareholders holding more than 5% of US BioEnergy’s common stock, including Gordon W. Ommen, Ron Fagen and CHS Inc., together control approximately 46.4% of its common stock. Based on these ownership percentages, Messrs. Endres, Ommen and Fagen and CHS Inc. will own in the aggregate approximately 39.7% of our outstanding common stock following the proposed merger with US BioEnergy. As a result, these shareholders, acting individually or together, could significantly influence our management and affairs and all matters requiring shareholder approval, including the election of directors and approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying or preventing a change in control of us and might affect the market price of our common stock.

The interests of these shareholders may not coincide with our interests or the interests of our other shareholders. For instance, Capitaline Advisors, LLC, a private equity investment management firm specializing in renewable energy investments which is 100% owned and controlled by Gordon W. Ommen, and Fagen, Inc., the leading builder of ethanol plants in the U.S., which is owned and controlled by Ron Fagen, have invested and may continue to invest in a number of other ethanol producers. For example, Capitaline Advisors currently has an investment in Big River Resources, LLC, US BioEnergy’s joint venture partner for the Grinnell plant. As a result of these and other potential conflicting interests, these existing shareholders may make decisions with respect to us with which we or our other shareholders may disagree.

We do not own or control some of the assets we depend on to operate our business.

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

We are subject to financial reporting and other requirements, and we will become subject to additional financial reporting and other requirements, in each case for which our accounting, internal audit and other management systems and resources may not be adequately prepared. We have experienced material weaknesses in our internal controls.

We are 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 of 2002. Section 404 requires annual management assessment of the effectiveness of a company’s internal controls over financial reporting and a report by its independent registered public accounting firm addressing the effectiveness of our internal controls

 

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over financial reporting. These reporting and other obligations place significant demands on our management, administrative, operational, internal audit and accounting resources. If we are unable to meet these demands in a timely and effective fashion, our ability to comply with our financial reporting requirements and other rules that apply to us could be impaired. Any failure to maintain effective internal controls could have a material adverse effect on our business, results of operations and financial condition.

In connection with the audit of our consolidated financial statements for the year ended December 31, 2006, we identified several material weaknesses in our internal controls over financial reporting relating to inadequate monitoring of accounting recognition matters and significant accounting estimates, including derivative financial instruments and income taxes, and deficiencies in our financial closing process. A “material weakness” is a significant deficiency, or a combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected. A “significant deficiency” is a control deficiency, or a combination of control deficiencies, that adversely affects an entity’s ability to initiate, authorize, record, process or report financial data reliably in accordance with generally accepted accounting principles such that there is more than a remote likelihood that a misstatement of the entity’s financial statements that is more than inconsequential will not be prevented or detected. We believe that we have remediated these weaknesses, but we cannot assure you that we will have no future deficiencies or weaknesses in our internal controls over financial reporting.

Any failure to remediate any material weaknesses that we may identify or to implement new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

Some provisions contained in our articles of incorporation and bylaws, as well as provisions of South Dakota law, could impair a takeover attempt.

Our articles of incorporation and bylaws and South Dakota law contain several provisions that may make it substantially more difficult for a third-party to acquire control of us without the approval of our board of directors. This may make it more difficult or expensive for a third-party to acquire a majority of our outstanding common stock. These provisions also may delay, prevent or deter a merger, acquisition, tender offer, proxy contest or other transaction that might otherwise result in our shareholders receiving a premium over the market price for their common stock.

RISK FACTORS RELATING TO THE PROPOSED MERGER WITH US BIOENERGY

Our failure to complete the proposed merger with US BioEnergy could negatively impact our stock price and our future business and financial results.

Completion of the proposed merger is conditioned upon, among other things, the approval and adoption of the merger agreement and the approval of the merger by US BioEnergy shareholders, the approval of the issuance of our common stock in the merger by our shareholders. In addition, the merger agreement contains other customary closing conditions, which may not be satisfied or waived. The merger agreement also contains certain termination rights held by US BioEnergy and us. If for any reason we are unable to complete the merger, we would be subject to a number of risks, including the following:

 

   

we may be required, under certain circumstances, to pay US BioEnergy a termination fee of $61 million;

 

   

we may not realize the benefits of the proposed merger, including any synergies from combining the two companies;

 

   

we will incur and will remain liable for significant transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the merger, whether or not it is completed;

 

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the diversion of our management team’s time and attention away from day-to-day operations could have an adverse effect on our financial condition and operating results;

 

   

we could lose otherwise attractive business opportunities due to restrictions under the merger agreement;

 

   

our business may be harmed to the extent that customers, suppliers and others believe that we cannot effectively compete in the marketplace without the merger, or otherwise remain uncertain about our company;

 

   

we would continue to be exposed to the general competitive pressures and risks discussed elsewhere in this Annual Report on Form 10-K, and such pressures and risks may be increased if the merger is not completed; and

 

   

the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed.

The occurrence of any of these events, individually or in combination, could have a material adverse effect on our business, financial condition and results of operations or the trading price of our common stock.

Although we expect that the proposed merger will result in benefits to us, we may not realize those benefits because of integration and other challenges.

Our failure to meet the challenges involved in integrating our and US BioEnergy’s operations successfully or otherwise to realize any of the anticipated benefits of the proposed merger could seriously harm our results of operations. Realizing the benefits of the proposed merger will depend in part on the integration of operations and personnel. The integration of companies is a complex and time-consuming process that, without proper planning and implementation, could significantly disrupt our business. The challenges involved in integration include the following:

 

   

difficulties in integrating operations, existing contracts, accounting processes and employees and realizing the anticipated synergies of the combined businesses;

 

   

diversion of financial resources from existing operations;

 

   

minimizing the diversion of management attention from ongoing business concerns;

 

   

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;

 

   

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

 

   

assumption of unanticipated problems or latent liabilities; and

 

   

general competitive factors in the market place.

We may not successfully integrate the operations of VeraSun and US BioEnergy in a timely manner, or at all, and we may not realize the anticipated benefits or synergies of the merger to the extent, or in the timeframe, anticipated. The anticipated benefits and synergies are based on projections and assumptions, not actual experience, and assume a successful integration. In addition to the integration risks discussed above, our ability to realize these benefits and synergies could be adversely impacted by practical constraints on our ability to combine operations.

 

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In order to be successful, we must retain and motivate key employees and failure to do so could seriously harm us.

In order to be successful, we must retain and motivate executives and other key employees. Our current employees or US BioEnergy employees may experience uncertainty about their future roles with us until or after our post-merger strategies are announced or executed. These circumstances may adversely affect our ability to retain key personnel. We also must continue to motivate employees and keep them focused on our strategies and goals, which may be particularly difficult due to the potential distractions of the merger.

If we are unable to manage growth profitably, our business and financial results could suffer.

Our future financial results will depend in part on our ability to profitably manage our core businesses, including any growth that we may be able to achieve. Since our incorporation, we have engaged in the identification of, and competition for, growth and expansion opportunities. In order to achieve those initiatives, we will need to maintain existing customers and attract new customers, recruit, train, retain and effectively manage employees, as well as expand operations, customer support and financial control systems. If we are unable to manage our businesses profitably, including any growth that we may be able to achieve, our business and financial results could suffer.

In our proposed merger with US BioEnergy, the exchange ratio is fixed and will not be adjusted in the event of any change in either our or US BioEnergy’s stock price. Accordingly, because the market price of our common stock may fluctuate, at the time of the our special meeting of shareholders, our shareholders cannot be sure of the market value of the consideration that we will pay in the merger.

Upon completion of the proposed merger, US BioEnergy shareholders will receive consideration equal to 0.810 shares of VeraSun common stock for each share of US BioEnergy common stock they own. The 0.810 to 1 exchange ratio was agreed upon in the merger agreement, and will not be adjusted due to any increases or decreases in the price of VeraSun or US BioEnergy common stock. In addition, neither party has a right to terminate the merger agreement based solely upon changes in the market price of VeraSun’s common stock or US BioEnergy’s common stock, and the merger agreement contains no other provisions that would limit the impact of increases or decreases in the market price of VeraSun’s or US BioEnergy’s common stock. As a result, any changes in the value of VeraSun’s common stock will have a corresponding effect on the value of the consideration that VeraSun pays to US BioEnergy shareholders in the merger.

The market price of VeraSun common stock at the time of completion of the merger may vary significantly from the price on the date of the merger agreement or from the price on the date that VeraSun shareholders and US BioEnergy shareholders submit proxies for their respective shareholders’ meetings or the dates of such shareholders’ meetings. These variations may be caused by a variety of factors, including:

 

   

changes in the business, operations and prospects of VeraSun or US BioEnergy;

 

   

changes in market assessments of the business, operations and prospects of the combined company;

 

   

market assessments of the likelihood that the proposed merger will be completed;

 

   

interest rates, general market and economic conditions and other factors generally affecting the price of VeraSun’s common stock and US BioEnergy’s common stock;

 

   

conditions in the biofuels industry generally;

 

   

changes in market prices for ethanol, distillers grains or raw materials, such as corn or natural gas;

 

   

VeraSun’s ability to raise additional capital; and

 

   

changes in federal, state and local legislation, governmental regulation and other legal developments affecting VeraSun or US BioEnergy.

 

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VeraSun common stock has historically experienced volatility. The closing price of VeraSun common stock on the NYSE on November 28, 2007, the day prior to the announcement of the merger agreement, was $ 10.64 per share. From November 28, 2007 through February 29, 2008, the trading price of VeraSun common stock ranged from a high of $17.75 per share to a low of $8.59 per share. The market price of VeraSun common stock may continue to fluctuate prior to completion of the merger, which would result in corresponding fluctuations in the value of the consideration paid by VeraSun to US BioEnergy shareholders in the merger.

In addition, because the proposed merger will be consummated after the VeraSun special meeting, at the time of the VeraSun special meeting VeraSun shareholders may not be sure of the market value of the VeraSun common stock that US BioEnergy shareholders will receive upon completion of the merger and VeraSun may pay more for shares of US BioEnergy common stock than the value calculated on the date of the VeraSun special meeting. Similarly, because the date that the merger is completed may be later than the date of the US BioEnergy special meeting, at the time of the US BioEnergy special meeting US BioEnergy shareholders may not be sure of the market value of the VeraSun common stock they will receive upon completion of the merger or the market value of VeraSun common stock at any time after the completion of the merger.

We urge you to obtain current market quotations for VeraSun and US BioEnergy common stock.

The issuance of shares of VeraSun common stock to US BioEnergy shareholders in the proposed merger will substantially reduce the percentage ownership interest of current VeraSun shareholders.

If the proposed merger is completed, VeraSun will issue approximately 64.5 million shares of VeraSun common stock in the merger. Based on the number of shares of VeraSun and US BioEnergy common stock outstanding on the VeraSun and US BioEnergy record dates, US BioEnergy shareholders before the merger will own, in the aggregate, approximately 41% of the shares of VeraSun common stock outstanding immediately after the merger. The issuance of shares of VeraSun common stock to US BioEnergy shareholders in the merger and to holders of assumed options and restricted stock awards to acquire shares of US BioEnergy common stock will cause a significant reduction in the relative percentage interest of current VeraSun shareholders in earnings, voting, liquidation value and book and market value of VeraSun.

Charges to earnings resulting from the application of the purchase method of accounting may adversely affect the market value of VeraSun’s common stock following the proposed merger.

In accordance with U.S. GAAP, the combined company will account for the merger using the purchase method of accounting, which will result in charges to VeraSun’s earnings that could adversely affect the market value of the common stock of VeraSun following completion of the proposed merger. Under the purchase method of accounting, the combined company will allocate the total purchase price to US BioEnergy’s net tangible assets, amortizable intangible assets and intangible assets with indefinite lives based on their fair values as of the date of completion of the merger, and record the excess of the purchase price over the fair values of the identified tangible and intangible assets as goodwill. The combined company will incur additional depreciation and amortization expense over the useful lives of certain of the net tangible and intangible assets acquired in connection with the merger. In addition, to the extent the value of goodwill or intangible assets becomes impaired, the combined company may be required to incur material charges relating to the impairment of those assets. These depreciation, amortization and potential impairment charges could have a material impact on the combined company’s results of operations and adversely affect the market value of VeraSun’s common stock.

Some of the directors and executive officers of US BioEnergy and VeraSun have interests in the proposed merger that are different from, or in addition to, those of US BioEnergy’s and VeraSun’s other shareholders.

Certain directors of US BioEnergy and VeraSun have arrangements or other interests that provide them with interests in the proposed merger that are different from, or in addition to, those of US BioEnergy’s or VeraSun’s other shareholders. For example, Donald L. Endres, the CEO of VeraSun, who is also a director of VeraSun, will, pursuant to the merger agreement, remain CEO of VeraSun and will also remain on the board of directors of

 

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VeraSun following the merger, and Gordon W. Ommen, the President and CEO of US BioEnergy, will become non-executive chairman of the board of directors of VeraSun following the merger. In addition, three other US BioEnergy directors and all of the other VeraSun directors may serve on VeraSun’s board following the merger. While other US BioEnergy directors will not become directors of the combined company after the merger, VeraSun will maintain liability insurance and US BioEnergy’s directors will be indemnified for services as directors of US BioEnergy before the merger. Certain officers of VeraSun and US BioEnergy also have change in control agreements and participate in equity incentive plans provided by VeraSun or US BioEnergy that will provide them with certain enhanced protections and acceleration of equity awards if the merger occurs. In addition, two directors of US BioEnergy are executive officers of entities that have commercial arrangements with US BioEnergy, and one of these entities also has commercial arrangements with VeraSun.

The merger agreement limits the ability of VeraSun to pursue alternatives to the proposed merger, and in certain instances requires payment of a termination fee, which could deter a third party from proposing an alternative transaction to the merger.

The merger agreement contains terms and conditions that make it more difficult for VeraSun to enter into an alternative transaction to the proposed merger. These “no shop” provisions impose restrictions on VeraSun that, subject to certain exceptions, limit VeraSun’s ability to discuss, facilitate or commit to competing third party proposals to acquire all or a significant part of VeraSun.

Moreover, under specified circumstances, VeraSun could be required to pay US BioEnergy a termination fee of $61 million in connection with the termination of the merger agreement. This termination fee could deter a third party from proposing an alternative to the merger.

VeraSun and US BioEnergy shareholders have no dissenters’ rights of appraisal.

Under the public company exception in Section 47-1A-1302 of the South Dakota Business Corporation Act, shareholders of VeraSun and US BioEnergy are not entitled to appraisal rights in connection with the merger. Accordingly, neither company’s shareholders have the right to seek a judicial determination for the fair value of those shares.

Sales of a substantial number of shares of VeraSun’s common stock after completion of the proposed merger could cause the price of VeraSun’s common stock to decline.

Under the terms of the shareholders agreements entered into concurrently with the merger agreement, for 180 days following the completion of the proposed merger, Donald L. Endres, in his capacity as a shareholder of VeraSun, and certain principal shareholders of US BioEnergy who will receive VeraSun common stock in the merger and who, together with Mr. Endres, in the aggregate will own a significant percentage of the common stock of VeraSun, will be limited in their ability to sell an amount of such shares equal to approximately 25% of the total number of shares of VeraSun common stock to be outstanding following the merger. However, upon the expiration of the 180 days, such shares will become eligible for sale. Sales of a substantial number of these shares in the public market, or the perception that these sales could occur, could cause the market price of VeraSun’s common stock to decline and could impair the ability of VeraSun shareholders to sell their shares of VeraSun common stock in the amounts and at such times and prices as they may desire. In addition, the sale of these shares could impair VeraSun’s ability to raise capital through the sale of additional equity securities.

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

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

 

   

our operating performance and the performance of our competitors;

 

   

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

 

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

 

   

variations in general economic conditions;

 

   

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

 

   

the number of shares that are publicly traded;

 

   

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

 

   

the arrival or departure of key personnel; and

 

   

other developments affecting us, our industry or our competitors.

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

 

ITEM 2. PROPERTIES

All facilities are 100% owned, use dry-milling technology and use natural gas as the primary energy source.

 

Location

   Year Completed
or schedule to
be completed
   Annual ethanol
capacity (in millions
of gallons) (a)

Albion, Nebraska (b)

   2007    110

Aurora, South Dakota

   2003    120

Bloomingburg, Ohio (b)

   2008    110

Charles City, Iowa

   2007    110

Fort Dodge, Iowa

   2005    110

Hartley, Iowa

   2008    110

Linden, Indiana (b)

   2007    110

Reynolds, Indiana (c)

   2009    110

Welcome, Minnesota

   2008    110
       
      1,000
       

 

(a) Estimated upon completion

 

(b) The Albion, Bloomingburg and Linden facilities are subject to mortgages securing the Senior Credit Facility. See Note 4 to the consolidated financial statements included elsewhere in this Form 10-K.

 

(c) We suspended construction of our Reynolds facility in October 2007 due to market conditions. We expect to resume construction at Reynolds in 2008, depending on the return of more favorable market conditions.

 

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.

 

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PART II

 

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

Market Information

Shares of VeraSun common stock are listed on the New York Stock Exchange under the symbol “VSE”. The following table shows, for the calendar quarters indicated, based on published financial sources, the high and low sales prices of shares of VeraSun common stock. VeraSun has not paid any dividends.

 

     High    Low

Year Ended December 31, 2006

     

Second Quarter

   $ 30.75    $ 24.10

Third Quarter

     28.10      15.87

Fourth Quarter

     25.88      15.08

Year Ended December 31, 2007

     

First Quarter

   $ 21.06    $ 15.12

Second Quarter

     21.47      12.90

Third Quarter

     16.93      10.41

Fourth Quarter

     17.75      9.60

On February 29, 2008, the closing price of our common stock was $9.04. As of February 29, 2008, there were approximately 363 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 February 29, 2008, there were 93,098,390 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 indentures underlying our 9 7/8% senior secured notes due 2012 and our 9 3/8% senior notes due 2017 limit, 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, 2007.

 

Plan Category

   Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights
(a)
   Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b)
   Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column a)
(c)

Equity compensation plans approved by security holders:

        

Stock Incentive Plan

   2,736,483    $ 11.00    3,975,741

Equity compensation plans not approved by security holders:

        

None

   —        —      —  
                

TOTAL

   2,736,483    $ 11.00    3,975,741
                

 

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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 as of June 14, 2006, our IPO date. The stock performance presented below covers the period from our IPO date through December 31, 2007; historical stock performance may not be indicative of future performance.

LOGO

 

     6/14/06    6/30/06    9/29/06    12/29/06    3/30/07    6/29/07    9/28/07    12/31/07

VeraSun Energy Corporation

   100.00    87.47    53.50    65.83    66.23    48.27    36.67    50.93

Russell 2000

   100.00    107.11    107.58    117.16    124.71    124.71    120.86    115.32

Peer Group*

   100.00    106.30    60.34    66.34    59.84    51.30    34.29    35.72

 

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

 

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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, 2005, 2004 and 2003 and the selected consolidated income statement data and other financial data for the years ended December 31, 2004 and 2003 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, 2007 and 2006 and the selected consolidated income statement data and other financial data for each of the years in the three year period ended December 31, 2007 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,  
     2007     2006     2005     2004     2003  
     (dollars in thousands, except per share data)  

Income Statement data: (1)

          

Net sales

   $ 844,327     $ 553,989     $ 235,440     $ 186,029     $ 10,884  

Other revenues, incentive income

     3,954       3,828       919       7,723       1,776  
                                        

Total revenues

     848,281       557,817       236,359       193,752       12,660  

Cost of goods sold

     752,382       365,139       200,823       154,022       8,450  
                                        

Gross profit

     95,899       192,678       35,536       39,730       4,210  

Selling, general and administrative expenses

     42,480       41,060       11,874       6,140       2,233  
                                        

Operating income

     53,419       151,618       23,662       33,590       1,977  
                                        

Other income (expense):

          

Interest expense (2)

     (33,376 )     (37,871 )     (7,609 )     (8,892 )     (839 )

Other interest expense, loss on extinguishment of debt

  

 

—  

 

 

 

—  

 

 

 

(15,744

)

 

 

—  

 

 

 

—  

 

Interest income

     16,855       13,618       448       182       11  

Other

     57       2,712       17       33       14  
                                        
     (16,464 )     (21,541 )     (22,888 )     (8,677 )     (814 )
                                        

Income before income taxes and minority interest

  

 

36,955

 

 

 

130,077

 

 

 

774

 

 

 

24,913

 

 

 

1,163

 

Income tax provision

     10,348       54,350       582       10,242       571  
                                        

Income before minority interest

     26,607       75,727       192       14,671       592  

Minority interest in net loss of subsidiary

     —         —         61       100       —    
                                        

Net income

   $ 26,607     $ 75,727     $ 253     $ 14,771     $ 592  
                                        

Per Share data:

          

Income per common share—basic

   $ 0.32     $ 1.09     $ 0.01     $ 0.40     $ 0.02  

Basic weighted average number of common shares

     82,659,352       69,328,436       44,810,490       36,738,191       30,380,082  

Income per common share—diluted

   $ 0.31     $ 1.03     $ 0.01     $ 0.39     $ 0.02  

Diluted weighted average number of common and common equivalent shares

     86,236,442       73,779,278       47,578,869       37,908,751       30,577,961  

Other financial data:

          

Working capital (deficit)

     227,653       384,067       61,551       9,779       (35,182 )

Capital expenditures (4)

     481,859       131,329       87,095       25,215       63,974  

Net cash provided by (used in) operating activities

     39,047       97,264       (2,515 )     20,858       (10,641 )

Net cash used in investing activities

     (676,884 )     (42,615 )     (212,049 )     (25,214 )     (63,974 )

Net cash provided by financing activities

     498,630       233,686       233,982       14,621       70,381  

Other non-GAAP financial performance data:

          

EBITDA (3)

   $ 90,359     $ 177,615     $ 29,880     $ 37,831     $ 2,350  

Operating data:

          

Ethanol sold (gallons)

     353,132,722       224,520,662       126,346,295       101,370,470       6,459,804  

Average gross price of ethanol sold (dollars per gallon) (5)

  

$

1.99

 

 

$

2.18

 

 

$

1.59

 

 

$

1.50

 

 

$

1.28

 

Average corn cost per bushel

     3.60       2.16       2.12       2.50       2.17  

Average natural gas cost per MMBTU

     7.16       8.39       9.12       6.16       —    

Average dry distillers grains price per ton

     104.81       86.04       87.00       111.00       —    

 

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     As of December 31,
     2007    2006    2005    2004    2003
     (dollars in thousands)

Balance sheet data:

              

Cash and cash equivalents

   $ 110,942    $ 318,049    $ 29,714    $ 10,296    $ 31

Restricted cash

     —        44,267      124,750      —        —  

Property and equipment, net

     1,251,612      301,720      179,683      106,753      76,882

Total assets

     1,863,506      794,497      405,129      150,328      96,479

Total debt (6)

     908,492      210,000      210,000      58,381      58,503

Total equity

     755,731      506,431      144,918      44,476      17,594

 

(1) Income statement data reflect the financial impact of operations of our Aurora facility, which commenced operations in December 2003, our Fort Dodge facility, which commenced operations in October 2005, our Charles City facility, which commenced operations in April 2007, our Linden facility, which commenced operations in August 2007, and our Albion facility, which commended operations in October 2007.

 

(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.

 

(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.

 

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

 

     Year Ended December 31,
     2007    2006    2005    2004    2003
     (dollars in thousands)

Net income

   $ 26,607    $ 75,727    $ 253    $ 14,771    $ 592

Depreciation and amortization

     20,028      9,667      5,692      3,926      348

Interest expense

     33,376      37,871      23,353      8,892      839

Income tax provision

     10,348      54,350      582      10,242      571
                                  

EBITDA

   $ 90,359    $ 177,615    $ 29,880    $ 37,831    $ 2,350
                                  

 

(4) 2007 capital expenditures and 2006 expenditures includes $44.3 million and $88.4 million, respectively, 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, 2007, 2006 and 2005 is shown before unaccreted discount of $3.0 million, $1.1 million and $1.3 million, respectively.

 

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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

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

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

We own and operate five of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 560 million gallons per year, or “MMGY.” As of March 4, 2008, our ethanol production capacity represented approximately 7.0% of the total ethanol production capacity in the U.S., according to the RFA.

Our facilities are designed to operate on a continuous basis and use current dry-milling technology, a production process that results in increased ethanol yield and reduced capital costs compared to wet-milling facilities. In addition to producing ethanol, we produce and sell wet and dry distillers grains as ethanol co-products, which serve to partially offset our corn costs. In 2007, we produced approximately 376.1 million gallons of fuel ethanol and 1.2 million tons of distillers grains.

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

Executive Summary

Highlights for 2007 are as follows:

 

   

Total revenues increased 52.1% or $290.5 million compared to 2006.

 

   

Net income per diluted common share decreased from $1.03 for 2006 to $0.31 for 2007.

 

   

We completed construction and began commercial operation of our facility in Charles City, Iowa in April 2007.

 

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We completed the ASA Acquisition in August 2007 and completed construction and began commercial operation of the Linden facility in August 2007 and of the Albion facility in October 2007.

 

   

We more than doubled our production capacity in 2007 with completion of our Charles City, Linden and Albion facilities.

 

   

We entered into an agreement to acquire US BioEnergy, which when completed will increase our production capacity to approximately 1.6 billion gallons per year.

Our financial results were primarily driven by a 57.3% increase in ethanol gallons sold and an 8.7% decrease in the net realized price per gallon for 2007 compared to 2006.

Components of Revenues and Expenses

Total revenues. Our primary source of revenue is the sale of products produced at our Aurora, South Dakota; Fort Dodge, Iowa; Charles City, Iowa, Linden, Indiana; and Albion, Nebraska facilities. Our principal sources of revenue are:

 

   

the sale of ethanol;

 

   

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

 

   

the sale of ethanol blended VE85™ fuel.

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

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

Startup expenses. Costs associated with the operation of a facility prior to the production and sale of ethanol are expensed as incurred. During 2007, we incurred startup expenses relating to the Charles City, Iowa; Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. During 2006, the startup expenses pertained to the Charles City, Iowa facility. During 2005, the start-up expenses pertained to the Fort Dodge, Iowa facility.

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

Other income (expense). Other income (expense) includes the interest on our long-term debt, the change in fair value of a put warrant in all years prior to 2007, and the amortization of the related fees to execute required financing agreements. We expect interest expense, net of interest capitalized as part of new plant construction, to increase significantly as a result of our issuance of additional debt May 2007 and debt assumed in connection with the ASA acquisition in August 2007.

 

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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:

 

    Years Ended December 31,     Three Months Ended December 31,  
    2007     2006     2005     2007     2006  
    (dollars in thousands)     (unaudited)     (unaudited)  
          (dollars in thousands)  

Total revenues

  $ 848,281     100.0 %   $ 557,817     100.0 %   $ 236,359     100.0 %   $ 312,347     100.0 %   $ 146,498   100.0 %

Cost of goods sold

    752,382     88.7       365,139     65.5       200,823     85.0       281,571     90.1       105,697   72.1  
                                                                   

Gross profit

    95,899     11.3       192,678     34.5       35,536     15.0       30,776     9.9       40,801   27.9  

Selling, general and administrative expenses

    42,480     5.0       41,060     7.4       11,874     5.0       11,012     3.5       7,454   5.1  
                                                                   

Operating income

    53,419     6.3       151,618     27.1       23,662     10.0       19,764     6.4       33,347   22.8  

Other income (expense), net

    (16,464 )   (1.9 )     (21,541 )   (3.9 )     (22,888 )   (9.7 )     (10,983 )   (3.5 )     1,325   0.9  
                                                                   

Income before income taxes and minority interest

    36,955     4.4       130,077     23.2       774     0.3       8,781     2.9       34,672   23.7  

Income tax provision

    10,348     1.2       54,350     9.7       582     0.2       4,791     1.5       13,233   9.0  
                                                                   

Income before minority interest

    26,607     3.2       75,727     13.5       192     0.1       3,990     1.4       21,439   14.7  

Minority interest in net loss (income) of subsidiary

    —       —         —       —         61     —         —       —         —     —    
                                                                   

Net income

  $ 26,607     3.2 %   $ 75,727     13.5 %   $ 253     0.1 %   $ 3,990     1.4 %   $ 21,439   14.7 %
                                                                   

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,
 
     2007    2006    2005     2007     2006  
     (in thousands, except per unit data)     (unaudited)  

Other financial data:

            

Net cash flows provided by (used in) operating activities

     39,047      97,264      (2,515 )     (34,599 )     (20,108 )

Other non-GAAP financial performance data:

            

EBITDA (2)

   $ 90,359    $ 177,615    $ 29,880     $ 31,118     $ 40,537  

Operating data:

            

Ethanol sold (gallons) (1)

     353,133      224,520      126,346       134,444       58,103  

Average gross price of ethanol sold per gallon

   $ 1.99    $ 2.18    $ 1.59     $ 1.87     $ 2.17  

Average corn cost per bushel

     3.60      2.16      2.12       3.61       2.52  

Average natural gas cost per MMBTU

     7.16      8.39      9.12       7.12       8.51  

Average dry distillers grains gross price per ton

     104.81      86.00      87.00       126.09       95.00  

 

(1)

Includes gallons produced and used in VE85 sales.

 

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

 

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Non-GAAP Financial Measures

We believe that earnings before interest expense, income tax provision (benefit), depreciation and amortization, or EBITDA, is useful to investors and management in evaluating our operating performance in relation to other companies in our industry because the calculation of EBITDA generally eliminates the effects of financings and income taxes, which items may vary for different companies for reasons unrelated to overall operating performance. EBITDA is a non-GAAP financial measure and has limitations as an analytical tool, and should not be considered in isolation or as a substitute for net income or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as a measure of liquidity. Some of the limitations of EBITDA are:

 

   

EBITDA does not reflect our cash used for capital expenditures;

 

   

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

 

   

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

 

   

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

 

   

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

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

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

 

     Year Ended December 31,    Three Months Ended
December 31,
     2007    2006    2005    2007    2006
     (in thousands)    (unaudited)    (unaudited)

Net income

   $ 26,607    $ 75,727    $ 253    $ 3,990    $ 21,439

Depreciation

     20,028      9,667      5,692      8,908      2,502

Interest expense

     33,376      37,871      23,353      13,429      3,363

Income tax provision

     10,348      54,350      582      4,791      13,233
                                  

EBITDA

   $ 90,359    $ 177,615    $ 29,880    $ 31,118    $ 40,537
                                  

Quarter Ended December 31, 2007 Compared to Quarter Ended December 31, 2006

Total revenues. Total revenues, which include revenues from the sale of ethanol, distillers grains and VE85™, increased by $165.8 million, or 113.2% for the three months ended December 31, 2007, to $312.3 million from $146.5 million for the three months ended December 31, 2006. The increase in total revenues was primarily the result of a 131.4% increase in ethanol volume sold, partially offset by a decrease in average ethanol prices of $0.30 per gallon, or 13.8%, compared to 2006. Ethanol production increased by 82.5 million gallons, or 138.4%, as a result of the added capacity from bringing the Charles City, Iowa facility on-line in April 2007, the Linden, Indiana facility on-line in August 2007, and the Albion, Nebraska facility on-line in October 2007.

Net sales from ethanol increased $125.6 million, or 99.8%, to $251.5 million for the three months ended December 31, 2007 from $125.9 million for the three months ended December 31, 2006. The impact of increased volume, primarily from the additional Charles City, Linden, and Albion capacity, was $165.4 million, partially offset by a $39.8 million reduction due to lower prices. The average price of ethanol sold was $1.87 per gallon for the three months ended December 31, 2007, compared to $2.17 per gallon for the three months ended December 31, 2006.

 

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There was no net gain from derivatives included in net sales for the three months ended December 31, 2007, compared to a net gain of $2.9 million for the three months ended December 31, 2006. See “Critical Accounting Policies and Estimates—Derivative instruments and hedging activities.”

Net sales from co-products increased $36.5 million, or 202.7%, to $54.6 million for the three months ended December 31, 2007 from $18.1 million for the three months ended December 31, 2006. The impact of increased volume from the additional Charles City, Linden, and Albion capacity was $26.4 million and the impact of higher prices was $10.1 million.

Net sales of VE85™, our branded E85 product, increased $3.0 million, or 166.0%, to $4.8 million for the three months ended December 31, 2007 from $1.8 million for the three months ended December 31, 2006, primarily due to an increase in the number of retail outlets selling our product.

Cost of goods sold and gross profit. Gross profit decreased $10.0 million to $30.8 million for the three months ended December 31, 2007 from $40.8 million for the three months ended December 31, 2006. The decrease in gross profit was primarily due to higher corn costs and lower ethanol prices, partially offset by an increase in ethanol volume produced in the 2007 period compared to the 2006 period.

Corn costs increased $119.0 million to $173.2 million for the three months ended December 31, 2007 from $54.2 million for the three months ended December 31, 2006. Corn costs represented 61.5% of our cost of goods sold before taking into account our co-product sales and 42.1% of our cost of goods sold after taking into account co-product sales for the 2007 period, compared to 51.3% of our cost of goods sold before taking into account our co-product sales and 34.2% of our cost of goods sold after taking into account co-product sales for the 2006 period.

The increase in total corn costs for the three months ended December 31, 2007 was driven by the $40.3 million impact of higher prices and the $78.7 million impact of increased volume from the additional production from our Charles City, Linden, and Albion facilities. 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.”

The net loss from derivatives included in cost of goods sold was $1.8 million for the three months ended December 31, 2007 compared to a net gain loss of $1.4 million for the three months ended December 31, 2006. The decrease was primarily due to the mark-to-market adjustment. We mark all exchange traded corn futures contracts to market through costs of goods sold.

Natural gas costs increased $13.8 million to $28.9 million for the three months ended December 31, 2007 from $15.1 million for the three months ended December 31, 2006, and accounted for 10.3% of our cost of goods sold for the three months ended December 31, 2007 compared to 14.3% of our cost of goods sold for the three months ended December 31, 2006. The increase in natural gas costs in for the three months ended December 31, 2007 was attributable to an increase in our production compared to the three months ended December 31, 2006, partially offset by a $1.39 or 16.3% decrease in natural gas prices per million British Thermal Units, or MMBTU, in 2007.

Transportation expense increased $14.9 million to $34.0 million for the three months ended December 31, 2007 from $19.1 million for the three months ended December 31, 2006, primarily due to additional volume of ethanol and co-products shipped, and increased rail rates for 2007. Transportation expense accounted for 12.1% of our cost of goods sold for the three months ended December 31, 2007 compared to 17.0% of our cost of goods sold for the three months ended December 31, 2006.

Other inputs, which includes chemicals, electricity and denaturant, increased $11.9 million to $18.3 million for the three months ended December 31, 2007 from $6.4 million for the three months ended December 31, 2006. The increase is primarily due to the increased volume from the additional Charles City, Linden, and Albion capacity that came on line in 2007.

 

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Labor and manufacturing overhead costs increased $13.0 million to $21.9 million for the three months ended December 31, 2007 from $8.9 million for the three months ended December 31, 2006. The increase was primarily due to additional production at our Charles City, Iowa, Linden, Indiana, and Albion, Nebraska facilities.

Startup expenses. Startup expenses increased $1.6 million to $1.7 million for the three months ended December 31, 2007 from $0.1 million for the three months ended December 31, 2006. The increase was due to the increase in the number of plants under construction or in development. In 2006, the Charles City, Iowa plant was starting up, while in 2007, the Hartley, Iowa, Welcome, Minnesota, Reynolds, Indiana, Albion, Nebraska, and the Bloomingburg, Ohio facilities were all under construction or in development.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.9 million to $9.3 million for the three months ended December 31, 2007 from $7.4 million for the three months ended December 31, 2006. The increase was primarily the result of a increased management and administrative costs in the 2007 period to support our growth strategy. Selling, general and administrative expenses were $0.07 per gallon shipped during the three months ended December 31, 2007, compared to $0.13 per gallon shipped during the three months ended December 31, 2006.

Other income (expense). Interest expense increased $10.0 million to $13.4 million for the three months ended December 31, 2007, compared to $3.4 million for the three months ended December 31, 2006. The increase is primarily due to the additional debt issued in 2008.

Interest income decreased $2.3 million to $2.4 million for the three months ended December 31, 2007, compared to $4.7 million for the three months ended December 31, 2006. The decrease was primarily attributable to a decrease in the funds available to be invested in interest bearing securities.

Income taxes. The income tax provision was $4.8 million and $13.2 million for the three months ended December 31, 2007 and 2006, respectively. The effective tax rate for 2007 was 28.0%, compared to 41.8% for 2006. The effective tax rate in 2007 was below the expected federal tax rate due to the tax exempt interest income earned during the year. The effective tax rate was higher in the 2006 period due to nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO. The 2007 effective tax rate increased from our third quarter estimate of 19.2% to 28.0% due to better than expected earnings in the fourth quarter, driven primarily by an increase in the selling price of ethanol, which caused tax exempt interest income to have less of an impact than previously expected.

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

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Total revenues. Total revenues, which include revenues from the sale of ethanol, distillers grains and VE85™, increased by $290.5 million, or 52.1%, to $848.3 million from $557.8 million. The increase in total revenues was primarily the result of a 57.3% increase in ethanol volume sold, partially offset by a decrease in average ethanol prices of $0.19 per gallon, or 8.7%, compared to 2006. Ethanol production increased by 152.8 million gallons, or 67.5%, as a result of the added capacity from bringing the Charles City, Iowa facility on-line in April 2007, the Linden, Indiana facility on-line in August 2007, and the Albion, Nebraska facility on-line in October 2007.

Net sales from ethanol increased $219.7 million, or 45.0%, to $707.7 million for 2007 from $488.0 million for 2006. The impact of increased volume, primarily from the additional Charles City, Linden, and Albion

 

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capacity, was $284.9 million, partially offset by a $65.3 million reduction due to lower prices. The average price of ethanol sold was $1.99 per gallon for 2007, compared to $2.18 per gallon for 2006.

The net gain from derivatives included in net sales was $1.2 million for 2007, compared to a net gain of $2.4 million for 2006. See “Critical Accounting Policies and Estimates—Derivative instruments and hedging activities.”

Net sales from co-products increased $63.7 million, or 109.3%, to $122.0 million for 2007 from $58.3 million for 2006. The impact of increased volume from the additional Charles City, Linden, and Albion capacity was $41.8 million and the impact of higher prices was $21.8 million.

Net sales of VE85™, our branded E85 product, increased $7.0 million, or 92.3%, to $14.6 million for 2007 from $7.6 million for 2006, primarily due to an increase in the number of retail outlets selling our product.

Cost of goods sold and gross profit. Gross profit decreased $96.8 million to $95.9 million for 2007 from $192.7 million for 2006. The decrease in gross profit was primarily due to higher corn costs and lower ethanol prices, partially offset by an increase in ethanol volume produced in the 2007 period compared to the 2006 period. Also included in cost of sales for 2007 was a $0.6 million impairment relating to a cancelled biodiesel project.

Corn costs increased $280.7 million to $454.2 million for 2007 from $173.5 million for 2006. Corn costs represented 60.4% of our cost of goods sold before taking into account our co-product sales and 44.2% of our cost of goods sold after taking into account co-product sales for 2007, compared to 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.

The increase in total corn costs for 2007 was driven by the $178.7 million impact of higher prices and the $101.9 million impact of increased volume from the additional production from our Charles City, Linden, and Albion facilities. 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.”

The net gain from derivatives included in cost of goods sold was $3.8 million for 2007 compared to a net loss of $3.9 million for 2006. The increase was primarily due to the mark-to-market adjustment. We mark all exchange traded corn futures contracts to market through costs of goods sold.

Natural gas costs increased $18.3 million to $76.5 million for 2007 from $58.2 million for 2006, and accounted for 10.2% of our cost of goods sold for 2007 compared to 15.9% of our cost of goods sold for 2006. The increase in natural gas costs in 2007 was attributable to an increase in our production compared to 2006, partially offset by a decrease in natural gas prices per million British Thermal Units, or MMBTU, in 2007.

Transportation expense increased $30.3 million to $88.8 million for 2007 from $58.5 million for 2006, primarily due to additional volume of ethanol and co-products shipped, and increased rail rates for 2007. Transportation expense accounted for 11.8% of our cost of goods sold for 2007 compared to 16.0% of our cost of goods sold for 2006.

Other inputs, which includes chemicals, electricity and denaturant, increased $19.6 million to $54.4 million from $34.8 million in 2006. The increase is primarily due to the increased volume from the additional Charles City, Linden, and Albion capacity that came on line in 2007.

Labor and manufacturing overhead costs increased $26.1 million to $58.4 million for 2007 from $32.3 million for 2006. The increase was primarily due to additional production at our Charles City, Iowa, Linden, Indiana, and Albion, Nebraska facilities. Also included in overhead was a $0.6 million impairment of assets related to a canceled biodiesel project.

 

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The net gain from derivatives included in cost of goods sold was $3.8 million for 2007, compared to a net loss of $3.9 million for 2006. The net gain related to corn derivatives was $5.7 million, partially offset by a loss of $1.9 million related to natural gas derivatives.

Startup expenses. Startup expenses increased $4.4 million to $5.0 million for 2007 from $0.6 million for 2006. The increase was due to the increase in the number of plants under construction or in development. In 2006, the Charles City, Iowa plant was starting up, while in 2007, the Hartley, Iowa, Welcome, Minnesota, Reynolds, Indiana, Albion, Nebraska, and the Bloomingburg, Ohio facilities were all under construction or in development.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $2.9 million to $37.5 million for 2007 from $40.4 million for 2006. The decrease was primarily the result of a decrease in stock compensation expense partially offset by increased management and administrative costs in the 2007 period to support our growth strategy. In 2006 we recorded $20.6 million of stock compensation expense due to the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO. In 2007, stock compensation expense was $5.7 million. Selling, general and administrative expenses were $0.11 per gallon shipped in 2007, compared to $0.18 per gallon shipped in 2006.

Other income (expense). Interest expense decreased $4.5 million to $33.4 million for 2007, compared to $37.9 million for 2006. Interest expense in the 2006 period included a charge of $19.7 million relating to a put warrant that was fully exercised in connection with our IPO.

Interest income increased $3.3 million to $16.9 million for 2007, compared to $13.6 million for 2006. The increase was primarily attributable to an increase in the funds available to be invested in interest bearing securities.

Income taxes. The income tax provision was $10.3 million and $54.4 million for 2007 and 2006, respectively. The effective tax rate for 2007 was 28.0%, compared to 41.8% for 2006. The effective tax rate in 2007 was below the expected federal tax rate due to the tax exempt interest income earned during the year. The effective tax rate was higher in the 2006 period due to nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO. The 2007 effective tax rate increased from our third quarter estimate of 19.2% to 28.0% due to better than expected earnings in the fourth quarter, driven primarily by an increase in the selling price of ethanol, which caused tax exempt interest income to have less of an impact than previously expected.

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

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

 

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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™ 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 $28.5 million to $40.4 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

 

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$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.

Liquidity and Capital Resources

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

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

 

     Years Ended December 31,     Three Months Ended
December 31,
 
     2007     2006     2005     2007     2006  
     (in thousands)     (unaudited)  

Net cash provided by (used in) operating activities

   $ 39,047     $ 97,264     $ (2,515 )   $ (34,599 )   $ (20,108 )

Net cash used in investing activities

     (676,884 )     (42,615 )     (212,049 )     (124,378 )     (26,196 )

Net cash provided by financing activities

     498,630       233,686       233,982       17,599       1,707  

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

Cash provided by operating activities was $39.0 million for 2007, compared to $97.3 million provided by operating activities for 2006. Our inventory increased $65.6 million during 2007, primarily because of the termination of our marketing relationship with Aventine. Under the Aventine relationship, ethanol was transferred to Aventine at our facilities so that our inventory of ethanol was limited to work in process and ethanol that had not been loaded into railcars at the facilities. Our inventory balances now include ethanol in transit to customers or terminals. The inventory impact of terminating the Aventine relationship was partially

 

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offset by our marketing relationship with Cargill at our Linden, Indiana; Albion, Nebraska; and Bloomingburg, Ohio facilities. Like the Aventine relationship, the Cargill relationship reduces our inventory requirements at those facilities as compared to our other facilities. As we add additional facilities, we expect that our total working capital requirements will increase. As December 31, 2007, we had total cash and cash equivalents of $110.9 million compared to $318.0 million at December 31, 2006.

As of December 31, 2007, we had short-term investments of $43.2 million. These short-term investments consisted of triple A rated auction rate securities issued by municipalities. Subsequent to December 31, 2007, we converted $40.2 million of these short-term investments to cash and cash equivalents with no losses incurred. As of February 29, 2008, the short-term investment balance was $3.0 million. We reclassified $67.9 million in auction rate securities in 2006 to conform with the 2007 presentation of cash and cash equivalents and short term investments.

Cash used in investing activities was $676.9 million for 2007 compared to cash used of $110.5 million in 2006. The increase primarily resulted from construction expenditures, the cash portion of the purchase price of the ASA Acquisition, and the acquisitions of other fixed assets in the 2007 period. During 2007, we spent $437.6 million for the purchase of property and equipment, in addition to $44.3 million spent from escrowed cash for the construction of our Charles City facility.

Cash provided by financing activities for 2007 was $498.6 million, compared to $233.7 million provided by financing activities for 2006. The 2006 period included debt issuance costs and net proceeds from our IPO. The 2007 period included proceeds from long-term debt and debt issuance costs.

As of December 31, 2007, we had total debt of $905.5 million, net of $3.0 million of unaccreted debt discount. In addition, we had $8.4 million of letters of credit issued but not drawn under our $30 million credit agreement, leaving $21.6 million of borrowing capacity under that agreement at December 31, 2007. The amount undrawn on the Senior Credit Facility was $34.1 million as of December 31, 2007. Our debt service requirements in 2008 are expected to be approximately $104.3 million, consisting of $16.5 million in principal payment and $87.8 million in interest.

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

 

   

our ability to generate cash flows from operations;

 

   

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

 

   

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

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

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

In 2008, we expect to make capital expenditures of between $75 million and $100 million in the first quarter, between $50 million and $75 million in the second quarter, and between $25 million and $50 million in each of the third and fourth quarters for the construction of our previously announced ethanol production

 

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facilities, the purchase and installation of corn oil extraction equipment, facility maintenance, terminal infrastructure, cellulosic ethanol projects, operational improvements and further development of possible ethanol facility sites. We intend to fund these capital expenditures through cash flows from operations, cash and cash equivalents, short-term investments and our credit agreements.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations

The following summarizes our contractual obligations as of December 31, 2007. Our obligations are likely to increase significantly as we enter into agreements in connection with the construction of our Hartley, Iowa, Welcome, Minnesota and Bloomingburg, Ohio facilities (in thousands).

 

Types of Obligations

  2008   2009   2010   2011   2012   Thereafter   Total

Long-term debt obligations (1)

  $ 101,354   $ 115,226   $ 112,897   $ 110,568   $ 318,236   $ 996,484   $ 1,754,765

Operating lease obligations

    29,269     30,220     30,205     30,205     26,695     92,693     239,287

Purchase obligations (2)

    9,142     8,820     8,433     8,460     8,410     46,618     89,883

Other purchase obligations (3)

    142,544     11,098     2,424     —       —       —       156,066
                                         

Total contractual obligations

  $ 282,309   $ 165,364   $ 153,959   $ 149,233   $ 353,341   $ 1,135,795   $ 2,240,001
                                         

 

(1) Amounts represent principal and interest payments due on the senior secured notes, Senior Credit agreement, capital leases, etc 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, 2007 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 about matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We consider an accounting estimate to be critical if:

 

   

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

 

   

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

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

Revenue recognition. Revenue from the production of ethanol and its co-products is recorded when title transfers to customers. Shipping and handling charges to customers are included in revenues. In accordance with our prior marketing agreement with Aventine, sales through March 31, 2007 were recorded when products were

 

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shipped from our production facilities, net of commissions retained by Aventine at the time payment was remitted. As of April 1, 2007, we commenced direct sales of our ethanol to customers. Our sales of ethanol are now generally recognized upon delivery to our customers, at terminals or other locations, rather than upon shipment from our plants, except for sales to Cargill from our plants at Linden, Indiana and Albion, Nebraska, where sales are recognized upon delivery to Cargill at the 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 SFAS No. 133, as amended, unless designated otherwise, and therefore are not marked to market in our financial statements. Forward contracts designated otherwise are marked to market.

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

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

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

 

   

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

 

   

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

 

   

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

If our estimates we use to calculate the fair value for employee stock options differ from actual results, we may be exposed to gains or losses that could be material. See Note 8 of our Consolidated Financial Statements.

 

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

 

     Years

Land improvements

   10-39

Buildings and improvements

   7-40

Machinery and equipment

  

• Railroad equipment (side track, locomotive and other)

   20-39

• Facility equipment (large tanks, fermenters and other equipment)

   20-39

• Other

   5-7

Office furniture and equipment

   3-10

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

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

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

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

LOGO

 

(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.

 

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We consider market risk to be the potential loss arising from adverse changes in market rates and prices. We are subject to significant market risk with respect to the price of ethanol, our principal product, and the price and availability of corn, the principal commodity used in our ethanol production process. In general, ethanol prices are influenced by the supply and demand for gasoline, the availability of substitutes and the effect of laws and regulations. Higher corn costs result in lower profit margins and, therefore, represent unfavorable market conditions. Historically, we have not been able to pass along increased corn costs to our ethanol customers. The availability and price of corn are subject to wide fluctuations due to unpredictable factors such as weather conditions during the corn growing season, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture and international supply and demand. Corn costs represented approximately 60.4% of our total cost of goods sold for 2007 compared to 47.5% for 2006. Over the ten-year period from 1998 through 2007, 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 $4.55 per bushel on December 31, 2007 with prices averaging $2.42 per bushel during this period. At February 29, 2008, the CBOT price per bushel of corn for March delivery was $5.46.

Corn prices increased significantly in the fourth quarter of 2006 and have remained in 2007 at substantially higher levels than in 2006. In 2007, CBOT corn prices have ranged from a low of $3.10 per bushel to a high of $4.55 per bushel, with prices averaging $3.73 per bushel, compared to CBOT corn prices in 2006 that ranged from a low of $2.05 per bushel to a high of $3.90 per bushel, with prices averaging $2.60 per bushel. These higher corn prices contributed to adverse comparisons in the year-over-year comparisons in our cost of goods sold, gross profit, operating income, net income and EBITDA.

We are also subject to market risk with respect to our supply of natural gas that is consumed in the ethanol production process and has been historically subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions and overall economic conditions. Natural gas costs represented 10.2% of our cost of goods sold for 2007 compared to 15.9% for 2006. The price fluctuation in natural gas prices over the seven-year period from 2000 through 2007, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBTU on September 26, 2001 to a high of $15.38 per MMBTU on December 23, 2005, averaging $6.03 per MMBTU during this period. At February 29, 2008, the NYMEX price of natural gas for April delivery was $9.37 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 2007. 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 2007) net of the corn and natural gas forward and futures contracts used to hedge our market risk with respect to our corn and natural gas requirements. The results of this analysis are set forth in the following table. Actual results may differ from these amounts due to various factors, including significant increases in the Company’s production capacity during 2008.

 

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

Ethanol

   353.1    gallons    10 %   $ (70.8 )

Corn

   126.1    bushels    10       (45.4 )

Natural gas

   10.7    MMBTU    10       (7.7 )

As of December 31, 2007, we did not have any quantities of corn or natural gas contracted forward on a fixed price basis.

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

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Report of Independent Registered Public Accounting Firm on the Consolidated Financial Statements

   53

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

   54

Consolidated balance sheets at December 31, 2007 and 2006

   55

Consolidated statements of income for each of the three years in the period ended December 31, 2007

   56

Consolidated statements of shareholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2007

   57

Consolidated statements of cash flows for each of the three years in the period ended December 31, 2007

   58

Notes to the consolidated financial statements

   59

 

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Report of Independent Registered Public Accounting Firm on the Consolidated Financial Statements

To the Board of Directors and Shareholders

VeraSun Energy Corporation

We have audited the consolidated balance sheets of VeraSun Energy Corporation and subsidiaries (Company) as of December 31, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule of the Company listed in Item 15(a). These financial statements and financial statement schedules 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 the 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 the Company as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As described in Note 1 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board (FASB) Statement No. 123(R) Share-Based Payment in 2006 and as described in Note 5, the Company adopted FASB Interpretation No. 48 Accounting for Uncertainties in Income Taxes in 2007.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 11, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

LOGO

Sioux Falls, South Dakota

March 11, 2008

 

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Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

To the Board of Directors and Shareholders

VeraSun Energy Corporation

We have audited VeraSun Energy Corporation and subsidiaries’ (Company) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

The Company acquired ASA OpCo Holdings, LLC and its subsidiaries (“ASA Holdings”), on August 17, 2007. Management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, ASA Holding’s internal control over financial reporting included in the consolidated financial statements of the Company for the period from date of acquisition (August 17, 2007) until December 31, 2007. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of ASA Holdings for the period from date of acquisition (August 17, 2007) until December 31, 2007.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006 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, 2007 and our report dated March 11 2008 expressed an unqualified opinion on those financial statements.

LOGO

Sioux Falls, South Dakota

March 11, 2008

 

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VERASUN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31, 2007 and 2006

 

     2007    2006  
     (dollars in thousands,
except per share data)
 

Assets

     

Current Assets

     

Cash and cash equivalents

   $ 110,942    $ 250,149  

Short-term investments

     43,175      67,900  

Trade receivables, less allowance for doubtful accounts of $95 and $65 in 2007 and 2006, respectively

     51,294      32,194  

Inventories

     107,912      39,049  

Prepaid expenses and other current assets

     63,597      34,542  

Derivative financial instruments

     12,627      12,382  
               

Total current assets

     389,547      436,216  
               

Restricted cash held in escrow

     —        44,267  

Debt issuance costs, net

     15,478      5,685  

Goodwill

     169,629      6,129  

Other intangible assets

     21,668      —    

Other long-term assets

     15,572      480  
               
     222,347      56,561  
               

Property and equipment, net

     1,251,612      301,720  
               
   $ 1,863,506    $ 794,497  
               

Liabilities and Shareholders’ Equity

     

Current Liabilities

     

Current maturities of long-term debt

   $ 16,774    $ —    

Current portion of deferred revenues

     95      96  

Accounts payable

     120,814      36,391  

Accrued expenses

     11,043      2,961  

Derivative financial instruments

     11,299      11,331  

Deferred income taxes

     1,869      1,370  
               

Total current liabilities

     161,894      52,149  
               

Long-term debt, less current maturities

     888,696      208,905  

Deferred revenues, less current portion

     1,519      1,613  

Deferred income taxes

     51,564      25,399  

Other long-term liabilities

     4,102      —    
               
     945,881      235,917  
               

Commitments and Contingencies (Note 10)

     

Shareholders’ Equity

     

Preferred stock, $0.01 par value; authorized 25,000,000 shares; none issued or outstanding

     —        —    

Common stock, $0.01 par value; authorized 250,000,000 shares; 92,948,664 and 75,463,640 shares issued and outstanding in 2007 and 2006, respectively

     929      755  

Additional paid-in capital

     638,606      417,049  

Retained earnings

     116,196      89,589  

Accumulated other comprehensive loss

     —        (962 )
               
     755,731      506,431  
               
   $ 1,863,506    $ 794,497  
               

See Notes to Consolidated Financial Statements.

 

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VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, 2007, 2006 and 2005

 

     2007     2006     2005  
     (dollars in thousands, except per share data)  

Revenues:

      

Net sales

   $ 844,327     $ 553,989     $ 235,440  

Other revenues, incentive income

     3,954       3,828       919  
                        

Total revenues

     848,281       557,817       236,359  
                        

Cost of goods sold:

      

Cost and expenses of production

     752,464       365,036       198,183  

Loss (gain) on disposal of equipment

     (82 )     103       2,640  
                        

Total cost of goods sold

     752,382       365,139       200,823  
                        

Gross profit

     95,899       192,678       35,536  

Startup expenses

     4,961       634       1,893  

Selling, general and administrative expenses

     37,519       40,426       9,981  
                        

Operating income

     53,419       151,618       23,662  
                        

Other income (expense):

      

Interest expense, including change in fair value of convertible put warrant of $19,670 in 2006 and $2,809 in 2005

     (33,376 )     (37,871 )     (7,609 )

Other interest expense, loss on extinguishment of debt

     —         —         (15,744 )

Interest income

     16,855       13,618       448  

Other income

     57       2,712       17  
                        
     (16,464 )     (21,541 )     (22,888 )
                        

Income before income taxes and minority interest

     36,955       130,077       774  

Income tax provision

     10,348       54,350       582  
                        

Income before minority interest

     26,607       75,727       192  

Minority interest in net loss of subsidiary

     —         —         61  
                        

Net income

   $ 26,607     $ 75,727     $ 253  
                        

Per Share data:

      

Income per common share—basic

   $ 0.32     $ 1.09     $ 0.01  

Basic weighted average number of common shares

     82,659,352       69,328,436       44,810,490  

Income per common share—diluted

   $ 0.31     $ 1.03     $ 0.01  

Diluted weighted average number of common and common equivalent shares

     86,236,442       73,779,278       47,578,869  

Pro forma amounts as if all subsidiaries were taxable for entire period (unaudited):

      

Pro forma income tax expense

   $ 10,348     $ 54,350     $ 1,839  

Pro forma net income (loss)

     26,607       75,727       (1,004 )

Pro forma income (loss) per common share:

      

Basic

   $ 0.32     $ 1.09     $ (0.02 )

Diluted

     0.31       1.03       (0.02 )

See Notes to Consolidated Financial Statements.

 

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VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

Years Ended December 31, 2007, 2006 and 2005

 

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

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

     —         1,106       —        —         —         1,106  

Amortization of deferred compensation

     —         —         —        36       —         36  

Comprehensive income:

             

Net income

     —         —         253      —         —      

Unrealized loss on hedging activities

     —         —         —        —         (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

     110       233,057       —        —         —         233,167  

Issuance of restricted stock

     3       —         —        —         —         3  

Stock-based compensation

     —         22,345       —        107       —         22,452  

Exercise of stock options and warrants

     17       351       —        —         —         368  

Excess tax benefits from share-based payment arrangements

     —         1,320       —        —         —         1,320  

Extinguishment of convertible put warrant liability

     —         27,128       —        —         —         27,128  

Comprehensive income:

             

Net income

     —         —         75,727      —         —      

Unrealized gain on hedging activities

     —         —         —        —         1,348    

Comprehensive income

     —         —         —        —         —         77,075  
                                               

Balance, December 31, 2006

     755       417,049       89,589      —         (962 )     506,431  

Issuance of 14,401,384 shares of common stock

     144       203,248       —        —         —         203,392  

Issuance of 102,239 shares restricted stock

     1       (1 )     —        —         —         —    

Restricted stock reacquired, 6,278 shares

     —         (123 )     —        —         —         (123 )

Forfeiture of 57,280 shares restricted stock

     (1 )     1       —        —         —         —    

Stock-based compensation

     —         5,733       —        —         —         5,733  

Exercise of stock options and warrants, 3,044,959 shares

     30       4,219       —        —         —         4,249  

Excess tax benefits from share-based payment arrangements

     —         8,480       —        —         —         8,480  

Comprehensive income:

             

Net income

     —         —         26,607      —         —      

Unrealized gain on hedging activities

     —         —         —        —         962    

Comprehensive income

     —         —         —        —         —         27,569  
                                               

Balance, December 31, 2007

   $ 929     $ 638,606     $ 116,196    $ —       $ —       $ 755,731  
                                               

See Notes to Consolidated Financial Statements.

 

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VERASUN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2007, 2006 and 2005

 

     2007     2006     2005  
     (dollars in thousands)  

Cash Flows from Operating Activities

      

Net income

   $ 26,607     $ 75,727     $ 253  

Adjustments to reconcile net income to net cash provided by (used in) operating activities:

      

Depreciation

     19,586       9,667       5,692  

Amortization

     2,427       1,141       325  

Accretion of deferred revenue

     (95 )     (96 )     (96 )

Minority interest in net loss of subsidiary

     —         —         (61 )

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  

Change in derivative financial instruments

     1,203       (3,402 )     615  

Deferred income taxes

     26,146       16,124       410  

(Gain) loss on disposal of equipment

     (82 )     103       2,640  

Stock-based compensation expense

     5,733       22,452       1,142  

Excess tax benefits from share-based payment arrangements

     (8,480 )     (1,320 )     —    

Change in other long-term liabilities

     1,395       —         —    

Changes in current assets and liabilities, net of affects of business acquisition:

      

(Increase) decrease in:

      

Receivables

     (19,100 )     (33,886 )     (13,915 )

Inventories

     (65,583 )     (19,758 )     (6,843 )

Prepaid expenses

     (28,640 )     424       (3,655 )

Increase (decrease) in:

      

Accounts payable

     72,344       9,448       5,020  

Accrued expenses

     5,586       970       762  
                        

Net cash provided by (used in) operating activities

     39,047       97,264       (2,515 )
                        

Cash Flows from Investing Activities

      

Payments for investments in short-term investments

     (617,471 )     (204,635 )     —    

Proceeds from the sale of short-term investments

     642,196       136,735       —    

Investment in restricted cash

     —         —         (125,000 )

Purchases of property and equipment

     (437,592 )     (42,973 )     (87,095 )

Payments for other long-term assets

     (14,961 )     (480 )     —    

ASA acquisition

     (249,068 )     —         —    

Proceeds from sales of equipment

     12       838       46  
                        

Net cash used in investing activities

     (676,884 )     (110,515 )     (212,049 )
                        

Cash Flows from Financing Activities

      

Proceeds from long-term debt

     497,480       —         208,711  

Principal payments on long-term debt

     —         —         (58,890 )

Net proceeds from the issuance of shares of common stock

     —         233,170       90,138  

Net proceeds from the issuance of stock options and warrants

     4,126       368       —    

Excess tax benefits from share-based payment arrangements

     8,480       1,320       —    

Debt issuance costs paid

     (11,456 )     (1,172 )     (5,977 )
                        

Net cash provided by financing activities

     498,630       233,686       233,982  
                        

Net increase (decrease) in cash and cash equivalents

     (139,207 )     220,435       19,418  

Cash and Cash Equivalents

      

Beginning

     250,149       29,714       10,296  
                        

Ending

   $ 110,942     $ 250,149     $ 29,714  
                        

See Note 13 for supplemental disclosures of cash flow information.

See Notes to Consolidated Financial Statements.

 

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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, 2007: VeraSun Aurora Corporation (“Aurora”), VeraSun Fort Dodge, LLC (“Fort Dodge”), VeraSun Charles City, LLC (“Charles City”), VeraSun Marketing, LLC (“Marketing”), VeraSun Hartley, LLC (“Hartley”), VeraSun Granite City, LLC (“Granite City”), VeraSun Reynolds, LLC (“Reynolds”), VeraSun Welcome, LLC (“Welcome”), VeraSun Litchfield, LLC (“Litchfield”), VeraSun Biodiesel, LLC (“Biodiesel”), ASA Albion, LLC (“Albion”), ASA OpCo Holdings, LLC (“OpCo”), ASA Linden, LLC (“Linden”), ASA Bloomingburg, LLC (“Bloomingburg”), VeraSun Tilton, LLC (“Tilton”), ASAB NewCo, LLC (“NewCo”), ASA Mount Vernon, LLC (“Mount Vernon”), ASA McLeansboro, LLC (“McLeansboro”), and ASA Tipton, LLC (“Tipton”). VeraSun Energy Corporation and its subsidiaries are collectively referred to as the “Company”.

The Company owns and operates five ethanol production facilities in the U.S., with a combined ethanol production capacity of 560 million gallons per year, or “MMGY.” The Company commenced operations at the facility in Aurora, South Dakota in December 2003, at the facility in Fort Dodge, Iowa in October 2005, at the facility in Charles City, Iowa in April 2007, at the facility in Linden, Indiana in August 2007, and at the facility in Albion, Nebraska in October 2007. Construction of the facilities in Hartley, Iowa; Welcome, Minnesota; and Bloomingburg, Ohio has commenced and the Company expects each of those facilities to begin production during the first six months of 2008. Upon completion of these facilities, the Company will have production capacity of 890 MMGY. The Company also broke ground for a facility in Reynolds, Indiana in April 2007. However, in October 2007 the Company suspended construction there because of market conditions. The Company expects to resume construction at Reynolds in 2008, depending on the return of more favorable market conditions, and bring the Company’s production capacity to one billion gallons per year by the end of 2009.

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

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

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

The Company has reclassified investments in auction rate securities held at December 31, 2006 to conform with the 2007 presentation of cash and cash equivalents and short term investments. As a result of this reclassification, December 31, 2006 cash and cash equivalents was reduced by, and short term investments were increased by, $67,900 and cash flows from investing activities for 2006 were decreased by the same amount. The gross purchases and sales of these short term investments have been included in cash flows from investing activities on the consolidated statement of cash flows. This reclassification had no impact on results of operations, cash flows from operations, earnings per share, total current assets, total assets, or shareholders’ equity.

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 (i) the reported amounts of assets and liabilities, (ii) the disclosure of contingent assets and liabilities at the date of the financial statements, and (iii) the reported amounts of revenues and expenses during the reporting period.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

The Company uses estimates and assumptions in accounting for the following significant matters, among others:

 

   

Allowances for doubtful accounts

 

   

Valuation of acquired assets

 

   

Inventory valuation and allowances

 

   

Fair value of derivative instruments and related hedged items

 

   

Useful lives of property and equipment and intangible assets

 

   

Asset retirement obligations

 

   

Long-lived asset impairments, including goodwill

 

   

Contingencies

 

   

Fair value of options and restricted stock granted under the Company’s stock-based compensation plans

 

   

Tax related items

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

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

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 $2,021, $981 and $1,037 in 2007, 2006 and 2005, respectively. Dried distillers grains with solubles (“DDGS”) sales are recorded net of commissions of $576, zero, and zero in 2007, 2006 and 2005, respectively.

At times, the Company enters into simultaneous ethanol purchase and sales commitments with third parties to lend or borrow ethanol at storage terminals. These transactions are done in contemplation of one another and generally settled on a non-cash basis with ethanol. The Company does not record revenue or costs of goods from such ethanol exchange transactions.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

The Company receives incentives to produce ethanol from state and federal entities. In accordance with the terms of these arrangements, incentive income is recognized when the Company produces ethanol or blends ethanol with gasoline to produce E85.

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

 

     2007    2006    2005

Net sales from external customers:

        

Ethanol

   $ 707,716    $ 488,049    $ 199,677

Distillers Grains

     121,981      58,332      34,966

E85

     14,630      7,608      755

Other

     —        —        42
                    
   $ 844,327    $ 553,989    $ 235,440
                    

The amount of foreign sales included in total revenues was $10,353, $6,446, and zero for the year ended December 31, 2007, 2006, and 2005, respectively.

Cost of goods sold. The Company’s cost of goods sold primarily includes cost of 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. Cost of goods sold also includes gains and losses from derivatives related to corn and natural gas.

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

Startup expenses: Costs associated with the operation of a facility prior to the production and sale of ethanol are expensed as incurred. During 2007 the Company incurred startup expenses relating to the Charles City, Iowa; Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. During 2006 the startup expenses pertained to the Charles City, Iowa facility. During 2005 the startup expenses pertained to the Fort Dodge, Iowa facility.

Taxes collected from customers: The Company is required to charge and collect sales and other taxes on sales to its customers and remit the taxes to government authorities. Amounts collected and remitted are recorded net on the consolidated balance sheet and excluded from the consolidated statement of income.

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, except cash restricted for the construction of property and equipment. Cash and cash equivalents are generally not federally insured. As of December 31, 2007, $27,138 was held by one commercial bank. Cash equivalents consist of variable rate demand notes, commercial paper and money market mutual funds among other short-term instruments.

Short-term Investments: Short-term investments consisted of triple A rated auction rate securities issued by municipalities. The Company considers short-term investments to be available-for-sale securities that are carried

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

at fair value, with any unrealized gains and losses, net of the related tax effect, to be reported as a separate component of shareholders’ equity. At December 31, 2007 and 2006, cost was equal to fair value for all such securities so there was no amount of unrealized gain or loss to be reported.

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 or market.

A summary of inventories at December 31 is as follows:

 

     2007    2006

Corn

   $ 27,637    $ 24,492

Supplies

     11,341      7,084

Chemicals

     2,743      1,214

Work in process

     7,859      2,489

Distillers grains

     2,133      431

Ethanol

     56,199      3,339
             
   $ 107,912    $ 39,049
             

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.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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.

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. The 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 and Fort Dodge operations were taxed as partnerships under the provisions of the Internal Revenue Code through September 30, 2005 and December 31, 2005, respectively. Under such provisions, their net income or loss was reported on the individual income tax returns of their members. Accordingly, no provision/benefit or asset/liability for income taxes has been reflected in these financial statements relative to the income or loss of VeraSun, LLC or Fort Dodge through those dates for interests in those activities held by members other than Aurora. VeraSun, LLC 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 Aurora.

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 $1,663, $955 and $278 during 2007, 2006 and 2005, respectively. Future amortization of debt issuance costs, based on debt outstanding as of December 31, 2007, is expected to be approximately $2,115 for each upcoming year until 2012 and approximately $1,165 for each year from 2012 until 2017. Debt issuance costs 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.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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.

Interest costs are capitalized during the period of construction and included in property, plant and equipment. Interest is capitalized until the project is substantially complete.

Construction in progress as of December 31, 2007 primarily relates to the Welcome, Hartley, Bloomingburg, and Reynolds facilities and will be depreciated upon the commencement of operations of the facilities.

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

 

     2007    2006

Land and land improvements

   $ 66,564    $ 17,229

Construction in progress

     899,323      117,217

Buildings and improvements

     5,438      4,072

Machinery and equipment

     314,947      179,855

Office furniture and equipment

     4,233      2,638
             
     1,290,505      321,011

Less accumulated depreciation

     38,893      19,291
             
   $ 1,251,612    $ 301,720
             

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

Goodwill: Goodwill represents the excess of the purchase price of an acquired entity over the fair value of 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 amount of those assets.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

Other intangible assets: Intangible assets with finite lives are carried at cost less accumulated amortization. The Company amortizes other intangible assets on a straight-line basis over estimated useful lives of 2 years for noncompete agreements and 20 years for vendor supply arrangements. See Note 2.

Other intangible assets as of December 31, 2007 include non-compete agreements with a gross carrying amount of $1,740 and accumulated amortization of $214, and vendor supply arrangements with a gross carrying amount of $20,370 and accumulated amortization of $228. Amortization expense was $442 for 2007.

Aggregate future intangible asset amortization expense is estimated to be as follows:

 

2008

   $ 1,902

2009

     1,599

2010

     1,019

2011

     1,019

2012

     1,019

Thereafter

     15,110
      

Total

   $ 21,668
      

Convertible put warrant: The value of the convertible warrant was adjusted to the formula-based put value in each period prior to exercise. 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 (See Note 15).

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.

Income per common share: Basic income per common share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted income per common share 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.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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

 

     Net
Income
   Weighted
Average
Shares
Outstanding
   Per
Share
Amount
 

2007:

        

Income per common share—basic

   $ 26,607    82,659,352    $ 0.32  

Effects of dilutive securities:

        

Exercise of stock options and warrants

     —      3,577,090      (0.01 )
                    

Income per common share—diluted

   $ 26,607    86,236,442    $ 0.31  
                    

2006:

        

Income per common share—basic

   $ 75,727    69,328,436    $ 1.09  

Effects of dilutive securities:

        

Exercise of stock options and warrants

     —      4,450,842      (0.06 )
                    

Income per common share—diluted

   $ 75,727    73,779,278    $ 1.03  
                    

2005:

        

Income per common share—basic

   $ 253    44,810,490    $ 0.01  

Effects of dilutive securities:

        

Exercise of stock options and warrants

     —      2,768,379      —    
                    

Income per common share—diluted

   $ 253    47,578,869    $ 0.01  
                    

Stock option awards outstanding for 1,420,329 and 1,426,640 shares of common stock at a weighted average exercise price of $22.84 and $23.04 were not included in diluted earnings per common share in 2007 and 2006, respectively, 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 year ended December 31, 2005, because the related performance conditions had not been met.

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: The Company accounts for share-based payments under 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 as of January 1, 2006, 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

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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 year ended December 31, 2005:

 

     Year Ended
December 31,
2005
 

Net income, as reported

   $ 253  

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  

Deduct proforma employee stock-based compensation expense determined under fair value based method for all awards, net of related tax effects

     (1,713 )
        

Pro forma net loss

   $ (706 )
        

Basic income (loss) per common share:

  

As reported

   $ 0.01  

Pro forma

     (0.02 )

Diluted income (loss) per common share:

  

As reported

     0.01  

Pro forma

     (0.02 )

Advertising costs: Advertising and promotion costs are expensed when incurred. Advertising costs during 2007, 2006 and 2005 were $1,275, $1,250 and $468, 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 $847, $657 and $217 for 2007, 2006 and 2005, respectively.

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 $110,942 and $250,149 at December 31, 2007 and 2006, respectively, which approximated fair values due to the relatively short maturity of these instruments.

Short-term investments: The carrying value of short-term investments was $43,175 and $67,900 at December 31, 2007 and 2006, respectively, which approximated fair values due to the variable rate of these investments.

Restricted cash held in escrow: The carrying value of restricted cash was $44,267 at December 31, 2006, which approximated fair value due to the relatively short maturity of the instrument.

Long-term debt: The carrying value and fair value of long-term debt were $905,470 and $845,358, respectively, at December 31, 2007. The carrying value and fair value of long-term debt were $208,905 and

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

$222,075, respectively, at December 31, 2006. The fair value of the Company’s long-term debt at December 31, 2007 and 2006 was estimated based generally on quoted market prices.

Derivatives: The carrying values of commodity derivatives were assets of $12,627 and liabilities of $11,299 at December 31, 2007 and assets of $12,382 and liabilities of $11,331 at December 31, 2006. These instruments are recorded at fair value on the accompanying balance sheets, with such fair value determined based on quoted market prices or estimated fair 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 or decision making group in deciding how to allocate resources and in assessing performance. In connection with the termination of the Company’s marketing arrangement with Aventine on March 31, 2007, the Company subsequently re-evaluated its operating segments based on the application of SFAS 131 and have identified one reportable business segment, the manufacture and marketing of fuel-grade ethanol and the co-products of the ethanol production process. The Company’s chief operating decision maker reviews financial information presented on a consolidated basis for purposes of assessing financial performance and making operating decisions. The chief operating decision maker also receives disaggregated information about certain operating expenses. Accordingly, the Company considers itself to be operating in a single industry segment. Previously, the Company had two reportable segments, ethanol production and other.

Concentration of business: In 2007, the Company acquired agreements with Cargill for the marketing, billing, receipt of payment and other administrative services for all of the ethanol and DDGS produced by the Linden, Albion and Bloomingburg facilities. The Company pays fees to Cargill based on the selling price. Sales to Cargill are recorded net of fees and were 14.3% of total sales during 2007. At December 31, 2007, $18,759 was due from Cargill and is included in accounts receivable in the accompanying balance sheet.

Prior to March 31, 2007, the Company had 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. Sales to Aventine represented 14.2%, 88.1% and 84.8% of total sales in fiscal 2007, 2006 and 2005, respectively. At December 31, 2007 and 2006, zero and $25,496, respectively, was due from Aventine and is included in receivables in the accompanying balance sheets.

Another customer accounted for 10.7% of total sales in fiscal 2007. No other customer accounted for more than 10.0% of total sales. Sales to the largest 10 customers represented approximately 76.6% of the Company’s total sales in fiscal year 2007 and 93.4% in fiscal year 2006 and 97.9% in fiscal year 2005.

Recently Issued Accounting Pronouncements

Fair Value Measurements

The FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The provisions of this statement are to generally be applied prospectively in the fiscal year beginning January 1, 2008. Other than the newly required disclosures, the Company does not expect the effects of adoption to be significant.

Fair Value Option

The FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FASB Statement No. 115.” This statement provides entities with the option to

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

measure eligible financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The provisions of this statement are effective as of the beginning of the first fiscal year beginning after November 15, 2007. Currently, the Company does not intend to apply the provisions of SFAS No. 159 to any of the Company’s existing financial assets or liabilities.

Business Combinations and Noncontrolling Interests

The FASB issued SFAS No. 141 (revised 2007), “Business Combinations.” This statement significantly changes the financial accounting and reporting of business combination transactions. The provisions of this statement are to be applied prospectively to business combination transactions in the first annual reporting period beginning on or after December 15, 2008.

The FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in subsidiaries. This statement requires the reporting of all noncontrolling interests as a separate component of stockholders’ equity, the reporting of consolidated net income (loss) as the amount attributable to both the parent and the noncontrolling interests and the separate disclosure of net income (loss) attributable to the parent and to the noncontrolling interests. In addition, this statement provides accounting and reporting guidance related to changes in noncontrolling ownership interests. Other than the reporting requirements described above which require retrospective application, the provisions of SFAS No. 160 are to be applied prospectively in the first annual reporting period beginning on or after December 15, 2008. The Company currently does not have any noncontrolling interests in subsidiaries.

Note 2. Acquisition

On August 17, 2007, the Company acquired all of the equity interests in ASA OpCo Holdings, LLC (“ASA Holdings”) from ASAlliances Biofuels, LLC for an aggregate purchase price of $683,997. Of this amount, the Company issued 13,801,384 shares of the Company’s common stock valued at $194,323, and paid $250,000 of cash to the seller at closing, and $6,310 for transaction fees and expenses. The balance of the purchase price consisted of $233,364 of indebtedness owed by ASA Holdings and its subsidiaries, ASA Albion, LLC, ASA Bloomingburg, LLC and ASA Linden, LLC, which remained outstanding after the closing under a Credit Agreement, dated February 6, 2006 among ASA Holdings, ASA Albion, LLC, ASA Bloomingburg, LLC and ASA Linden, LLC, as borrowers, and WestLB AG, New York branch, as administrative agent for the lenders and the lenders named therein (“Senior Credit Facility”). The Company also agreed to register under applicable securities laws, within 180 days of the acquisition date, the shares issued in the transaction. ASA Holdings owns companies with three biorefineries and developmental rights to two sites. This transaction is referred to in this document as the “ASA Acquisition”.

The three acquired facilities are each expected to operate at 110 million gallons per year and are located in Albion, Nebraska, Bloomingburg, Ohio, and Linden, Indiana. This transaction allowed the Company to expedite its expansion in the ethanol market as one plant was in operation and two plants were near completion. The Linden facility began operations in August 2007 and the Albion facility began startup operations in October 2007. The Bloomingburg facility is expected to start up by the end of first quarter 2008. The major factors that contributed to goodwill include the expected future profitability of the facilities which reflected the spreads between commodities prices for corn and ethanol prevailing at the time, the comparative ease of integrating a less mature business without management functions (which were not acquired), the geographic locations of the

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

facilities, and the significant contribution to VeraSun’s production capacity compared to pre-acquisition levels, which helped establish VeraSun’s strategic position as a consolidator in a highly fractured industry.

The acquired assets of the ASA Acquisition have been included in the consolidated balance sheet as of December 31, 2007 and the operations of ASA Holdings are included in the Company’s consolidated statement of operations beginning August 17, 2007.

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

The unaudited pro forma information below presents the results of operations of 2007 and 2006 as if the ASA Acquisition occurred at the beginning of each of the respective periods, after giving effect to certain adjustments (depreciation and amortization of tangible and intangible assets, to remove non-recurring expenses directly related to the acquisition, interest expense and amortization of deferred financing costs related to debt not assumed and the acquisition debt and the related income tax affects). The pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition been made at the beginning of each of the presented periods or of the results which may occur in the future.

 

     2007    2006

Total Revenues

   $ 848,281    $ 557,817

Net income

     11,200      57,600

Basic net income per share

     0.12      0.69

Diluted net income per share

     0.11      0.66

In accordance with SFAS No. 141 “Business Combinations,” the Company recorded this acquisition using the purchase method of accounting. The purchase price has been allocated to tangible and identifiable intangible assets acquired and liabilities assumed based on their respective fair values. The excess purchase price over the fair value of tangible and intangible assets acquired and liabilities assumed was recorded as goodwill, all of which will be deductible for tax purposes. Adjustments have been made to the preliminary allocation as reported as of September 30, 2007, primarily relating to finalizing the fair value of property, plant and equipment, establishing a value of identifiable intangibles (see Note 1), recording transaction costs associated with the transaction, and recording additional liabilities assumed. The adjustments had the impact of reducing goodwill by $28,956, increasing other intangible assets by $15,432, increasing property, plant and equipment by $22,188 and increasing current liabilities by $2,511. The following sets forth the allocation of the purchase consideration:

 

Current assets

   $ 10,877

Property, plant and equipment

     487,320

Goodwill

     163,500

Other intangible assets

     22,110

Other non-current assets

     190
      

Total assets acquired

     683,997
      

Current liabilities

     34,601

Non-current liabilities

     198,763
      

Total liabilities assumed

     233,364
      

Net assets acquired

   $ 450,633
      

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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

Note 3. Prepaid Expenses and Other Assets

A summary of prepaid expenses and other current assets at December 31 is as follows:

 

     2007    2006

Prepaid expenses

   $ 7,020    $ 4,187

Receivable from Broker

     15,186      15,390

Income tax receivable

     36,062      12,380

Other

     5,329      2,585
             
   $ 63,597    $ 34,542
             

Note 4. Long-Term Debt and Credit Facility

The following table summarizes the Company’s long-term debt as of December 31:

 

     2007     2006  

9 7/8% senior secured notes due 2012 (a)

   $ 210,000     $ 210,000  

9 3/8% senior notes due 2017 (a)

     450,000       —    

Senior credit facility (b)

     240,946       —    

Capital lease obligation (c)

     2,546       —    

Tax increment revenue note (d)

     5,000       —    
                

Total

     908,492       210,000  

Less unamortized discount

     (3,022 )     (1,095 )

Less current maturities of long-term debt

     (16,774 )     —    
                

Long-term debt

   $ 888,696     $ 208,905  
                

The schedule of principal payments for long-term debt, assuming the senior credit facility conversion from construction loans to term loans, at December 31, 2007 is as follows:

 

2008

   $ 16,774

2009

     16,703

2010

     16,734

2011

     16,767

2012

     226,802

Thereafter

     614,712
      

Total

   $ 908,492
      

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

(a) Senior Notes

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

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

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

Under the registration rights agreement that was executed in connection with the offering of the 2017 Notes, the Company agreed to: (a) cause an exchange offer of registered notes to be completed by May 15, 2008 and (b) file a shelf registration statement for the resale of the notes by May 15, 2008 if the Company cannot effect an exchange offer and in some other circumstances. If the Company has not effected the exchange offer for the 2017 Notes or caused a shelf registration statement with respect to resale of the notes to be declared effective by May 15, 2008, the annual interest rate will increase by 0.25% per annum and by an additional 0.25% for each subsequent 90-day period, up to a maximum of 1% per annum, until all registration defaults have been cured.

The Company amortized debt discount in the amount $322, $187, and $8 for the years ended December 31, 2007, 2006, and 2005, respectively.

(b) Senior Credit Facility

In connection with the ASA Acquisition, the Senior Credit Facility, as amended, remained in effect and provides for aggregate borrowings of up to $275,000 in two tranches: Tranche A for $175,000 and Tranche B for $100,000. Borrowings under the Senior Credit Facility must be used for the development, engineering, construction and operation of the Company’s Linden, Albion and Bloomingburg plants.

At December 31, 2007, the Company had borrowed $153,567 and $87,379 under the Senior Credit Facility in the form of Tranche A and Tranche B construction loans, respectively. The construction loans will be converted into term loans on March 15, 2008, and any remaining construction loan proceeds will be deposited in an account to fund construction costs. Amounts borrowed and repaid under the Senior Credit Facility may not be re-borrowed. The Company pays quarterly commitment fees of 0.5% per annum on the average daily unused

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

amount of the construction loan commitments under the Senior Credit Facility. The Company also pays agent fees of $125 per year.

Tranche A loans bear interest, at the Company’s option, at the administrative agent’s base rate (which is the higher of the federal funds effective rate and the administrative agent’s prime rate) plus 1.5% per annum or a Eurodollar rate based on LIBOR plus 2.5% per annum. Tranche B loans bear interest, at the Company’s option, at the administrative agent base rate plus 3.5% per annum or LIBOR plus 4.5% per annum. The average interest rate as of December 31, 2007 was 7.7% and 10.1% for Tranche A loans and Tranche B loans, respectively.

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

After the construction loans are converted into term loans, the Tranche A term loans would be payable in equal quarterly installments of principal of $2,625 and the Tranche B term loans would be payable in equal quarterly installments of principal of $1,500, plus accrued interest in accordance with the terms of the Senior Credit Facility, and would mature on the earlier of 78 months after the term loan conversion date or June 30, 2014.

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

The construction loans will convert to term loans on March 17, 2008. The credit agreement was amended effective March 7, 2008 to extend the date by which the Bloomingburg facility is required to be completed from March 15 to May 31, 2008, and to permit intercompany loans of up to $20 million to be made to each of ASA Linden. ASA Albion and ASA Bloomingburg entities.

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

The Senior Credit Facility contains customary events of default and also includes events of default for failure to complete the Bloomingburg plant by May 31, 2008; defaults on other indebtedness by ASA Holdings and its subsidiaries (including trade debt under certain conditions); and certain changes of control. The Senior Credit Facility also may become in default based on certain actions by Fagen, the design-builder of the Linden, Albion and Bloomingburg facilities, Cargill, and other third parties that provide goods and services to the facilities, including actions that are unrelated to the construction and operation of the facilities. In particular, the material breach by any such third parties of their agreements relating to the facilities, the failure of any such third parties to pay their indebtedness, including trade payables, and the entry of material judgments or the occurrence of an insolvency event with respect to any such third party would constitute an event of default under the Senior Credit Facility.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

(c) Capital lease obligation

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

The schedule of capital lease payments at December 31, 2007 is $274 annually through December 2027.

(d) Taxable tax increment revenue note

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

Interest on this note accrues at an initial rate of 8.5% per annum, which shall be adjusted on December 1, 2009, December 1, 2012, and December 1, 2015, to a rate equal to the lower of (1) the Three-Year United States Treasury Constant Maturity Index plus 425 basis points or (2) 10%. Interest is payable annually beginning on February 1, 2008.

The Note is subject to redemption in whole or in part prior to maturity at the option of the Company, on or after February 1, 2009, at a redemption price in varying amounts of up to 103% of the principal amount being redeemed, together with accrued interest.

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

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. In 2007 the agreement was amended to a $15,000 sublimit for letters of credit. Loan advances under the agreement have a borrowing base limitation based on a percentage of eligible receivables and outstanding inventory. As of December 31, 2007, funds of $30,000 were available to be drawn as computed under the borrowing base limitation, of which $8,361 in irrevocable stand-by letters of credit were outstanding, leaving a $21,639 remaining unused borrowing capacity. The agreement bears interest at LIBOR plus 250 basis points for a total rate of 7.33% as of December 31, 2007. The agreement has an expiration date of December 31, 2008, if not renewed, 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. 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, 2007 and 2006, no loans were outstanding under the agreement.

Note 5. Income Tax Matters

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), on January 1, 2007. Previously, the Company had accounted for tax contingencies in

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

accordance with SFAS No. 5, Accounting for Contingencies. As required by Interpretation 48, which clarifies SFAS No. 109, Accounting for Income Taxes, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting this standard, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. At the adoption date, the Company applied Interpretation 48 to all tax positions for which the statute of limitations remained open.

As a result of the implementation of FIN 48, the Company did not recognize a liability for unrecognized tax benefits as of January 1, 2007. During the year ended December 31, 2007, the Company recorded a liability for unrecognized tax benefits of approximately $1,352. A reconciliation of the beginning and ending amount of total unrecognized tax benefits is as follows:

 

Balance as January 1, 2007

   $ —  

Additions based on tax positions related to the current year

     832

Additions for tax positions of prior years

     520

Reductions for tax positions of prior years

     —  

Settlements

     —  
      

Balance at December 31, 2007

   $ 1,352
      

The majority of the liability for unrecognized tax benefits above relates to positions where only the timing of a deduction or revenue item is in question. Such liabilities are offset by deferred taxes and the only effect on the Company’s income statement relates to the interest accrued on such liabilities. The total liability associated with unrecognized tax benefits that, if recognized, would impact the effective tax rate was $158 at December 31, 2007. Based on current information, the Company anticipates that it is reasonably possible that the total unrecognized tax benefit will decrease within the next twelve months by a range of zero to $500.

The Company accrues interest related to unrecognized tax benefits in income tax expense. During the year ended December 31, 2007 the Company recognized approximately $44 in interest.

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

The Company is currently under examination by the Internal Revenue Service for tax year 2004 and the nine-month period ended September 30, 2005. The examination is expected to be completed by the end of 2008. As of December 31, 2007, the IRS has proposed certain adjustments to the Company’s 2004 and 2005 federal tax returns. Management is currently evaluating these proposed adjustments, but if accepted, the Company does not anticipate the adjustments would result in material changes to the Company’s financial position or results of operations.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

Net deferred tax liabilities consist of the following components as of December 31, 2007 and 2006:

 

     2007     2006  

Deferred tax assets:

    

Organizational expenses

   $ 1,881     $ 2,579  

Compensation expense

     3,993       6,196  

State credits and net operating losses

     11,794       —    

Accrued expenses

     861       —    

Tax increment financing

     589       —    

Federal tax credits

     2,506       —    

Other

     294       318  
                
     21,918       9,093  

Less: Valuation allowance

     (9,581 )     —    
                
     12,337       9,093  
                

Deferred tax liabilities:

    

Property and equipment

     (61,027 )     (34,061 )

Prepaid expenses

     (2,498 )     (1,111 )

Derivative financial instruments

     (499 )     (690 )

Amortization of goodwill for tax reporting

     (1,746 )     —    
                
     (65,770 )     (35,862 )
                

Net deferred tax liabilities

   $ (53,433 )   $ (26,769 )
                

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:

 

     2007     2006  

Current liabilities

   $ (1,869 )   $ (1,370 )

Noncurrent liabilities

     (51,564 )     (25,399 )
                
   $ (53,433 )   $ (26,769 )
                

Deferred tax assets include $2,017 relating to state net operating loss carryforwards. These carryforwards expire in varying amounts through 2027. Deferred tax assets relating to state credits expire in 2012 and 2014. Deferred tax assets for federal tax credits relate primarily to alternate minimum taxes and have no expiration.

A $9,581 valuation allowance has been recorded as of December 31, 2007, related to state tax credits. The Company cannot conclude that the Company will more likely than not generate sufficient taxable income in the applicable states to utilize the entire state tax credit carry forward prior to its expiration and, as a result, established the valuation allowance. The reversal of valuation allowance amounts, if ever recognized, would reduce future income tax expense.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

The provision for income taxes charged to operations for the years ended December 31, 2007, 2006 and 2005 consists of the following:

 

     2007     2006    2005

Current:

       

Federal

   $ (15,347 )   $ 37,526    $ 172

State

     (451 )     700      —  
                     
     (15,798 )     38,226      172
                     

Deferred:

       

Federal

     24,664       14,383      410

State

     1,482       1,741      —  
                     
     26,146       16,124      410
                     

Income tax provision

   $ 10,348     $ 54,350    $ 582
                     

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, 2007, 2006 and 2005, due to the following:

 

     2007     2006     2005  

Computed “expected” federal tax expense

   $ 12,934     $ 45,527     $ 271  

Increase (decrease) in income taxes resulting from:

      

Convertible put warrant

     —         7,180       983  

Stock-based compensation

     137       1,883       167  

State taxes, net of federal benefit

     1,168       1,541       —    

State tax credits, net of federal benefit

     (9,718 )     —         —    

Tax exempt interest

     (3,425 )     (684 )     —    

Domestic manufacturing deduction

     —         (1,175 )     —    

Federal tax credits

     (553 )     (131 )     —    

Change in valuation allowance for state tax credits

     9,581       —         —    

Effect of lower tax rates

     —         —         260  

Income from nontaxable subsidiaries, including the initial recognition of deferred taxes as of the dates of reorganization in 2005

     —         —         (1,257 )

Other, net

     224       209       158  
                        
   $ 10,348     $ 54,350     $ 582  
                        

Note 6. 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 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

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

related property and equipment. During 2007, 2006 and 2005, $95, $96 and $96, respectively, of amortization was included in the accompanying statements of income.

Note 7. 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 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, 2007, 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.

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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, 2007 and 2006 was zero and $962, respectively, net of tax, relating to derivative financial instruments. Hedging gains (losses) included in the statements of income consist of the following for the years ended December 31, 2007, 2006 and 2005:

 

     2007     2006     2005  

Undesignated

   $ 5,721     $ 4,959     $ 387  

Designated cash flow hedges

     (1,893 )     (7,879 )     (5,063 )

Ineffectiveness on cash flow hedges

     —         (943 )     (3,231 )
                        

Total amounts included in cost of goods sold

   $ 3,828     $ (3,863 )   $ (7,907 )
                        

Designated cash flow hedges included in net sales

   $ (1,237 )   $ 2,380     $ (3,862 )
                        

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.

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

 

     2007     2006     2005  

Unrealized holding (loss) arising during the year, net

   $ (1,651 )   $ (4,368 )   $ (12,341 )

Less reclassification adjustment for net gains (losses) realized in net income

     (3,131 )     (6,442 )     (12,251 )
                        

Net change in unrealized gain (loss) before income taxes

     1,480       2,074       (90 )

Income taxes benefit (expense)

     (518 )     (726 )     31  
                        

Other comprehensive income (loss)

   $ 962     $ 1,348     $ (59 )
                        

Note 8. 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

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

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. In addition, the members of the senior executive team were granted restricted stock awards which cliff vest on January 1, 2009 in accordance with an executive compensation structure approved by the Compensation Committee of the Board of Directors in 2007. As of December 31, 2007, there were 3,975,741 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 $5,733, $22,452 and $1,142 for the years ended December 31, 2007, 2006 and 2005, respectively, of which $5,677, $20,571 and $1,142, respectively, was charged to selling, general and administrative expenses and the remainder was charged to cost of goods sold. The total income tax benefit recognized in the consolidated statements of income for grants under the Plan was $219, $6,155 and $182 for the years ended December 31, 2007, 2006 and 2005, respectively. No compensation expense was capitalized during the three years ended December 31, 2007.

Net cash received from the exercise of options and awards under the Plan was $4,126, $368 and zero for the years ended December 31, 2007, 2006 and 2005, respectively. The Company recognized an excess tax benefit of $8,480 and $1,320 in connection with related exercises in 2007 and 2006, respectively and no significant tax benefits were recognized in 2005.

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.

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, 2007, considered collectively for the expected term of the award. The Company uses historical activity to estimate option exercise, forfeiture and employee termination assumptions within the valuation model. The expected

 

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VERASUN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except per share data)

 

terms of options granted are 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,
     2007    2006    2005

Expected volatility

   59%    58%    58%

Expected dividend yield

   None    None    None

Expected term

   8 – 10 years    8 – 10 years    8 – 10 years

Risk-free interest rate

   4.6% – 4.9%    4.5% – 5.1%    4.4%

The following table lists Service Award activity under the Plan for the year ended December 31, 2007:

 

Service Awards

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

Outstanding at January 1, 2007

   4,033,205     $ 9.33      

Granted

   54,378       16.85      

Forfeited

   (277,548 )     23.06      

Exercised

   (1,576,594 )     1.88