S-1 1 v18617s1sv1.htm FORM S-1 sv1
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As filed with the Securities and Exchange Commission on March 30, 2006
Registration No. 333-                    
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
VERASUN ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
         
South Dakota   2860   20-3430241
(State or other jurisdiction of incorporation or
organization)
  (Primary Standard Industrial Classification
Code Number)
  (I.R.S. Employer
Identification No.)
100 22nd Avenue
Brookings, South Dakota 57006
(605) 696-7200
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
DONALD L. ENDRES
Chief Executive Officer
VeraSun Energy Corporation
100 22nd Avenue
Brookings, South Dakota 57006
(605) 696-7200
(Name, address, including zip code, and telephone number, including area code, of agent for service)
It is respectfully requested that the Securities and Exchange Commission send copies of all notices, orders and communications to:
     
JOHN R. THOMAS
IAN G. MERRILL
PAUL M. TIGER
Stoel Rives LLP
900 SW Fifth Avenue, Suite 2600
Portland, Oregon 97204
(503) 224-3380
  JOHN J. SABL
DAVID S. BAKST
Sidley Austin LLP
One South Dearborn
Chicago, Illinois 60603
(312) 853-7437
 
     Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement becomes effective.
     If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box.    o
     If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
     If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
     If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
CALCULATION OF REGISTRATION FEE
               
               
               
Title of Each Class of     Proposed Maximum Aggregate        
Securities to be Registered     Offering Price(1)(2)     Amount of Registration Fee  
               
Common Stock, $0.01 par value per share
    $150,000,000     $16,050.00  
               
               
(1)  Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
 
(2)  Including shares of common stock which may be purchased by the underwriters to cover over-allotments, if any.
 
     The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the Registration Statement shall become effective on such a date as the Commission, acting pursuant to said Section 8(a), may determine.
 
 


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The information in this preliminary prospectus is not complete and may be changed. Neither we nor the selling shareholders may sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting offers to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS (Subject To Completion)
Issued                         , 2006
                                    Shares
(VERASUN ENERGY LOGO)
COMMON STOCK
 
VeraSun Energy Corporation and the selling shareholders are offering                      shares and                      shares, respectively, of common stock. We will not receive any proceeds from shares sold by the selling shareholders. This is our initial public offering, and no public market exists for our shares. We anticipate that the initial public offering price for our shares will be between $          and $           per share.
 
We have applied to list our common stock on the New York Stock Exchange under the symbol “VSE.”
 
Investing in our common stock involves risks. See “Risk Factors” beginning on page 10.
 
PRICE $               A SHARE
 
                                 
        Underwriting       Proceeds to
    Price to   Discounts and   Proceeds to   Selling
    Public   Commissions   VeraSun   Shareholders
                 
Per Share
       $            $            $            $    
Total
  $       $       $       $    
The selling shareholders have granted the underwriters the right to purchase up to an additional                      shares of common stock to cover over-allotments.
The Securities and Exchange Commission and state securities regulators have not approved or disapproved these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the shares of common stock to purchasers on                     , 2006.
 
MORGAN STANLEY LEHMAN BROTHERS
 
A.G. EDWARDS
                         , 2006


 

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 EXHIBIT 4.1
 EXHIBIT 4.2
 EXHIBIT 4.3
 EXHIBIT 4.4
 EXHIBIT 4.5
 EXHIBIT 21.1
 EXHIBIT 23.1
 EXHIBIT 23.3
 
      You should rely only on the information contained in this prospectus. We and the selling shareholders have not authorized anyone to provide you with information that is different. We and the selling shareholders are offering to sell and seeking offers to buy shares of our common stock only in jurisdictions where offers or sales are permitted. The information contained in this prospectus is accurate as of the date of this prospectus.
      Until                     , 2006 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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INDUSTRY AND MARKET DATA
      We obtained the industry, market and competitive position data used throughout this prospectus from our own research, internal surveys and studies conducted by third parties, independent industry associations or general publications and other publicly available information. In particular, we have based much of our discussion of the ethanol industry, including government regulation relevant to the industry and forecasted growth in demand, on information published by the Renewable Fuels Association, or RFA, the national trade association for the U.S. ethanol industry. Donald L. Endres, our Chief Executive Officer, is a member of the board of directors and executive committee member of the RFA. With respect to the E85 fuel industry, we have based our discussion on information published by the National Ethanol Vehicle Coalition, or NEVC. William L. Honnef, our Senior Vice President, Sales and Marketing, is a member of the board of directors of the NEVC. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. Further, because the RFA and NEVC are trade organizations for the ethanol industry, they may present information in a manner that is more favorable to that industry than would be presented by an independent source. Although we believe that these studies and publications are reliable, neither we nor the underwriters have independently verified this data and neither we nor the underwriters make any representation as to the accuracy of this information. Forecasts are particularly likely to be inaccurate, especially over long periods of time. Similarly, we believe our internal research is reliable, but it has not been verified by any independent sources.
 
FORWARD-LOOKING STATEMENTS
      This prospectus contains forward-looking statements. In particular, statements that we make under the headings “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Business” relating to our overall volume trends, industry forces, margin trends, anticipated capital expenditures and our strategies are forward-looking statements. When used in this prospectus, the words “will,” “could,” “should,” “target,” “potential,” “anticipate,” “estimate,” “expect,” “project,” “believe,” “plan,” “seek” and similar expressions are intended to identify forward-looking statements.
      These statements are based on assumptions and assessments made by our management in light of their experience and their perception of historical trends, current conditions, expected future developments and other factors they believe to be appropriate. Any forward-looking statements are not guarantees of our future performance and are subject to risks and uncertainties that could cause actual results, developments and business decisions to differ materially from those contemplated by any forward-looking statements. We disclaim any duty to update any forward-looking statements. Some of the factors that may cause actual results, developments and business decisions to differ materially from those contemplated by any forward-looking statements include the risks and uncertainties discussed under the heading “Risk Factors.”

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PROSPECTUS SUMMARY
      This summary highlights information contained elsewhere in this prospectus. This summary is not complete and does not contain all the information that may be important to you. You should carefully read the entire prospectus, especially the risks set forth under the heading “Risk Factors” and our financial statements and related notes included elsewhere in this prospectus, before making an investment decision. Unless the context requires otherwise, references in this prospectus to “VeraSun,” “we,” “us,” and “our” refer to VeraSun Energy Corporation and its subsidiaries.
VeraSun Energy Corporation
Overview
      VeraSun Energy Corporation is the second largest ethanol producer in the U.S. We are also the largest “pure-play” ethanol producer, focusing primarily on the production and sale of ethanol and its co-products. This focus has enabled us to significantly grow our ethanol production capacity and to work with automakers, fuel distributors, trade associations and consumers to increase the demand for ethanol. As an industry leader, we play an active role in developments within the renewable fuels industry.
      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. 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 20% from 2000 to 2005. We believe the ethanol market will continue to grow as a result of its favorable production economics relative to gasoline, ethanol’s clean burning characteristics, a shortage of domestic petroleum refining capacity, geopolitical concerns, and federally mandated renewable fuel usage. We also believe that E85, a fuel blend composed primarily of ethanol, will become increasingly important over time as an alternative to unleaded gasoline.
      We own and operate two of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 230 million gallons per year, or MMGY. As of January 1, 2006, our ethanol production capacity represented approximately 5% of the total ethanol production capacity in the U.S., according to the RFA. In addition to producing ethanol, we produce and sell wet and dry distillers grains as ethanol co-products, which serve to partially offset our corn costs. We expect to operate three facilities with an aggregate production capacity of 340 MMGY by the end of August 2007 and five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008.
      The table below provides an overview, as of March 2006, of our ethanol plants that are in operation, which we refer to as the Aurora Facility and the Fort Dodge Facility, respectively, or under construction in Charles City, Iowa, which we refer to as the Charles City Facility.
             
    Aurora Facility   Fort Dodge Facility   Charles City Facility(1)
             
Location
  Aurora, South Dakota   Fort Dodge, Iowa   Charles City, Iowa
Year completed or scheduled to be completed
  2003 (expansion 2005)(2)   2005   2007
Annual ethanol capacity (in millions of gallons)
  120   110   110(3)
Ownership
  100%   100%   100%
Production process
  Dry-Milling   Dry-Milling   Dry-Milling
Primary energy source
  Natural Gas   Natural Gas   Natural Gas
 
(1)  Construction of our Charles City Facility commenced in 2006 and is being funded primarily with $125.0 million of the net proceeds from the sale of senior secured notes in December 2005.
(2)  In June 2005, our Aurora Facility was expanded from a production capacity of 100 MMGY to 120 MMGY.
(3)  Estimated upon completion of construction of our Charles City Facility.

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     In addition, we plan to construct two 110 MMGY ethanol production facilities in Iowa and Minnesota, which we expect to be operational by the end of the first quarter of 2008. We refer to these additional production facilities as the Northwestern Iowa Facility and the Welcome Facility, respectively. We expect to commence construction of these facilities in the latter half of 2006 and to finance the construction costs with the net proceeds we receive from this offering and from our cash flow from operations. We intend to replicate our successful construction and production processes at these additional facilities.
      For the year ended December 31, 2005, our total revenues, EBITDA and net income were $236.4 million, $29.9 million and $253,000, respectively, reflecting a full year of operations at our Aurora Facility and less than three months of operations at our Fort Dodge Facility. For a reconciliation of net income to EBITDA, see footnote 3 under “—Summary Consolidated Financial and Operating Data.”
Recent Developments
  In February 2006, VeraSun and General Motors Corporation, or General Motors, announced a collaborative partnership to promote the awareness and use of E85 in flexible fuel vehicles, or FFVs, and the installation of VE85tm fuel pumps at 20 service stations in the Chicago area. In March 2006, we announced that we are adding VE85tm fuel pumps at 14 service stations in the Minneapolis area.
 
  In February 2006, Ford Motor Company, or Ford, announced the creation of a Midwest ethanol corridor through the planned conversion of fuel pumps to VE85tm in Illinois and Missouri. This plan is part of the initiative announced in November 2005 by Ford and VeraSun to raise awareness of the benefits of VE85tm and to expand the VE85tm distribution infrastructure.
 
  In February 2006, we acquired options to purchase approximately 440 acres of land near Hartley, Iowa and approximately 440 acres of land near Everly, Iowa as potential sites for the construction of our Northwestern Iowa Facility. In addition, the City of Welcome, Minnesota recently exercised options on our behalf to purchase land in Welcome for construction of our Welcome Facility.
 
  In March 2006, we commenced construction of our Charles City Facility, which is being funded primarily with a portion of the net proceeds from our issuance of senior secured notes in December 2005.
Ethanol Industry
      Ethanol is marketed across the U.S. as a gasoline blend component that serves as an octane enhancer, a clean air additive and a renewable fuel resource. It is used by refiners to meet clean air standards and to improve refinery production by increasing octane levels and extending fuel supplies. As of January 1, 2006, ethanol accounted for approximately 3% of the U.S. gasoline fuel supply.
      The U.S. fuel ethanol industry has grown significantly over the last few years, expanding production capacity at a compounded annual growth rate of approximately 20% from 2000 to 2005. Use of ethanol is expected to continue to grow as a result of the following factors:
  Favorable production economics relative to gasoline. Ethanol currently represents an economically attractive source of fuel. We believe that our cost of producing a gallon of ethanol currently is significantly lower than the cost incurred by refiners to produce a gallon of gasoline.
 
  Attractive performance characteristics. Ethanol has performance characteristics that are attractive to both petroleum refiners and consumers of gasoline, including a high octane level and reduced tailpipe emission levels.
 
  Strong legislative and government policy support. The Energy Policy Act of 2005, or the Energy Policy Act, mandates a baseline use of renewable fuels, such as ethanol, by petroleum producers commencing at 4.0 billion gallons per year, or BGY, in 2006 and increasing to 7.5 BGY by 2012. In addition, in January 2006, President Bush announced, in his State of the Union address, support for the use of ethanol in motor vehicles as a clean, renewable fuel to replace foreign crude oil and diversify the U.S. fuel supply.

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  Replacement of MTBE. In recent years, as a result of health and environmental concerns, 25 states have banned or significantly limited the use of methyl tertiary-butyl ether, or MTBE, and refiners are now expediting the phase-out of MTBE nationwide, creating a shortage of octane and clean blend components and additional demand for ethanol.
 
  Shortage of domestic petroleum refining capacity. According to the Energy Information Administration, or EIA, while domestic petroleum refining capacity has decreased approximately 5% from 1980 to 2005, domestic demand has increased 21% over the same period. The EIA expects growth in petroleum refining capacity to average 1.3% per year until 2025, with demand for refined petroleum products growing at 1.5% per year over the same period. Because ethanol is blended with gasoline after the refining process, it directly increases domestic fuel supplies. We believe that domestic fuel refining shortages will result in greater demand for ethanol.
Competitive Strengths
             Our competitive strengths include:
  Industry leadership. We have established a leadership position within the renewable fuels industry by being the first company to:
  —  develop new, large-scale 100 MMGY or greater dry-mill ethanol facilities in an industry primarily composed of smaller-scale, dry-mill facilities with capacities below 50 MMGY;
 
  —  design and site ethanol production facilities to strategically utilize trains with a large number of dedicated cars, such as unit trains, carrying our products, as a means of reducing transportation costs and delivery cycle times; and
 
  —  create the only branded E85 fuel, VE85tm, and enter into strategic relationships with major automakers to increase awareness and availability of E85.
        In addition, Donald L. Endres, our Chief Executive Officer and majority shareholder, serves on the board of directors and executive committee of the RFA and William L. Honnef, our Senior Vice President, Sales and Marketing, serves on the board of directors of the NEVC. We believe our involvement with these two leading ethanol trade organizations provides us with strategic insights into the industry.
  Low-cost operator. We believe our facilities provide us with an efficient cost structure for ethanol production. Our low-cost operations are the result of our:
  —  Strategic locations. Each of our facilities is located near abundant, low-cost corn supplies with direct or indirect access to multiple rail carriers, enabling us to reduce our delivery costs and access favorably-priced corn from other regions of the country;
 
  —  Modern technology. We use the latest production technology, resulting in lower operating costs and more efficient conversion of corn to ethanol than older plants that use older technology. We believe our efficient energy systems and heat recovery technology require relatively less energy than older dry-mill ethanol plants. In addition, we believe that our advanced computer control systems and process automation increase our facilities’ operating rate, energy efficiency and product quality.
 
  —  Scale of facilities. Our large facilities allow us to use unit trains to ship our finished ethanol product more efficiently and to store up to 30 days of corn in order to take advantage of attractive corn purchasing opportunities. Moreover, we have sufficient available land at our existing facilities to provide for possible future expansion;
 
  —  Substantial production capacity. Our current production capacity is 230 MMGY, which we intend to increase to 340 MMGY by the end of August 2007 and to 560 MMGY by the end of the first quarter of 2008. We believe our scale allows us to market and distribute our ethanol more efficiently and to manage our business more effectively than many other producers; and

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  —  Construction and development experience. Our expertise and involvement in constructing and developing low cost, large facilities allow us to complete new construction and expansion projects more efficiently than many of our smaller competitors, whom we believe are not as involved in the design and construction process and typically contract for more costly “turn-key” facilities.
  VE85™ branded ethanol fuel. We believe VeraSun’s branded VE85tm fuel gives us a significant advantage over our competitors in the market for E85. E85, a fuel blend composed of up to 85% ethanol, is used in FFVs. According to the NEVC, as of the end of the 2005 model year, 6.0 million FFVs capable of accepting VE85tm were in use in the U.S. We believe the number of FFVs will increase over the next several years. We recently entered into arrangements with Ford and General Motors to increase the number of VE85tm fuel pumps in various locations such as Chicago, Illinois and Minneapolis, Minnesota, which will enable us to expand our direct channel of branded fuel into the marketplace.
 
  Experienced and proven management team. Our management team, led by our chief executive officer and majority shareholder, Donald L. Endres, has extensive experience in the ethanol industry, and its core members have worked together successfully for over ten years. Our senior project management and operations executives, together with our two facility managers, have an average of over 20 years of experience in process operations in the ethanol, energy and chemical industries.
Business Strategy
        Our objective is to maintain our leading market position in the U.S. renewable fuels industry and to continue to realize efficiencies in ethanol production. Key elements of our strategy to achieve this objective include:
  Add low-cost production capacity. We intend to capitalize on the growing U.S. demand for ethanol by expanding our production capacity rapidly over the next several years. We are focused on the development and construction of our Charles City Facility, our Northwestern Iowa Facility and our Welcome Facility. In pursuing our expansion strategy, we seek to build on the success of our operating facilities, continue to build large-scale facilities, leverage proven facility design, incorporate technology improvements and continue to locate facilities with direct or indirect access to multiple rail carriers.
 
  Continue to focus on cost efficiency. We plan to continue to take advantage of our large production capacity and greater economies of scale to become more energy efficient and increase yield. We will also continue to use our on-site corn storage facilities to purchase corn during peak supply periods to reduce our corn costs. We intend to reduce our per-unit transportation costs by making greater use of unit trains to ship our finished ethanol and distillers grains products. We are also evaluating the benefits of expanding one or more of our existing facilities to take further advantage of economies of scale.
 
  Explore alternative technologies. We are studying the costs and feasibility of implementing biomass combustion systems at our facilities. These systems should allow us to reduce our energy costs by using biomass, such as switchgrass, straw, corn stover and other fibrous materials, as a substitute energy source in place of natural gas. Our research indicates that biomass combustion could potentially produce a majority of the energy needed to operate our facilities, thereby significantly reducing our reliance on natural gas. We are evaluating the capital costs and engineering challenges associated with implementation of biomass combustion.
 
  Expand market demand for ethanol. We plan to create additional demand for ethanol by continuing to work with refiners and blenders to introduce ethanol into new markets. We will also continue to pursue the development of partnerships to market VE85tm and expand the availability of VE85tm fuel with a variety of industry participants, including major automakers, such as those developed with Ford and General Motors; independent gasoline marketers; and other entities, such as the NEVC, the RFA, various corn grower groups, and state and federal agencies.

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  Continue to use price mitigation strategies. We seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn requirements on a fixed price basis and by purchasing corn and natural gas futures contracts. To mitigate ethanol price risk, we sell a portion of our production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract, such as unleaded gasoline on the New York Mercantile Exchange, or NYMEX, and we may hedge a portion of the price risk associated with index contracts by selling exchange-traded unleaded gasoline contracts. We believe our strategy of managing exposure to commodity price fluctuations will reduce somewhat the volatility of our results.
 
  Pursue potential acquisition opportunities. We believe that opportunities for expansion of our business through industry acquisitions will arise as the ethanol industry matures. We evaluate opportunities to acquire additional ethanol production, storage or distribution facilities and related infrastructure. In addition to operational production facilities, we may also seek to acquire potential facility sites under development.
Our Corporate Information
        Our corporate offices are located at 100 22nd Avenue, Brookings, South Dakota 57006. We were incorporated in South Dakota as the successor to a business organized in 2001. Our website address is http://www.verasun.com and our telephone number is 605-696-7200. Information on our website is not incorporated into this prospectus and should not be relied upon in determining whether to make an investment in our common stock. Our logo and other trademarks mentioned in this prospectus are the property of their respective owners.

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THE OFFERING
                           
Common stock offered by us                  shares                  
 
Common stock offered by selling shareholders                  shares                  
                     
 
  Total                  shares                  
                     
 
Common stock to be outstanding immediately after this offering                  shares                  
 
Over-allotment option offered by the selling shareholders                  shares                  
     
 
Use of proceeds   We intend to use the net proceeds to us from this offering, estimated at $      million, together with cash generated from operations, to finance the construction of our Northwestern Iowa Facility and our Welcome Facility at an estimated aggregate cost of $280.0 million and, possibly, for other general corporate purposes. We will not receive any proceeds from the sale of shares by the selling shareholders. See “Use of Proceeds.”
 
Risk factors   You should read the “Risk Factors” section of this prospectus for a discussion of factors that you should consider carefully before deciding to invest in shares of our common stock.
 
Proposed New York Stock Exchange symbol   “VSE”
      The number of shares of common stock that will be outstanding after this offering is based on 62,492,722 shares outstanding at December 31, 2005, and excludes:
  shares of common stock issuable upon the exercise of options and warrants outstanding at December 31, 2005 at a weighted average exercise price of $1.10 per share; and
 
  shares of common stock reserved for future issuance under our stock incentive plan.
      Except as otherwise indicated, all information in this prospectus assumes:
  no exercise of outstanding options or warrants after December 31, 2005, and
 
  no exercise of the underwriters’ option to purchase up to an additional                      shares of common stock from the selling shareholders to cover over-allotments.

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SUMMARY CONSOLIDATED FINANCIAL AND OPERATING DATA
      The following table presents summary consolidated financial and operating data as of the dates and for the periods indicated. The summary consolidated balance sheet financial data as of December 31, 2003 have been derived from our audited consolidated financial statements that are not included in this prospectus. The summary consolidated balance sheet financial data as of December 31, 2004 and 2005 and the summary consolidated income statement data for each of the three years in the period ended December 31, 2005 have been derived from the audited consolidated financial statements included elsewhere in this prospectus. You should read the information contained in this table in conjunction with the “Selected Consolidated Financial and Operating Data,” “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 prospectus.
                             
    Year Ended December 31,
     
    2003   2004   2005
             
    (dollars in thousands, except per share
    data)
Income statement data:(1)
                       
Net sales
  $ 10,884     $ 186,029     $ 235,440  
Other revenues, incentive income
    1,776       7,723       919  
                   
Total revenues
    12,660       193,752       236,359  
Cost of goods sold
    8,450       154,022       200,823  
                   
Gross profit
    4,210       39,730       35,536  
Selling, general and administrative expenses
    2,233       6,140       11,874  
                   
Operating income
    1,977       33,590       23,662  
                   
Other income (expense):
                       
 
Interest expense(2)
    (839 )     (8,892 )     (7,609 )
 
Other interest expense, loss on extinguishment of debt
                (15,744 )
 
Interest income
    11       182       448  
 
Other income
    14       33       17  
                   
      (814 )     (8,677 )     (22,888 )
                   
 
Income before income taxes and minority interest
    1,163       24,913       774  
Income taxes
    571       10,242       582  
                   
Income before minority interest
    592       14,671       192  
Minority interest in net loss of subsidiary
          100       61  
                   
 
Net income
  $ 592     $ 14,771     $ 253  
                   
Earnings per common share
                       
   
Basic
  $ 0.02     $ 0.40     $ 0.01  
   
Diluted
    0.02       0.39       0.01  
Shares used in per common share calculations
                       
   
Basic
    30,380,082       36,738,191       44,810,490  
   
Diluted
    30,577,961       37,908,751       47,578,869  
 
Other financial data:
                       
EBITDA(3)
  $ 2,350     $ 37,831     $ 29,880  
Certain items included in EBITDA(4)
    1       951       7,416  
Working capital (deficit)
    (35,182 )     9,779       61,551  
Capital expenditures
    63,974       25,215       87,095  
Net cash provided by (used in) operating activities
    (10,641 )     20,858       (2,515 )
Net cash used in investing activities
    (63,974 )     (25,214 )     (212,049 )
Net cash provided by financing activities
    70,381       14,621       233,982  
 
Operating data:
                       
Ethanol sold (gallons)
    6,459,804       101,370,470       126,346,295  
Average gross price of ethanol sold (dollars per gallon)(5)
  $ 1.28     $ 1.50     $ 1.59  
Total corn cost
    7,172       89,677       99,434  
Total natural gas cost
    452       19,115       37,067  

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    As of December 31,
     
    Actual   As Adjusted
         
    2003   2004   2005   2005(6)
                 
    (in thousands)
Balance Sheet Data:
                               
Cash and cash equivalents
  $ 31     $ 10,296     $ 29,714     $    
Restricted cash
                124,750       124,750  
Property and equipment, net
    76,882       106,753       179,683       179,683  
Total assets
    96,479       150,328       405,129          
Total debt(7)
    58,503       58,381       210,000       210,000  
Total equity
    17,594       44,476       144,918          
 
(1)  Income statement data reflects the financial impact of operations of our Aurora Facility, which commenced operations in December 2003, and our Fort Dodge Facility, which commenced operations in October 2005.
 
(2)  Interest expense includes changes in the fair value of a put warrant of $566 for the year ended December 31, 2003, $3,481 for the year ended December 31, 2004, and $2,809 for the year ended December 31, 2005. The put warrant is described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Summary of Critical Accounting Policies and Estimates — Put warrant.”
 
(3)  EBITDA is defined as earnings before interest expense, income tax expense, depreciation and amortization. Amortization of debt issuance costs and debt discount are included in interest expense. EBITDA is not a measure of financial performance under accounting principles generally accepted in the U.S., or GAAP, and should not be considered an alternative to net income, or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity. EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. Some of the limitations of EBITDA are:
  EBITDA does not reflect our cash used for capital expenditures;
 
  Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA does not reflect the cash requirements for replacements;
 
  EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;
 
  EBITDA does not reflect the cash necessary to make payments of interest or principal on our indebtedness; and
 
  EBITDA includes non-recurring payments to us which are reflected in other income.
  Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to us to service our debt or to invest in the growth of our business. We compensate for these limitations by relying on our GAAP results as well as on our EBITDA. Management uses EBITDA as a measure of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.
 
  The following table reconciles our EBITDA to net income for each period presented:
                         
    Year Ended December 31,
     
    2003   2004   2005
             
    (in thousands)
Net income
  $ 592     $ 14,771     $ 253  
Depreciation
    348       3,926       5,692  
Interest expense
    839       8,892       23,353  
Income taxes
    571       10,242       582  
                   
EBITDA
  $ 2,350     $ 37,831     $ 29,880  
                   

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(4)  The following table shows certain items that are included in EBITDA associated with our earnings. We believe that the table, when reviewed in connection with our presentation of EBITDA, provides another useful tool to our management and investors for measuring comparative operating performance between time periods and among companies. In addition to EBITDA, our management assesses the adjustments presented in this table when preparing our annual operating budget and financial projections. EBITDA, as defined above, was reduced by the following items:
                           
    Year Ended December 31,
     
    2003   2004   2005
             
    (in thousands)
Loss attributable to VeraSun Fort Dodge, LLC, or VFD, excluding interest and depreciation*
  $ 1     $ 951     $ 4,776  
Loss on disposal of a thermal oxidizer system
                2,640  
                   
 
Total
  $ 1     $ 951     $ 7,416  
                   
Net loss incurred prior to commencement of operations of VFD in October 2005.
(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)  Adjusted to give effect to the issuance of shares of common stock in this offering at an assumed price of $         per share, estimated underwriting discounts and commissions and estimated offering expenses payable by us. Also adjusted for the expected reclassification of the long-term liability associated with the put warrant to shareholders’ equity, and for the estimated stock-based compensation expense to be recorded upon vesting of certain options and warrants upon completion of this offering. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Summary of Critical Accounting Policies and Estimates — Put warrant.”
 
(7)  Total debt at December 31, 2005 is shown before unaccreted discount of $1.3 million.

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RISK FACTORS
      An investment in our common stock involves risks. You should carefully consider the risks described below as well as the other information contained in this prospectus before investing in our common stock. The risks and uncertainties described below are not the only ones we may face. The following risks, together with additional risks and uncertainties not currently known to us or that we may currently deem immaterial, could impair our financial position and results of operations. The market price of our common stock could decline if one or more of these risks and uncertainties develop into actual events.
Risks Relating to Our Business
Our results of operations, financial position and business outlook are highly dependent on commodity prices, which are subject to significant volatility and uncertainty, and the availability of supplies, so our results could fluctuate substantially.
      Our results are substantially dependent on commodity prices, especially prices for corn, natural gas, ethanol and unleaded gasoline. As a result of the volatility of the prices for these items, our results may fluctuate substantially and we may experience periods of declining prices for our products and increasing costs for our raw materials, which could result in operating losses. Although we may attempt to offset a portion of the effects of fluctuations in prices by entering into forward contracts to supply ethanol or purchase corn, natural gas or other items or by engaging in transactions involving exchange-traded futures contracts, the amount and duration of these hedging and other price mitigation activities may vary substantially over time and these activities also involve substantial risks. See “—We engage in hedging transactions and other price mitigation strategies that could harm our results.”
      Our business is highly sensitive to corn prices and we generally cannot pass on increases in corn prices to our customers. The principal raw material we use to produce ethanol and co-products, including dry and wet distillers grains, is corn. As a result, changes in the price of corn can significantly affect our business. In general, rising corn prices produce lower profit margins. Because ethanol competes with non-corn-based fuels, we generally are unable to pass along increased corn costs to our customers. At certain levels, corn prices may make ethanol uneconomical to use in fuel markets. Corn costs for the year ended December 31, 2005 constituted approximately 49.5% of our total cost of goods sold. Over the ten-year period from 1996 through 2005, corn prices (based on the Chicago Board of Trade, or CBOT, daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $5.48 per bushel in 1996, with prices averaging $2.47 per bushel during this period. At December 30, 2005, the CBOT price per bushel of corn was $2.16.
      The price of corn is influenced by weather conditions and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors. These factors include government policies and subsidies with respect to agriculture and international trade, and global and local demand and supply. The significance and relative effect of these factors on the price of corn is difficult to predict. Any event that tends to negatively affect the supply of corn, such as adverse weather or crop disease, could increase corn prices and potentially harm our business. In addition, we may also have difficulty, from time to time, in physically sourcing corn on economical terms due to supply shortages. Such a shortage could require us to suspend operations until corn is available at economical terms, which would have a material adverse effect on our business, results of operations and financial position. The price we pay for corn at a facility could increase if an additional ethanol production facility is built in the same general vicinity.
      The spread between ethanol and corn prices can vary significantly and we do not expect the spread to remain at recent high levels. Our gross margin depends principally on the spread between ethanol and corn prices. During the five-year period from 2001 to 2005, ethanol prices (based on average U.S. ethanol rack prices from Bloomberg, L.P., or Bloomberg) have ranged from a low of $0.94 per gallon to a high of $2.76 per gallon, averaging $1.50 per gallon during this period. In recent periods, the spread between ethanol and corn prices has been at an historically high level, driven in large part by high oil prices and historically low corn prices. During 2005, however, this spread fluctuated widely and we do not provide any assurance that fluctuations will not continue to occur. Any reduction in the spread between ethanol and corn prices, whether

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as a result of an increase in corn prices or a reduction in ethanol prices, would adversely affect our results of operations and financial position.
      The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we use in our manufacturing process. We rely upon third parties for our supply of natural gas, which is consumed in the manufacture of ethanol. The prices for and availability of natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices resulting from colder than average weather conditions and overall economic conditions. Significant disruptions in the supply of natural gas could impair our ability to manufacture ethanol for our customers. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial position. Natural gas represented approximately 18.5% of our cost of goods sold in 2005. The price fluctuations in natural gas prices over the six-year period from December 31, 1999 through December 28, 2005, based on the NYMEX daily futures data, has ranged from a low of $2.34 per MMBTU in 2000 to a high of $13.91 per MMBTU in 2005, averaging $5.25 per MMBTU during this period. At December 30, 2005, the NYMEX price of natural gas was $11.23 per MMBTU.
      Fluctuations in the selling price and production cost of gasoline may reduce our profit margins. Ethanol is marketed both as a fuel additive to reduce vehicle emissions from gasoline and as an octane enhancer to improve the octane rating of gasoline with which it is blended. As a result, ethanol prices are influenced by the supply and demand for gasoline and our results of operations and financial position may be materially adversely affected if gasoline demand or price decreases. In addition, some of our sales contracts provide for pricing on an indexed basis, so that the price we receive for products sold under these arrangements is adjusted as gasoline prices change.
We engage in hedging transactions and other price mitigation strategies that could harm our results.
      In an attempt to partially offset the effects of volatility of ethanol prices and corn and natural gas costs, we enter into contracts to supply a portion of our ethanol production or purchase a portion of our corn or natural gas requirements on a forward basis and also engage in other hedging transactions involving exchange-traded futures contracts for corn, natural gas and unleaded gasoline from time to time. The price of unleaded gasoline also affects the price we receive for our ethanol under indexed contracts. The financial statement impact of these activities is dependent upon, among other things, the prices involved and our ability to sell sufficient products to use all of the corn and natural gas for which we have futures contracts. Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. A hedge position is often settled in the same time frame as the physical commodity is either purchased (corn and natural gas) or sold (ethanol). Hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol. We do not assure you that we will not experience hedging losses in the future. We also vary the amount of hedging or other price mitigation strategies we undertake, and we may choose not to engage in hedging transactions at all. As a result, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol or unleaded gasoline.
We are substantially dependent on two facilities, and any operational disruption could result in a reduction of our sales volumes and could cause us to incur substantial losses.
      Most of our revenues are and will continue to be derived from the sale of ethanol and the related co-products that we produce at our facilities. Our operations may be subject to significant interruption if any of our facilities experiences a major accident or is damaged by severe weather or other natural disasters. In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other operational hazards inherent in our industry. 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

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suspension of operations and the imposition of civil or criminal penalties. We do not provide any assurance that our insurance will be adequate to fully cover the potential operational hazards described above or that we will be able to renew this insurance on commercially reasonable terms or at all.
We give no assurance that we will be able to implement our expansion strategy as planned or at all.
      We plan to grow our business by investing in new or existing facilities and to pursue other business opportunities, such as marketing VE85tm and other ethanol-blended fuel. We believe that there is increasing competition for suitable sites. There is no assurance that we will find suitable additional sites for construction of new facilities or other suitable expansion opportunities.
      We may need additional financing to implement our expansion strategy and we give no assurance as to the availability or the terms of any additional financing we may require. We may not have access to the funding required for the expansion of our business or such funding may not be available to us on acceptable terms. We may finance the expansion of our business with additional indebtedness or by issuing additional equity securities. We could face financial risks associated with incurring additional indebtedness, such as reducing our liquidity and access to financial markets and increasing the amount of cash flow required to service such indebtedness, or associated with issuing additional stock, such as dilution of ownership and earnings.
      We must also obtain numerous regulatory approvals and permits in order to construct and operate additional or expanded facilities, including our Northwestern Iowa and Welcome facilities. There is no assurance that these requirements can be satisfied in a timely manner or at all. In addition, as described below under “—We may be adversely affected by environmental, health and safety laws, regulations and liabilities,” federal and state governmental requirements may substantially increase our costs, which could have a material adverse effect on our results of operations and financial position. Our expansion plans may also result in other unanticipated adverse consequences, such as the diversion of management’s attention from our existing operations.
      Our construction costs may also increase to levels that would make a new facility too expensive to complete or unprofitable to operate. We have not entered into any construction contracts or other arrangements with respect to the construction of our Northwestern Iowa Facility or our Welcome Facility that might limit our exposure to higher costs in developing and completing any new facilities. Contractors, engineering firms, construction firms and equipment suppliers also receive requests and orders from other ethanol companies and, therefore, we may not be able to secure their services or products on a timely basis or on acceptable financial terms. We may suffer significant delays or cost overruns as a result of a variety of factors, such as shortages of workers or materials, transportations constraints, adverse weather, unforeseen difficulties or labor issues, any of which could prevent us from commencing operations as expected at our facilities.
      Additionally, any expansion of our existing facilities or any installation of a solid-fuel combustion system at one of our existing facilities would be sufficiently novel and complex that we may not be able to complete either successfully or without incurring significant cost overruns and construction delays. We have only limited experience with facility expansion and we have never installed large-scale, solid-fuel combustion systems at our facilities.
      Accordingly, we give you no assurance that we will be able to implement our expansion strategy as planned or at all. There also is no assurance that we will find additional appropriate sites for new facilities or that we will be able to finance, construct, develop or operate these new or expanded facilities successfully.
Potential future acquisitions could be difficult to find and integrate, divert the attention of key personnel, disrupt our business, dilute shareholder value and adversely affect our financial results.
      As part of our business strategy, we may consider acquisitions of building sites, production facilities, storage or distribution facilities and selected infrastructure. There is no assurance that we will find suitable acquisition opportunities.

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      Acquisitions involve numerous risks, any of which could harm our business, including:
  difficulties in integrating the operations, technologies, products, existing contracts, accounting processes and personnel of the target and realizing the anticipated synergies of the combined businesses;
 
  difficulties in supporting and transitioning customers, if any, of the target company or assets;
 
  diversion of financial and management resources from existing operations;
 
  the price we pay or other resources that we devote may exceed the value we realize, or the value we could have realized if we had allocated the purchase price or other resources to another opportunity;
 
  risks of entering new markets or areas in which we have limited or no experience or are outside our core competencies;
 
  potential loss of key employees, customers and strategic alliances from either our current business or the business of the target;
 
  assumption of unanticipated problems or latent liabilities, such as problems with the quality of the products of the target; and
 
  inability to generate sufficient revenue to offset acquisition costs.
      Acquisitions also frequently result in the recording of goodwill and other intangible assets which are subject to potential impairments in the future that could harm our financial results. In addition, if we finance acquisitions by issuing convertible debt or equity securities, our existing shareholders may be diluted, which could affect the market price of our common stock. As a result, if we fail to properly evaluate acquisitions or investments, we may not achieve the anticipated benefits of any such acquisitions, and we may incur costs in excess of what we anticipate. The failure to successfully evaluate and execute acquisitions or investments or otherwise adequately address these risks could materially harm our business and financial results.
Growth in the sale and distribution of ethanol is dependent on the changes to and expansion of related infrastructure which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure disruptions.
      Substantial development of infrastructure will be required by persons and entities outside our control for our operations, and the ethanol industry generally, to grow. Areas requiring expansion include, but are not limited to:
  additional rail capacity;
 
  additional storage facilities for ethanol;
 
  increases in truck fleets capable of transporting ethanol within localized markets;
 
  expansion of refining and blending facilities to handle ethanol;
 
  growth in service stations equipped to handle ethanol fuels; and
 
  growth in the fleet of FFVs capable of using E85 fuel.
      There is no assurance that the substantial investments required for these infrastructure changes and expansions will be made or that they will be made on a timely basis. Any delay or failure in making the changes to or expansion of infrastructure could hurt the demand or prices for our products, impede our delivery of products, impose additional costs on us or otherwise have a material adverse effect on our results of operations or financial position. Our business is dependent on the continuing availability of infrastructure and any infrastructure disruptions could have a material adverse effect on our business.

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We have a limited operating history and our business may not be as successful as we envision.
      We began our business in 2001 and commenced commercial operations at our Aurora Facility in December 2003 and at our Fort Dodge Facility in October 2005. Accordingly, we have a limited operating history from which you can evaluate our business and prospects. In addition, our prospects must be considered in light of the risks and uncertainties encountered by an early-stage company and in rapidly evolving markets, such as the ethanol market, where supply and demand may change significantly in a short amount of time.
New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry.
      According to the RFA, domestic ethanol production capacity has increased from 1.8 BGY at December 31, 2001 to an estimated 4.5 BGY at March 20, 2006. The RFA estimates that, as of March 20, 2006, approximately 2.1 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 90 production facilities. Excess capacity in the ethanol industry would have an adverse effect on our results of operations, cash flows and financial position. In a manufacturing industry with excess capacity, producers have an incentive to manufacture additional products for so long as the price exceeds the marginal cost of production (i.e., the cost of producing only the next unit, without regard for interest, overhead or fixed costs). This incentive can result in the reduction of the market price of ethanol to a level that is inadequate to generate sufficient cash flow to cover costs.
      Excess capacity may also result from decreases in the demand for ethanol, which could result from a number of factors, including regulatory developments and reduced U.S. gasoline consumption. Reduced gasoline consumption could occur as a result of increased prices for gasoline or crude oil, which could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage. There is some evidence that this has occurred in the recent past as U.S. gasoline prices have increased.
We may not be able to compete effectively in our industry.
      In the U.S., we compete with other corn processors, ethanol producers and refiners, including Archer Daniels Midland Company, or ADM, Cargill, Inc., or Cargill, Aventine Renewable Energy, Inc., or Aventine, and Abengoa Bioenergy Corp., or Abengoa. A number of our competitors are divisions of substantially larger enterprises and have substantially greater financial resources than we do. Smaller competitors also pose a threat. Farmer-owned cooperatives and independent firms consisting of groups of individual farmers and investors have been able to compete successfully in the ethanol industry. These smaller competitors operate smaller facilities which do not affect the local price of corn grown in the proximity to the facility as much as larger facilities like ours do. In addition, many of these smaller competitors are farmer-owned and often require their farmer-owners to commit to selling them a certain amount of corn as a requirement of ownership. A significant portion of production capacity in our industry consists of smaller-sized facilities. Most new ethanol plants under development across the country are individually owned. In addition, institutional investors and high net worth individuals could heavily invest in ethanol production facilities and oversupply the demand for ethanol, resulting in lower ethanol price levels that might adversely affect our results of operations and financial position.
      We also face increasing competition from international suppliers. Although there is a $0.54 per gallon tariff (which is scheduled to expire in 2007) on foreign produced ethanol that is approximately equal to the blenders’ credit, ethanol imports equivalent to up to 7% of total domestic production in any given year from various countries were exempted from this tariff under the Caribbean Basin Initiative to spur economic development in Central America and the Caribbean. Currently, international suppliers produce ethanol primarily from sugar cane and have cost structures that may be substantially lower than ours.
      Any increase in domestic or foreign competition could cause us to reduce our prices and take other steps to compete effectively, which could adversely affect our results of operations and financial position.

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Our operating results may suffer if Aventine does not perform its obligations under existing arrangements or if we cannot achieve results comparable to those achieved by marketing through Aventine once we begin marketing and selling our ethanol directly to customers.
      Aventine, a significant competitor of ours, is also the sole buyer of substantially all of our ethanol and we rely heavily on its marketing efforts to successfully sell our product. Because Aventine sells ethanol for itself and a number of other producers, we have limited control over its sales efforts. In addition, a significant portion of our accounts receivable is attributable to Aventine, which is rated significantly below investment grade. If Aventine were to default on payments to us, we would experience a material loss.
      On February 15, 2006, we notified Aventine that we will terminate our agreements with it on March 31, 2007. At the expiration of our agreements with Aventine, we intend to market and sell our ethanol directly to blenders, refiners and other end users. We give no assurance, however, that the marketing, sales, distribution, transportation, storage or administrative efforts we will need to undertake or arrange will achieve results comparable to those achieved by marketing through Aventine. Any failure to successfully execute these responsibilities would have a material adverse effect on our results of operations and financial position.
We do not assure you that operations at our Charles City Facility or our additional planned facilities will achieve results comparable to our Aurora Facility or our Fort Dodge Facility.
      Test operations began at our Fort Dodge Facility in September 2005. During this time, a failure occurred in a key piece of equipment. This failure, which has been remedied by installation of replacement equipment from a new supplier, delayed our start up process. In October 2005, we recommenced our start up activities at the plant and are now operating at full capacity. As a new plant, our Fort Dodge Facility is subject, and our Charles City Facility and our additional planned facilities will be subject, to various uncertainties as to their ability to produce ethanol and co-products as planned, including the potential for additional failures of key equipment. We do not assure you that the results of our Charles City Facility or our additional planned facilities will be comparable to those of our Aurora Facility or our Fort Dodge Facility.
The U.S. ethanol industry is highly dependent upon a myriad of federal and state legislation and regulation and any changes in legislation or regulation could materially and adversely affect our results of operations and financial position.
      The elimination or significant reduction in the blenders’ credit could have a material adverse effect on our results of operations and financial position. The cost of production of ethanol is made significantly more competitive with regular gasoline by federal tax incentives. Before January 1, 2005, the federal excise tax incentive program allowed gasoline distributors who blended ethanol with gasoline to receive a federal excise tax rate reduction for each blended gallon they sold. If the fuel was blended with 10% ethanol, the refiner/marketer paid $0.052 per gallon less tax, which equated to an incentive of $0.52 per gallon of ethanol. The $0.52 per gallon incentive for ethanol was reduced to $0.51 per gallon in 2005 and is scheduled to expire (unless extended) in 2010. We do not assure you that the blenders’ credits will be renewed in 2010 or if renewed, on what terms they will be renewed. The elimination or significant reduction in the blenders’ credit may have a material adverse effect on our results of operations and financial position. See “Business — Legislation.”
      Ethanol can be imported into the U.S. duty-free from some countries, which may undermine the ethanol industry in the U.S. Imported ethanol is generally subject to a $0.54 per gallon tariff that was designed to offset the $0.51 per gallon ethanol incentive available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. A special exemption from the tariff exists for ethanol imported from 24 countries in Central America and the Caribbean Islands, which is limited to a total of 7% of U.S. production per year. Imports from the exempted countries may increase as a result of new plants under development. Since production costs for ethanol in these countries are estimated to be significantly less than what they are in the U.S., the duty-free import of ethanol through the countries exempted from the tariff may negatively affect the demand for domestic ethanol and the price at which we sell our ethanol. Any changes in the tariff or exemption from the tariff could have a material adverse effect on our results of operations and financial position. See “Business — Legislation.”

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      The effect of the RFS in the recent Energy Policy Act is uncertain. The use of fuel oxygenates, including ethanol, was mandated through regulation, and much of the forecasted growth in demand for ethanol was expected to result from additional mandated use of oxygenates. Most of this growth was projected to occur in the next few years as the remaining markets switch from MTBE to ethanol. The recently enacted energy bill, however, eliminated the mandated use of oxygenates and established minimum nationwide levels of renewable fuels (ethanol, biodiesel or any other liquid fuel produced from biomass or biogas) to be included in gasoline. The legislation also included provisions for trading of credits for use of renewable fuels and authorized potential reductions in the RFS minimum by action of a governmental administrator. In addition, the rules for implementation of the RFS and the energy bill are still under development. We provide no assurance that the favorable ethanol provisions in the energy bill will not be adversely affected by these provisions or the enactment of additional legislation.
      The legislation did not include MTBE liability protection sought by refiners, and ethanol producers have estimated that this will result in accelerated removal of MTBE and increased demand for ethanol. No assurance can be given, however, that refineries will use ethanol rather than possible replacement additives, such as iso-octane, iso-octene or alkylate. Accordingly, the actual demand for ethanol may increase at a lower rate than production for estimated demand, resulting in excess production capacity in our industry, which would negatively affect our results of operations, financial position and cash flows. See “—New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry.”
We may be adversely affected by environmental, health and safety laws, regulations and liabilities.
      We are subject to various federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees. In addition, some of these laws and regulations require our facilities to operate under permits that are subject to renewal or modification. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns. We do not assure you that we have been, are or will be at all times in complete compliance with these laws, regulations or permits or that we have had or have all permits required to operate our business. We also do not assure you that we will not be subject to legal actions brought by environmental advocacy groups and other parties for actual or alleged violations of environmental laws or our permits. In addition, we have made, and expect to make, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits.
      We may be liable for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arrange for the disposal of hazardous substances. If these substances have been or are disposed of or released at sites that undergo investigation and/or remediation by regulatory agencies, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, or other environmental laws for all or part of the costs of investigation and/or remediation, and for damages to natural resources. We may also be subject to related claims by private parties alleging property damage and personal injury due to exposure to hazardous or other materials at or from those properties. Some of these matters may require us to expend significant amounts for investigation, cleanup or other costs.
      In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional significant expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our production facilities. Present and future environmental laws and regulations (and interpretations thereof) applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial position.

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      The hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, and abnormal pressures and blowouts) may also result in personal injury claims or damage to property and third parties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, we could sustain losses for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. Events that result in significant personal injury or damage to our property or third parties or other losses that are not fully covered by insurance could have a material adverse effect on our results of operations and financial position.
We are dependent upon our officers for management and direction, and the loss of any of these persons could adversely affect our operations and results.
      We are dependent upon our officers for implementation of our proposed expansion strategy and execution of our business plan. The loss of any of our officers could have a material adverse effect upon our results of operations and financial position. We do not have employment agreements with our officers or other key personnel. In addition, we do not maintain “key person” life insurance for any of our officers. The loss of any of our officers could delay or prevent the achievement of our business objectives.
Our competitive position, financial position and results of operations may be adversely affected by technological advances.
      The development and implementation of new technologies may result in a significant reduction in the costs of ethanol production. We do not predict when new technologies may become available, the rate of acceptance of new technologies by our competitors or the costs associated with new technologies. In addition, advances in the development of alternatives to ethanol could significantly reduce demand for or eliminate the need for ethanol.
      Any advances in technology which require significant capital expenditures to remain competitive or which reduce demand or prices for ethanol would have a material adverse effect on our results of operations and financial position.
Our level of indebtedness could adversely affect our ability to react to changes in our business, and we may be limited in our ability to use debt to fund future capital needs.
      As of February 28, 2006, our total debt was $210.0 million, before unaccreted discount of $1.3 million. In addition, we had total borrowing capacity of approximately $26.9 million under our Credit Agreement. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $24.2 million of remaining borrowing capacity at February 28, 2006. Our substantial indebtedness could have important consequences for you by adversely affecting our financial position. Our substantial indebtedness could:
  require us to dedicate a substantial portion of our cash flow from operations to payments with respect to our indebtedness, thereby reducing the availability of our cash flow for working capital, capital expenditures and other general corporate expenditures;
 
  increase our vulnerability to adverse general economic or industry conditions;
 
  limit our flexibility in planning for, or reacting to, competition or changes in our business or industry;
 
  limit our ability to borrow additional funds;
 
  restrict us from building new facilities, making strategic acquisitions, introducing new products or services or exploiting business opportunities; and
 
  place us at a competitive disadvantage relative to competitors that have less debt or greater financial resources.
      Our ability to make payments on and refinance our indebtedness will depend on our ability to generate cash from our future operations. Our ability to generate cash from future operations is subject, in large part, to

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general economic, competitive, legislative and regulatory factors and other factors that are beyond our control. We do not guarantee that we will be able to generate enough cash flow from operations or that we will be able to obtain enough capital to service our debt or fund our planned capital expenditures. In addition, we may need to refinance some or all of our indebtedness on or before maturity. We do not guarantee that we will be able to refinance our indebtedness on commercially reasonable terms or at all.
      If we cannot service or refinance our indebtedness, we may have to take actions such as selling assets, seeking additional equity or reducing or delaying capital expenditures, strategic acquisitions, investments or alliances. We may not be able to take these actions, if necessary, on commercially reasonable terms or at all. In addition, our secured lenders could foreclose on and sell our assets if we default on our indebtedness.
      Moreover, we have the ability under our debt instruments to incur substantial additional indebtedness, and any additional indebtedness we incur could exacerbate the risks described above.
As a result of this offering, we will be subject to financial reporting and other requirements for which our accounting, internal audit and other management systems and resources may not be adequately prepared.
      As a result of this offering, we will become subject to reporting and other obligations under the Securities Exchange Act of 1934, as amended, or the Exchange Act, including the requirements of Section 404 of the Sarbanes-Oxley Act. Section 404 requires annual management assessment of the effectiveness of our internal controls over financial reporting and a report by our independent auditors addressing these assessments. These reporting and other obligations will place significant demands on our management, administrative, operational, internal audit and accounting resources. We anticipate that we will need to upgrade our systems; implement additional financial and management controls, reporting systems and procedures; implement an internal audit function; and hire additional accounting, internal audit and finance staff. If we are unable to accomplish these objectives in a timely and effective fashion, our ability to comply with our financial reporting requirements and other rules that apply to reporting companies could be impaired. Any failure to maintain effective internal controls could have a material adverse effect on our business, operating results and stock price.
Risks Relating to This Offering and Ownership of Our Common Stock
There is no existing market for our common stock and we do not know if one will develop. Even if a market does develop, the stock prices in the market may not exceed the offering price.
      Before this offering, there has not been a public market for our common stock and there are few public companies with substantial ethanol operations. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the New York Stock Exchange or otherwise, or how liquid that market may become, especially if few stock analysts follow our stock or issue research reports concerning our business or the ethanol industry in general. If an active trading market does not develop, you may have difficulty selling any shares that you buy.
      The offering price for the common stock will be determined by negotiations among us and the representative of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price you pay in this offering.
Our common stock price may be volatile and you may lose all or part of your investment.
      The market price of our common stock could fluctuate significantly, and you may not be able to resell your shares at or above the offering price. Those fluctuations could be based on various factors in addition to those otherwise described in this prospectus, 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 number of shares to be publicly traded after this offering;
 
  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.
A substantial number of shares of our common stock will become eligible for sale in the public market 180 days after the date of this offering, which could cause the price of our common stock to decline.
      Our officers and directors, substantially all of our existing shareholders and holders of options exercisable within 180 days of the date of this offering have agreed with the underwriters not to sell or otherwise dispose of any of their shares for a period of 180 days after the date of this offering. When these lock-up agreements expire, these shares and the shares underlying any options held by these individuals will become eligible for sale, in some cases subject only to the volume, manner of sale and notice requirements of Rule 144 of the Securities Act. Sales of a substantial number of these shares in the public market after this offering, or the perception that these sales could occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional equity securities. See “Shares Eligible for Future Sale” for further discussion of the shares that will be freely tradable 180 days after the date of this offering.
Our existing shareholders will exert significant influence over us after the completion of this offering. Their interests may not coincide with yours and they may make decisions with which you may disagree.
      After this offering, Donald L. Endres, our Chief Executive Officer, Bluestem Funds and Eos Funds will own approximately      %,      % and      % of our outstanding common stock, respectively, and our officers, directors and principal shareholders, i.e., shareholders holding more than 5.0% of our common stock, including Donald L. Endres, Bluestem Funds and Eos Funds, will together control approximately      % of our outstanding common stock. As a result, these shareholders, acting individually or together, could control substantially all matters requiring shareholder approval, including the election of most directors and approval of significant corporate transactions. In addition, this concentration of ownership may delay or prevent a change in control of our company and make some transactions more difficult or impossible without the support of these shareholders. The interests of these shareholders may not always coincide with our interests as a company or the interest of other shareholders. Accordingly, these shareholders could cause us to enter into transactions or agreements that you would not approve or make decisions with which you may disagree.
Provisions in our charter documents and South Dakota law may delay or prevent our acquisition by a third party.
      Our articles of incorporation, as amended, our 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

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over the market price for their common stock. See “Description of Capital Stock — Anti-Takeover Provisions.”
We may be a United States real property holding corporation, in which case non-U.S. investors may be subject to U.S. federal income tax (including withholding tax) in connection with the disposition of our shares, and U.S. investors selling our shares may be required to certify as to their status in order to avoid withholding.
      We believe that we have not been and are not currently a “United States real property holding corporation” within the meaning of the Internal Revenue Code of 1986, as amended, or the Code, and we do not expect to become a United States real property holding corporation. However, no assurances can be made in this regard.
      A non-U.S. holder of our common stock will generally be subject to U.S. federal income tax with respect to distributions made by us that are treated as dividends for U.S. federal income tax purposes. Moreover, a non-U.S. holder of our common stock not otherwise subject to U.S. federal income tax on gain from the sale or other disposition of our common stock may nevertheless be subject to U.S. federal income tax with respect to such sale or other disposition if we are, or have been, a United States real property holding corporation at any time within the five-year period preceding the disposition (or the non-U.S. holder’s holding period if shorter). Generally, we will be a United States real property holding corporation if the fair marker value of our U.S. real property interests, equals or exceeds 50% of the sum of the fair market values of our worldwide real property interests and other assets used or held for use in a trade or business, all as determined under applicable U.S. Treasury regulations.
      Certain non-U.S. holders of our common stock may be eligible for an exception to the forgoing general rule if our common stock is regularly traded on an established securities market during the calendar year in which the sale or disposition occurs and the non-U.S. holder holds no more than 5% of our outstanding common stock, directly or indirectly, during the relevant period (the “5% exception”). If we are a United States real property holding corporation during the relevant time period, and the 5% exception does not apply, the buyer or other transferee of our common stock will generally be required to withhold tax at the rate of 10% on the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in the applicable Treasury regulations. See “U.S. Federal Income Tax Considerations for Non-U.S. Holders” for a discussion of United States real property holding corporation issues.

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USE OF PROCEEDS
      We estimate that we will receive net proceeds of $           million from our sale of the                      shares of common stock offered by us in this offering, based upon an assumed initial public offering price of $           per share, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any of the proceeds from the sale of shares by the selling shareholders.
      We intend to use the net proceeds to us from this offering of common stock, together with cash generated from operations, to finance the construction of our Northwestern Iowa Facility and our Welcome Facility, at an aggregate cost of approximately $280.0 million, or $140.0 million per facility.
      The amounts and timing of these expenditures will depend on numerous factors, including the federal, state and local permitting and licensing process, the construction schedules of our contractors, the delivery of goods and equipment by our suppliers and various other considerations typically associated with large-scale construction projects. A portion of the proceeds also may be used for general corporate purposes. Pending any use as described above, we plan to invest the net proceeds in investment-grade, short-term, interest-bearing securities.
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 after this offering. The indenture underlying our senior secured notes limits, and our future debt agreements may restrict, our ability to pay dividends. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources” and “Description of Certain Indebtedness.”

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CAPITALIZATION
      The following table sets forth, as of December 31, 2005, our cash and cash equivalents and capitalization:
  On an actual basis; and
 
  On an as adjusted basis to give effect to the receipt of net proceeds from the sale of                      shares of common stock by us in this offering at an assumed initial public offering price of $           per share, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us and the adjustment described in footnote 2 below.
      You should read this table in conjunction with the consolidated financial statements and the related notes, “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial information included elsewhere in this prospectus.
                       
    As of December 31, 2005
     
    Actual   As Adjusted(1)(2)
         
    (in thousands)
Cash and cash equivalents
  $ 29,714     $    
             
Restricted cash(3)
  $ 124,750     $ 124,750  
             
Long-term debt, net of issuance discount(4)
  $ 208,719     $ 208,719  
             
Shareholders’ equity:
               
 
Preferred stock ($0.01 par value per share; 100,000,000 shares authorized, none issued or outstanding)
           
 
Common stock ($0.01 par value per share; 250,000,000 shares authorized; 62,492,722 shares issued and outstanding, actual, and            shares issued and outstanding, as adjusted)
    625          
 
Additional paid-in capital
    132,848          
 
Retained earnings
    13,862          
 
Deferred compensation
    (107 )     (107 )
 
Accumulated other comprehensive loss
    (2,310 )     (2,310 )
             
   
Total shareholders’ equity
    144,918          
             
     
Total capitalization
  $ 353,637     $    
             
 
(1)  A $1.00 increase (decrease) in the assumed initial public offering price of $         per share would increase (decrease) each of cash equivalents, additional paid-in capital, total shareholders’ equity and total capitalization by $ million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. The as adjusted information discussed above is illustrative only and following completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.
(2)  Adjusted to give effect to the issuance of shares of common stock in this offering at an assumed price of $         per share, estimated underwriting discounts and commissions and estimated offering expenses payable by us. Also adjusted for the expected reclassification of the long-term liability associated with the put warrant to shareholders’ equity, and for the estimated stock-based compensation expense to be recorded upon vesting of certain options and warrants upon completion of this offering. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Summary of Critical Accounting Policies and Estimates — Put warrant.”
(3)  In connection with the issuance of our $210.0 million senior secured notes, we deposited $125.0 million of the net proceeds into an escrow account to finance the start-up and construction costs of our Charles City Facility. The funds held in the escrow account are subject to a security interest granted to the trustee for the benefit of the holders of the senior secured notes and will be disbursed by the trustee, acting as an agent and securities intermediary, in accordance with an escrow agreement.
(4)  Our available capacity under the Credit Agreement is determined as a percentage of certain of our accounts receivable and inventory. As of December 31, 2005, we had total borrowing capacity of approximately $24.1 million. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $21.4 million of remaining borrowing capacity at December 31, 2005.

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     The table above excludes the following:
  shares of common stock issuable upon the exercise of options and warrants outstanding at December 31, 2005, at a weighted average exercise price of $1.10 per share; and
 
  shares of common stock reserved for future issuance under our stock incentive plan.
DILUTION
      If you invest in our common stock, your interest will be diluted to the extent of the difference between the public offering price per share of our common stock and the as adjusted net tangible book value per share of our common stock after this offering. We calculate net tangible book value per common share by dividing our net tangible book value, which equals total assets less intangible assets (including goodwill and unamortized debt issuance costs) and total liabilities, by the number of shares outstanding. Our net tangible book value at December 31, 2005 was $132.3 million, or $2.12 per common share, based upon 62,492,722 shares outstanding.
      After giving effect to the sale of                      shares of common stock in this offering, and after deducting the estimated underwriting discount and estimated offering expenses payable by us, our as adjusted net tangible book value as of December 31, 2005 would have been approximately $           million, or $           per common share (before the reclassification of the long-term liability associated with the put warrant). This represents an immediate increase in net tangible book value of $           per common share to existing shareholders, and an immediate dilution in net tangible book value of $           per common share to new investors, or approximately      % of the offering price of $           per common share. The following table illustrates this dilution on a per common share basis:
                   
Assumed initial public offering price per common share
          $    
 
Net tangible book value per common share as of December 31, 2005
  $ 2.12          
 
Increase in net tangible book value per common share attributable to this offering
               
             
Adjusted net tangible book value per common share after the offering
               
             
Dilution in net tangible book value per common share to new investors
          $    
             
      The following table shows on an as adjusted basis at December 31, 2005, the total net cash consideration paid to us and the average price per common share paid by existing shareholders and by new investors in this offering before deducting estimated underwriting discounts and estimated offering expenses payable by us.
                                         
    Shares Purchased   Total Consideration   Average
            Price Per
    Number   Percent   Amount   Percent   Share
                     
            (in thousands)        
Existing shareholders
    62,492,722         %   $ 121,941         %   $ 1.95  
New investors
                                       
                               
Total
            100.0 %   $         100.0 %   $    
                               
      This discussion of dilution, and the table quantifying it, assume no exercise of any outstanding stock options or warrants after December 31, 2005.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING 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, 2002 and 2003 and the selected consolidated income statement data for the year ended December 31, 2002 have been derived from our audited consolidated financial statements that are not included in this prospectus. The selected consolidated balance sheet financial data as of December 31, 2004 and 2005 and the selected consolidated income statement data for each of the three years in the period ended December 31, 2005 have been derived from the audited Consolidated Financial Statements included elsewhere in this prospectus. You should read the following table in conjunction with “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 prospectus. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following consolidated financial data.
                                     
    Year Ended December 31,
     
    2002   2003   2004   2005
                 
    (dollars in thousands, except per share data)
Income statement data:(1)
                               
Net sales
  $     $ 10,884     $ 186,029     $ 235,440  
Other revenues, incentive income
          1,776       7,723       919  
                         
Total revenues
          12,660       193,752       236,359  
Cost of goods sold
          8,450       154,022       200,823  
                         
Gross profit
          4,210       39,730       35,536  
Selling, general and administrative expenses
    1,226       2,233       6,140       11,874  
                         
Operating income (loss)
    (1,226 )     1,977       33,590       23,662  
                         
Other income (expense):
                               
 
Interest expense(2)
          (839 )     (8,892 )     (7,609 )
 
Other interest expense, loss on extinguishment of debt
                      (15,744 )
 
Interest income
    5       11       182       448  
 
Other income
    6       14       33       17  
                         
      11       (814 )     (8,677 )     (22,888 )
                         
 
Income (loss) before income taxes and minority interest
    (1,215 )     1,163       24,913       774  
Income taxes
          571       10,242       582  
                         
Income (loss) before minority interest
    (1,215 )     592       14,671       192  
Minority interest in net loss of subsidiary
                100       61  
                         
 
Net income (loss)
  $ (1,215 )   $ 592     $ 14,771     $ 253  
                         
Earnings (loss) per common share
                               
   
Basic
  $ (1.21 )   $ 0.02     $ 0.40     $ 0.01  
   
Diluted
    (1.21 )     0.02       0.39       0.01  
Shares used in per common share calculations
                               
   
Basic
    1,000,076       30,380,082       36,738,191       44,810,490  
   
Diluted
    1,031,975       30,577,961       37,908,751       47,578,869  
 
Other financial data:
                               
EBITDA(3)
  $ (1,203 )   $ 2,350     $ 37,831     $ 29,880  
Certain items included in EBITDA(4)
          1       951       7,416  
Working capital (deficit)
    1,526       (35,182 )     9,779       61,551  
Capital expenditures
    5,295       63,974       25,215       87,095  
Net cash provided by (used in) operating activities
    (653 )     (10,641 )     20,858       (2,515 )
Net cash used in investing activities
    (5,294 )     (63,974 )     (25,214 )     (212,049 )
Net cash provided by financing activities
    10,021       70,381       14,621       233,982  
 
Operating data:
                               
Ethanol sold (gallons)
          6,459,804       101,370,470       126,346,295  
Average gross price of ethanol sold (dollars per gallon)(5)
  $     $ 1.28     $ 1.50     $ 1.59  
Total corn cost
          7,172       89,677       99,434  
Total natural gas cost
          452       19,115       37,067  

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    As of December 31,
     
    2002   2003   2004   2005
                 
    (in thousands)
Balance sheet data:
                               
Cash and cash equivalents
  $ 4,264     $ 31     $ 10,296     $ 29,714  
Restricted cash
                      124,750  
Property and equipment, net
    6,223       76,882       106,753       179,683  
Total assets
    11,907       96,479       150,328       405,129  
Total debt(6)
          58,503       58,381       210,000  
Total equity
    8,567       17,594       44,476       144,918  
 
(1)  Income statement data reflects the financial impact of operations of our Aurora Facility, which commenced operations in December 2003, and our Fort Dodge Facility, which commenced operations in October 2005.
 
(2)  Interest expense includes changes in the fair value of a put warrant of $566 for the year ended December 31, 2003, $3,481 for the year ended December 31, 2004, and $2,809 for the year ended December 31, 2005. The put warrant is described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Summary of Critical Accounting Policies and Estimates — Put warrant.”
 
(3)  EBITDA is defined as earnings before interest expense, income tax expense, depreciation and amortization. Amortization of debt issuance costs and debt discount are included in interest expense. EBITDA is not a measure of financial performance under GAAP, and should not be considered an alternative to net income, or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity. EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. Some of the limitations of EBITDA are:
  EBITDA does not reflect our cash used for capital expenditures;
 
  Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA does not reflect the cash requirements for replacements;
 
  EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;
 
  EBITDA does not reflect the cash necessary to make payments of interest or principal on our indebtedness; and
 
  EBITDA includes non-recurring payments to us which are reflected in other income.
  Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to us to service our debt or to invest in the growth of our business. We compensate for these limitations by relying on our GAAP results as well as on our EBITDA. Management uses EBITDA as a measure of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.
 
  The following table reconciles our EBITDA to net income for each period presented:
                         
    Year Ended December 31,
     
    2003   2004   2005
             
    (in thousands)
Net income
  $ 592     $ 14,771     $ 253  
Depreciation
    348       3,926       5,692  
Interest expense
    839       8,892       23,353  
Income taxes
    571       10,242       582  
                   
EBITDA
  $ 2,350     $ 37,831     $ 29,880  
                   

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(4)  The following table shows certain items that are included in EBITDA associated with our earnings. We believe that the table, when reviewed in connection with our presentation of EBITDA, provides another useful tool to our management and investors for measuring comparative operating performance between time periods and among companies. In addition to EBITDA, our management assesses the adjustments presented in this table when preparing our annual operating budget and financial projections. EBITDA, as defined above, was reduced by the following items:
                           
    Year Ended December 31,
     
    2003   2004   2005
             
    (in thousands)
Loss attributable to VFD, excluding interest and depreciation*
  $ 1     $ 951     $ 4,776  
Loss on disposal of a thermal oxidizer system
                2,640  
                   
 
Total
  $ 1     $ 951     $ 7,416  
                   
Net loss incurred prior to commencement of operations of VFD in October 2005.
(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, 2005 is shown before unaccreted discount of $1.3 million.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
      The following discussion should be read in conjunction with the “Selected Consolidated Financial and Operating Data” and the consolidated financial statements and accompanying notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this prospectus, particularly in “Risk Factors.” All references to years relate to the calendar year ended December 31 of the particular year.
Overview
      VeraSun Energy Corporation is the second largest ethanol producer in the U.S. based on production capacity, according to the RFA. We are also the largest “pure-play” ethanol producer, focusing primarily on the production and sale of ethanol and its co-products. This focus has enabled us to significantly grow our ethanol production capacity and to work with automakers, fuel distributors, trade associations and consumers to increase the demand for ethanol. As an industry leader, we play an active role in developments within the renewable fuels industry.
      We own and operate two of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 230 MMGY. As of January 1, 2006, our ethanol production capacity represented approximately 5% of the total ethanol production capacity in the U.S., according to the RFA. In addition to producing ethanol, we produce and sell wet distillers grains, or WDGS, and dry distillers grains, or DDGS, as ethanol co-products, which serve to partially offset our corn costs. We expect to operate three facilities with an aggregate production capacity of 340 MMGY by the end of August 2007 and five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008.
      The table below provides an overview of our ethanol plants that are in operation or under construction as of March 2006.
             
    Aurora Facility   Fort Dodge Facility   Charles City Facility(1)
             
Location
  Aurora, South Dakota   Fort Dodge, Iowa   Charles City, Iowa
Year completed or scheduled to be completed
  2003 (expansion 2005)(2)   2005   2007
Annual ethanol capacity (in millions of gallons)
  120   110   110(3)
Ownership
  100%   100%   100%
Production process
  Dry-Milling   Dry-Milling   Dry-Milling
Primary energy source
  Natural Gas   Natural Gas   Natural Gas
Estimated distillers grains production (dry) per year
  390,000 tons   350,000 tons   350,000 tons
Estimated corn processed per year
  43 million bushels   39 million bushels   39 million bushels
Corn grown during 2004-2005 crop year within a 60-mile radius
  325 million bushels   598 million bushels   563 million bushels
 
(1)  Construction of our Charles City Facility commenced in 2006 and is being funded primarily with $125.0 million of the net proceeds from the sale of senior secured notes in December 2005.
(2)  In June 2005, our Aurora Facility was expanded from a production capacity of 100 MMGY to 120 MMGY.
(3)  Estimated upon completion of construction of our Charles City Facility.
     In addition, we expect to commence construction of the Northwestern Iowa Facility and the Welcome Facility in the latter half of 2006. We expect these facilities to be operational by the end of the first quarter of 2008. We plan to finance the construction costs of the Northwestern Iowa Facility and the Welcome Facility

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with the net proceeds we receive from this offering and from our cash flow from operations. We intend to replicate our successful construction and production processes at these additional facilities.
Recent Developments
      Marketing Arrangements. As a member of the Aventine marketing alliance, substantially all of our ethanol is sold and priced through a pooling of our and other producers’ ethanol. We believe our ethanol constitutes over 35% of the ethanol pool that Aventine manages, which makes us the largest contributor to the pool. On February 15, 2006, we notified Aventine that we will terminate our agreements with it on March 31, 2007. At the expiration of our agreements with Aventine, we intend to market and sell our ethanol directly to blenders, refiners and other end users. Up to this point in the development and expansion of our business, we have used our marketing arrangement with Aventine to pool our ethanol with other producers, allowing us to establish relationships with ethanol buyers seeking large suppliers. We believe our business has become large enough for us to market ethanol directly to customers, giving us the benefits of direct customer contact and control of contract negotiations.
      Senior Secured Notes Offering. On December 21, 2005, we issued $210.0 million of senior secured notes, the proceeds of which were used to repay indebtedness relating to the construction of our Aurora Facility and our Fort Dodge Facility, deposit $125.0 million into an escrow account to finance the start-up and construction costs of our Charles City Facility, pay fees and expenses related to the offering of the notes and the Credit Agreement and finance general corporate activities.
      Credit Agreement. In connection with, and as a condition to, the offering of the senior secured notes, we entered into the Credit Agreement. The Credit Agreement provides for a $30.0 million borrowing base line of credit, with a $10.0 million sublimit for letters of credit. Our obligations under the Credit Agreement are secured by a first priority lien on all of our and certain of our subsidiaries’ accounts receivable, inventory and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which the proceeds are deposited), and are unconditionally and irrevocably guaranteed by all of our existing and future ethanol production subsidiaries. Borrowings under the Credit Agreement bear interest at LIBOR plus the applicable margin, which was 3.0% as of February 28, 2006. In addition to paying interest on the outstanding principal under the Credit Agreement, we are also required to pay a commitment fee to First National Bank of Omaha in respect of unused loan commitments at an initial rate of 0.25%. The interest rate and the commitment fee are subject to adjustment based on our working capital levels. The Credit Agreement matures on December 31, 2008. As of February 28, 2006, there was no outstanding balance and $26.9 million was available to borrow under the Credit Agreement. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $24.2 million of remaining borrowing capacity at February 28, 2006.
Industry Outlook
      The ethanol industry has undergone significant growth in recent years and is affected by a number of factors, including the following items.
      Overall ethanol demand. We expect demand for ethanol in the U.S. to continue to grow as a result of:
  favorable economics for refiners and blenders requiring octane and clean blend components;
 
  phase-out of MTBE, an alternative oxygenate to ethanol, due to environmental, health and liability concerns;
 
  increased demand by consumers for, and favorable economics associated with, E85 as an alternative fuel to gasoline;
 
  shortage of domestic petroleum refining capacity;
 
  increased pressure to substitute renewable fuels for gasoline to extend U.S. gasoline supplies and reduce dependence on foreign oil; and

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  mandated renewable fuel usage in the Energy Policy Act of 2005.
      Spread between ethanol and corn prices. Our gross margins depend principally on the spread between ethanol and corn prices. In recent periods, the spread between ethanol and corn prices has been at a historically high level, driven in large part by high oil prices and historically low corn prices resulting from continuing record corn yields and decreasing exports of corn. Any increase or reduction in the spread between ethanol and corn prices, whether as a result of an increase in corn prices or a reduction in ethanol prices, will have an effect on our financial performance. The following graphs set forth various ethanol and corn price data for recent periods and illustrate the volatility in market prices.
Ethanol Prices(1)
(ETHANOL PRICES CHART)
 
(1)  Based on the monthly average of the daily closing price of U.S. average ethanol rack prices quoted by Bloomberg.

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Corn Prices(1)
(GRAPH)
 
(1)  Based on the monthly average of daily close prices of the Nearby Corn Futures quoted by the Chicago Board of Trade.

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     Corn and natural gas prices. Our gross margins and results of operations are highly dependent on the price of corn and natural gas. Both of these inputs are subject to volatile market conditions as a result of weather, market demand, regulation and general economic conditions. In addition to the graph above depicting corn prices for the most recent 5-year period, the following graph sets forth various natural gas price data for the most recent 5-year period and illustrates the changes in market prices.
Natural Gas Prices(1)
(GRAPH)
 
(1)  Based on the monthly average of daily close prices of Natural Gas Futures quoted by NYMEX.
     The Renewable Fuels Standard. As discussed above, we expect that some of the demand for ethanol will come from the RFS mandate of the Energy Policy Act. We provide you no assurance that the favorable ethanol provisions in the Energy Policy Act will not be adversely affected through further legislation. See “Risk Factors—The U.S. ethanol industry is highly dependent upon a myriad of federal and state legislation and regulation and any changes in legislation or regulation could materially and adversely affect our results of operations and financial position.”
      The federal blenders’ credit. Gasoline distributors who blend ethanol with gasoline receive a federal excise tax rate reduction for each blended gallon they sell, which improves the economics of ethanol as a blendstock. If the fuel is blended with 10% ethanol, the refiner/marketer pays $0.051 per gallon less tax, which equates to a $0.51 per gallon incentive for ethanol. The incentive is scheduled to expire in 2010 (unless extended).

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Components of Revenues and Expenses
      Total revenues. Our primary source of revenue is the sale of ethanol produced at our Aurora Facility and our Fort Dodge Facility. Sales of ethanol accounted for 81.2% of our net sales in 2004 and 84.8% of our net sales in 2005. We generate revenue from:
  the sale of ethanol;
 
  the sale of distillers grains, which are co-products of the ethanol production process;
 
  the sale of ethanol blended VE85tm fuel; and
 
  incentive income.
The selling prices we realize for our ethanol are largely determined by the market demand for ethanol, which, in turn, is influenced by the industry factors described above.
      Cost of goods sold and gross profit. Our gross profit is derived from our total revenues less our cost of goods sold. Our cost of goods sold is mainly affected by the cost of corn, natural gas and transportation expense. Corn is our most significant raw material cost. The price of corn is influenced by weather conditions and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors. These factors include government policies and subsidies with respect to agriculture and international trade, and global and local demand and supply. The spot price of corn tends to rise during the spring planting season in May and June and tends to decrease during the fall harvest in October and November. We purchase natural gas to power steam generation in our ethanol production process and to dry our distillers grains. Natural gas represents our second largest cost. Transportation expense represents the third major component of our cost of goods sold. Transportation expense consists of our transportation costs, including freight and shipping of our ethanol and co-products, as well as costs incurred in storing ethanol at destination terminals.
      Selling, general and administrative expenses. Selling, general and administrative expenses consist of salaries and benefits paid to our administrative employees, taxes, expenses relating to third-party services, insurance, travel, marketing and other expenses. Other expenses include education and training, marketing, travel, corporate donations and other miscellaneous overhead costs. We expect selling, general and administrative expenses to increase significantly in connection with our expansion plans, which will require us to hire more personnel. We also anticipate incurring higher expenses as a public company following the completion of this offering as a result of additional legal and corporate governance expenses, including: costs associated with compliance with Section 404 of the Sarbanes-Oxley Act of 2002; salary and payroll-related costs for additional accounting staff; and listing and transfer agent fees. In connection with this offering, substantially all of the outstanding options and warrants to purchase our common stock will become immediately exercisable due to accelerated vesting provisions within those instruments. This will result in a one-time, non-cash charge with respect to these options and warrants of approximately $           million, which we expect to record on completion of this offering. See “—Summary of Critical Accounting Policies and Estimates—Stock-based compensation.”
      Other income (expense). Other income (expense) includes the interest on our long-term debt and notes payable, the change in fair value of an outstanding put warrant, debt extinguishment costs and the amortization of the related fees to execute required financing agreements. We expect interest expense, net of interest capitalized as part of new plant construction, to increase significantly as a result of our issuance of $210.0 million aggregate principal amount of senior secured notes in December 2005 and future debt financings. Upon the closing of this offering, interest expense is expected to include an adjustment to adjust the outstanding put warrant to the initial public offering price of our common stock and the put feature is not expected to affect our earnings thereafter because it is expected to be terminated upon completion of this offering. See “—Summary of Critical Accounting Policies and Estimates—Put warrant.”

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Results of Operations
      The historical periods discussed below primarily reflect the operations of our Aurora Facility, which increased its production capacity from 100 MMGY to 120 MMGY in June 2005 after a shutdown of 17 days to expand the facility. Our Fort Dodge Facility did not begin full production until October 2005. Therefore, the results for the historical periods presented are not representative of the results that we expect to achieve in the future, which will reflect the full production from our Fort Dodge Facility, our Charles City Facility and, when constructed, our two additional planned facilities.
      The following table sets forth, for the periods indicated, revenues, expenses and net income, and the percentage relationship to total revenues of specified items in our consolidated income statement:
                                                 
    Year Ended December 31,
     
    2003   2004   2005
             
    (in thousands, except percentage data)
Total revenues
  $ 12,660       100.0 %   $ 193,752       100.0 %   $ 236,359       100.0 %
Cost of goods sold
    8,450       66.7       154,022       79.5       200,823       85.0  
                                     
Gross profit
    4,210       33.3       39,730       20.5       35,536       15.0  
Selling, general and administrative expenses
    2,233       17.7       6,140       3.2       11,874       5.0  
                                     
Operating income
    1,977       15.6       33,590       17.3       23,662       10.0  
Other expense, net
    (814 )     (6.4 )     (8,677 )     (4.4 )     (22,888 )     (9.7 )
                                     
Income before income taxes and minority interest
    1,163       9.2       24,913       12.9       774       0.3  
Income taxes
    571       4.5       10,242       5.3       582       0.2  
                                     
Income before minority interest
    592       4.7       14,671       7.6       192       0.1  
Minority interest in net loss of subsidiary
                100             61        
                                     
Net income
  $ 592       4.7 %   $ 14,771       7.6 %   $ 253       0.1 %
                                     
     Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
      Total revenues. Our total revenues consist of net sales and incentive income. Net sales increased by $49.4 million, or 26.6%, to $235.4 million for 2005 from $186.0 million for 2004. The increase in net sales was primarily the result of a 24.6% increase in the total gallons of fuel ethanol that we sold. Although nameplate capacity for our Aurora Facility increased to 120 MMGY from 100 MMGY in June 2005, fuel ethanol production for 2005 for our Aurora Facility was only slightly higher compared to 2004, primarily as a result of the loss of 17 production days in June 2005 during the plant expansion project. With our Fort Dodge Facility commencing operations in October 2005, however, total fuel ethanol production increased 27.4 million gallons for 2005. We produced a total of 128.0 million gallons of fuel ethanol, compared to 100.6 million gallons for 2004.
      In early 2005, ethanol prices significantly decreased due to a perceived over-supply of ethanol, which had a negative effect on our operating results in the second quarter of the year. Since that time, ethanol prices have recovered significantly due to increased gasoline prices, legislative changes and continued oil refining capacity shortages, resulting in an average realized price for 2005 that is $0.10 per gallon higher than the prior year period. The CBOT spot ethanol price rose from $1.19 per gallon in May 2005 to $2.08 per gallon as of December 31, 2005. The average price realized on our sales of ethanol increased to $1.59 per gallon, or 5.9%, for 2005 from $1.50 per gallon for 2004. Accordingly, net sales from ethanol increased $48.6 million, or 32.1%, to $199.7 million for 2005 from $151.1 million for 2004.
      The net loss from derivatives included in net sales was $3.9 million for 2005, compared to a loss of $4.3 million for 2004. See “—Summary of Critical Accounting Policies and Estimates—Derivative instruments and hedging activities.”

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      Net sales from co-products increased $100,000, or 0.3%, to $35.0 million for 2005 from $34.9 million for 2004. Co-product sales remained largely unchanged because decreased prices resulting from lower corn prices were offset by an increase in our production volumes.
      Our net sales of VE85™ increased $702,000 to $755,000 for 2005 from $53,000 for 2004. The increase was primarily the result of an increase in the number of service stations selling our product.
      Incentive income from government programs decreased $6.8 million, or 88.1%, to $0.9 million for 2005 from $7.7 million for 2004. These incentive payments are based primarily on increases in production levels from period to period, and our production did not increase for 2005 compared to 2004 because our Aurora Facility was in operation for both years. Accordingly, the incentive income received for 2004 was considerably higher than 2005 due to a substantial increase in ethanol production from 2003 to 2004, and only a minor increase from 2004 to 2005. The existing federal incentive income program will terminate on June 30, 2006. In addition, government funding has been limited to $1.275 million per producer.
      Cost of goods sold and gross profit. Gross profit decreased $4.2 million, or 10.6%, to $35.5 million for 2005 from $39.7 million for 2004. The decrease was primarily the result of a $2.6 million loss on disposal of equipment, decreased incentive income and higher natural gas and maintenance costs, partially offset by lower corn costs. Our average cost per bushel of corn decreased 14.9% in 2005.
      Corn represented 49.5% of our cost of goods sold before taking into account our co-product sales and 32.1% of our cost of goods sold after taking into account co-product sales for 2005 compared to 58.2% of our cost of goods sold before taking into account our co-product sales and 35.6% of our cost of goods sold after taking into account co-product sales for 2004. During the second quarter of 2005, the spread between ethanol and corn prices was historically narrow, primarily as a result of low ethanol prices due to concern over excess capacity arising when various markets did not require the blending of ethanol in gasoline as early as expected. In the third quarter of 2005, corn prices continued to decline and the ethanol market improved following the signing into law of the Energy Policy Act and continued oil refinery shortage concerns, resulting in historically wide spreads between ethanol and corn prices.
      Natural gas costs increased $18.0 million, or 93.9%, to $37.1 million and accounted for 18.5% of our cost of goods sold for 2005 from $19.1 million and accounted for 12.4% of our cost of goods sold for 2004. The increased cost of natural gas as a percentage of our cost of goods sold was primarily attributable to increased natural gas prices during the year. The average price for natural gas increased 48.1% for 2005, as a result of colder than average weather conditions and overall economic conditions.
      Transportation expense increased $6.3 million, or 27.4%, to $29.1 million for 2005 from $22.9 million for 2004, primarily as a result of an increase in our fleet of leased rail cars for our Fort Dodge Facility, increased rail rates for 2005 and increased shipments as a result of higher ethanol production.
      Labor and manufacturing overhead costs increased $9.8 million, or 124.2%, to $17.7 million for 2005 from $7.9 million for 2004. The increase was primarily a result of the additional maintenance cost associated with the Aurora Facility expansion project, annual maintenance at our Aurora Facility, increased depreciation expenses and the disposal of our Aurora Facility thermal oxidizer systems. The majority of the maintenance costs for our Aurora Facility were covered under warranty for 2004.
      The net loss from derivatives included in cost of goods sold was $7.9 million for 2005, compared to a gain of $5.1 million for 2004. See “—Summary of Critical Accounting Policies and Estimates—Derivative instruments and hedging activities.”
      Under policies adopted in connection with our prior subordinated debt facilities, we purchased forward contracts at specified times. These derivatives were designated as cash flow hedges during 2004 and through September 1, 2005. On September 1, 2005, we de-designated our exchange traded futures contracts for corn as cash flow hedges as our prospective assessment of the effectiveness of the derivatives was producing results outside the range acceptable under Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended. As a result, we now mark our corn position for

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all exchange traded futures contracts to market. Hedging losses recognized from ineffectiveness of the derivatives were $3.2 million for 2005.
      The loss on disposal of equipment of approximately $2.6 million that was included in cost of goods sold in 2005 was the result of the disposal of thermal oxidizer systems that were replaced as part of the plant expansion at our Aurora Facility in June 2005.
      Selling, general and administrative expenses. Selling, general and administrative expenses increased $5.7 million, or 93.4%, to $11.9 million for 2005 from $6.1 million for 2004. The increase was primarily the result of more than doubling our management and administrative staff over the prior period in anticipation of the expansion of our business due to construction of our Fort Dodge Facility. Administrative salaries and benefits increased $2.8 million, or 91.0%, to $5.9 million for 2005 from $3.1 million for 2004, and operations labor increased $1.2 million, or 64.7%, to $3.0 million for 2005 from $1.8 million for 2004. Each of these increases was attributable to the construction of our Fort Dodge Facility for 2005.
      Expense related to stock-based compensation increased $427,000, or 59.7%, to $1.1 million for 2005 from $715,000 for 2004. The increase was primarily the result of recognizing the vesting of performance based stock options at an increased intrinsic value based on the increase in the valuation of our common stock.
      Other income (expense). Net expense increased $14.2 million, or 163.8%, to $22.9 million for 2005 from $8.7 million for 2004. The increase was primarily the result of a loss on extinguishment of debt of $15.7 million offset partially by lower expense attributable to the change in fair value of an outstanding put warrant.
      Income taxes. The provision for income taxes decreased to $582,000 for 2005 from $10.2 million for 2004. The decrease was primarily the result of lower income before income taxes. The income tax provision of $582,000 for 2005 differs from the computed expected tax expense of $271,000 determined by applying the U.S. federal income tax rate to pretax income, as a result of the increase in income taxes relating largely to nondeductible expenses for the increase in value of the put warrant. This increase was partially offset by the effect of income from nontaxable consolidated subsidiaries. As a result of the business combination transactions which occurred in October and November 2005, which we collectively refer to as the Business Combination, future taxable gains and losses of our subsidiary VFD will be taken into account by us rather than by other members. For more information, see “Certain Relationships and Related Party Transactions—The Business Combination.”
      Minority interest. Minority interest in the loss of a subsidiary decreased $39,000, or 39%, to $61,000 for 2005 from $100,000 for 2004. The decrease related to the minority interest portion of start up expenses of our Fort Dodge Facility.
     Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
      Because our Aurora Facility did not commence operations until December 2003, we were in the development stage for substantially all of 2002 and 2003. As a result, comparisons with those years are not meaningful. In addition, our Fort Dodge Facility became operational in 2005. The following discussion, therefore, focuses primarily on the results achieved by our Aurora Facility for 2004.
      Total revenues. Net sales increased $175.1 million to $186.0 million for 2004 from $10.9 million for 2003. We produced 100.6 million gallons of ethanol.
      Net sales of ethanol increased $142.2 million to $151.1 million for 2004 from $8.9 million for 2003. Net sales from co-products increased $32.9 million to $34.9 million for 2004 from $1.9 million for 2003.
      The net loss from derivatives included in net sales was $4.3 million for 2004. See “—Summary of Critical Accounting Policies and Estimates—Derivative instruments and hedging activities.”
      Incentive income from government programs increased $5.9 million to $7.7 million for 2004, from $1.8 million for 2003.

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      Cost of goods sold and gross profit. Gross profit increased $35.5 million to $39.7 million for 2004 from $4.2 million for 2003. Our average cost per bushel of corn increased 15.0% in 2004.
      Corn represented 58.2% of our cost of goods sold before taking into account our co-product net sales and 35.6% of our cost of goods sold after taking into account our co-product net sales for 2004.
      Natural gas costs increased $18.7 million to $19.1 million for 2004 from $452,000 for 2003. Natural gas costs represented 12.4% of our cost of goods sold for 2004.
      Transportation expense increased $22.8 million to $22.9 million for 2004 from $67,000 for 2003. Freight expense represented $21.7 million, or 94.9%, of transportation expense for 2004.
      The net gain from derivatives included in cost of goods sold was $5.1 million for 2004. See “—Summary of Critical Accounting Policies and Estimates —Derivative instruments and hedging activities.”
      Selling, general and administrative expenses. Selling, general and administrative expenses increased $3.9 million, or 175.0%, to $6.1 million for 2004 from $2.2 million for 2003. Administrative salaries and benefits increased $1.9 million, or 153.3%, to $3.1 million from $1.2 million for 2003. These increases were primarily resulted from the increase in management and administrative staff after our Aurora Facility commenced operations in December 2003.
      Expense for stock-based compensation increased to $715,000 for 2004 from $0 for 2003. No stock options were granted in 2003.
      Other income (expense). Net expense increased $7.9 million to $8.7 million for 2004 from $814,000 for 2003, as a result of interest expense resulting from increased total borrowings under our credit facilities during 2004. We also recognized interest expense of $3.5 million resulting from the change in fair value of the put warrant held by Teachers Insurance and Annuity Association of America, or TIAA.
      Income taxes. The provision for income taxes increased to $10.2 million for 2004 from $571,000 for 2003. The increase was primarily the result of an increase in income from a full year of operation at our Aurora Facility, which commenced operations in December 2003. The income tax provision of $10.2 million for 2004 differs from the computed expected tax expense of $8.7 million determined by applying the U.S. federal income tax rate to pretax income, primarily as a result of the increase in income taxes of $1.2 million relating to nondeductible expenses for the increase in value of the put warrant and $380,000 relating to the loss from nontaxable consolidated subsidiaries.
      Minority interest. Minority interest in net loss of subsidiary was $100,000 for 2004, which related to the minority interest portion of start up expenses of our Fort Dodge Facility.
Fluctuations in Quarterly Results and Seasonality
      The following table presents our unaudited quarterly results of operation for our last four completed fiscal quarters.
                                   
    Three Months Ended
     
    March 31,   June 30,   September 30,   December 31,
    2005   2005   2005   2005
                 
    (in thousands, except per share data)
    (unaudited)
Total revenues
  $ 44,852     $ 34,410     $ 56,990     $ 100,107  
Gross profit (loss)
    6,171       (1,516 )     6,666       24,215  
Net income (loss)
    1,686       (3,910 )     (205 )     2,682  
Earnings (loss) per common share
                               
 
Basic
  $ 0.04     $ (0.09 )   $     $ 0.05  
 
Diluted
    0.04       (0.09 )           0.05  

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      Our quarterly operating results may fluctuate significantly as a result of a variety of factors. See “Risk Factors—Risks Relating to Our Business.” Our quarterly operating results are influenced by seasonal fluctuations in the price of our primary operating inputs, corn and natural gas, and the price of our primary product, ethanol. The spot price of corn tends to rise during the spring planting season in May and June and tends to decrease during the fall harvest in October and November. The price for natural gas, however, tends to move opposite that of corn and tends to be lower in the spring and summer and higher in the fall and winter. In addition, our ethanol prices are substantially correlated with the price of unleaded gasoline especially in connection with our indexed, gas-plus sales contracts. The price of unleaded gasoline tends to rise during each of the summer and winter.
      As a result of quarterly and seasonal fluctuations, we believe comparisons of operating measures between quarters is not as meaningful as comparisons between longer periods and should not be relied on as indicators of our future performance. See Note 18 to the Consolidated Financial Statements.
Hedging and Other Price Mitigation Strategies
      We seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn requirements on a fixed price basis and by purchasing corn and natural gas futures contracts. To mitigate ethanol price risk, we sell a portion of our production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract such as unleaded gasoline on the 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, but will also reduce our ability to benefit from favorable changes in prices.
      A substantial number of our ethanol sales contracts are based on six-month contracting periods, typically April 1 through September 30 and October 1 through March 31 of each year. These six-month contracts are typically entered into months before the contract commences, so that April 1 through September 1 contracts often are entered into during the winter and October 1 through March 31 contracts are often entered into during the summer. Our raw materials purchases are forecasted to take into account our expected production of ethanol.
      During 2005, approximately 49% of our ethanol sales were made under fixed price contracts, 14% under indexed contracts and 37% at spot prices. As of December 31, 2005, approximately 19% of our estimated ethanol production for 2006 was subject to fixed price contracts, and we had contracted forward on a fixed price basis the following quantities of corn and natural gas, which represent the indicated percentages of our estimated requirements for these inputs for 2006:
                 
    Year Ending December 31, 2006
     
    Quantity   Percentage of Estimated Requirements
         
Corn (thousands of bushels)*
    21,565     26%    
Natural gas (MMBTU)
    500,000     6%    
 
Represents our net corn position, which includes exchange-traded futures and forward purchase contracts. Changes in the value of these contracts are recognized in current period income. See “ — Summary of Critical Accounting Policies and Estimates — Derivative instruments and hedging activities.”
      As of December 31, 2005, far higher percentages of our forward ethanol sales and our corn and natural gas purchase requirements for 2006 were subject to fixed price arrangements in the first quarter of 2006 than in the remainder of 2006. The extent to which we enter into these arrangements during the year may vary substantially from time to time based on a number of factors, including supply and demand factors affecting the needs of customers or suppliers to purchase ethanol or sell us raw materials on a fixed basis, our views as to future market trends, seasonal 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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Liquidity and Capital Resources
      Our principal sources of liquidity consist of cash and cash equivalents, cash provided by operations and available borrowings under our Credit Agreement. In addition to funding operations, our principal uses of cash have been, and are expected to be, the debt service requirements of our indebtedness, the construction of new facilities, capital expenditures and general corporate purposes.
      We financed our operations for 2005 primarily through cash provided by financing activities. At December 31, 2005, we had total cash and cash equivalents of $29.7 million compared to $10.3 million at December 31, 2004. Cash used in operating activities was $2.5 million for 2005 compared to cash provided by operating activities of $20.9 million for 2004. The change in operating cash flow was primarily a result of the costs associated with the construction and start up activities at our Fort Dodge Facility and prepayment costs associated with the early retirement of debt.
      Cash used in investing activities was $212.1 million for 2005 compared to $25.2 million for 2004. The increase primarily resulted from our $125.0 million investment in restricted cash, due to the transfer of some of the proceeds from our senior secured notes offering into an escrow account primarily relating to the construction of our Charles City Facility, and $87.1 million of purchases of property and equipment primarily related to the construction costs of our Fort Dodge Facility.
      Cash provided by financing activities was $234.0 million for 2005 compared to $14.6 million for 2004. The increase primarily resulted from the proceeds to us of $90.1 million from the sale of 17,500,000 shares of common stock and $208.7 million from the issuance of our $210.0 million senior secured notes, partially offset by principal payments on long-term debt of $58.9 million.
      As of December 31, 2005, we had total debt of $210.0 million, before $1.3 million of unaccreted debt discount. In addition, we had total borrowing capacity of $24.1 million under our Credit Agreement. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $21.4 million of remaining borrowing capacity at December 31, 2005.
      Our financial position and liquidity are, and will be, influenced by a variety of factors, including:
  our ability to generate cash flows from operations;
 
  the level of our outstanding indebtedness and the interest we are obligated to pay on this indebtedness; and
 
  our capital expenditure requirements, which consist primarily of plant construction and the purchase of equipment.
      We intend to fund our principal liquidity requirements through cash and cash equivalents, cash provided by operations and, if necessary, borrowings under the Credit Agreement. We believe our sources of liquidity will be sufficient to meet the cash requirements of our operations for at least the next twelve months.
      To finance any material acquisitions or joint ventures, expand our operations or make additional capital expenditures, however, we may need to seek additional sources of funding, including from the issuance of additional equity or debt. Acquisitions or further expansion of our operations could cause our indebtedness, and our ratio of debt to equity, to increase. Our ability to access these sources of capital is restricted by the indenture governing the senior secured notes and the terms of the Credit Agreement.
      Capital Expenditures. We expect to make capital expenditures of approximately $150.0 million and $255.0 million in 2006 and 2007, respectively, primarily for construction of our Charles City, Northwestern Iowa and Welcome facilities.
      The Credit Agreement. On December 21, 2005, in connection with, and as a condition to, the offering of our senior secured notes, we entered into a $30.0 million borrowing base operating line of credit, with a $10.0 million sublimit for letters of credit, with First National Bank of Omaha, for general corporate purposes. Our obligations under the Credit Agreement are guaranteed by all of our existing and future ethanol production subsidiaries and are secured by a first priority lien on all of our and certain of our subsidiaries’

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accounts receivable, inventory and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which the proceeds are deposited). Borrowings under the Credit Agreement bear interest at LIBOR plus the applicable margin, which initially was 3.0%. In addition to paying interest on the outstanding principal under the Credit Agreement, we are also required to pay a commitment fee to First National Bank of Omaha in respect of unused loan commitments at an initial rate of 0.25%. The interest rate and the commitment fee are subject to adjustment based on our working capital levels. The Credit Agreement contains customary covenants, including minimum tangible net worth, working capital requirements and negative pledges. The Credit Agreement also contains certain customary events of default including defaults based on cross-defaults to other material indebtedness. The Credit Agreement matures on December 31, 2008. As of February 28, 2006, there was no outstanding balance and $26.9 million was available to borrow under the Credit Agreement. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $24.2 million of remaining borrowing capacity at February 28, 2006.
      Charles City Facility construction. We are using $125.0 million of the net proceeds from the issuance of our senior secured notes completed in December 2005 to finance construction and start up costs for our Charles City Facility. We commenced construction of our Charles City Facility in March 2006 and expect the project to be completed in July or August of 2007.
      Construction of Northwestern Iowa and Welcome Facilities. Using the net proceeds of this offering, together with cash generated from operations, we expect to use approximately $140.0 million to finance the construction of our planned Northwestern Iowa Facility and approximately $140.0 million to finance the construction of our planned Welcome Facility. Depending on where we first acquire all the necessary permits, we expect to begin construction at either our Northwestern Iowa or Welcome site in the third quarter of 2006, with operations commencing at that site by the end of the first quarter of 2008. We plan to begin construction on the other facility in the fourth quarter of 2006, with operations commencing at that site by the end of the first quarter of 2008.
Off-Balance Sheet Arrangements
      We have no off-balance sheet arrangements.
Contractual Obligations
      The following summarizes our contractual obligations as of December 31, 2005. Our obligations are likely to increase significantly as we enter into agreements in connection with the construction of our Charles City Facility, our Northwestern Iowa Facility and our Welcome Facility.
                                                           
Type of Obligation   2006   2007   2008   2009   2010   Thereafter   Total
                             
Long-term debt obligations(1)
  $ 20,813     $ 20,813     $ 20,813     $ 20,738     $ 20,738     $ 251,476     $ 355,391  
Operating lease obligations
    3,060       2,922       2,824       2,824       2,824       11,176       25,630  
Purchase obligations(2)
    3,376       3,383       3,390       2,756       2,458       11,508       26,871  
Other purchase obligations(3)
    61,214       9,287                               70,501  
                                           
 
Total contractual obligations
  $ 88,463     $ 36,405     $ 27,027     $ 26,318     $ 26,020     $ 274,160     $ 478,393  
                                           
 
(1)  Amounts represent principal and interest payments due on the senior secured notes and unused commitment fees under the 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, 2005 published bid prices for corn.

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Quantitative and Qualitative Disclosures about Market Risk
      We consider market risk to be the potential loss arising from adverse changes in market rates and prices. We are subject to significant market risk with respect to the price of ethanol, our principal product, and the price and availability of corn, the principal commodity used in our ethanol production process. In general, ethanol prices are influenced by the supply and demand for gasoline, the availability of substitutes and the effect of laws and regulations. Higher corn costs result in lower profit margins and, therefore, represent unfavorable market conditions. Traditionally, we have not been able to pass along increased corn costs to our ethanol customers. The availability and price of corn are subject to wide fluctuations due to unpredictable factors such as weather conditions during the corn growing season, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture, and international supply and demand. Corn costs represented approximately 49.5% of our total cost of goods sold for 2005. Over the ten-year period from 1996 through 2005, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $5.48 per bushel in 1996, with prices averaging $2.47 per bushel during this period. At December 30, 2005, the CBOT price per bushel of corn was $2.16.
      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 represented 18.5% of our cost of goods sold for 2005. The price fluctuation in natural gas prices over the six-year period from December 31, 1999 through December 28, 2005, based on the NYMEX daily futures data, has ranged from a low of $2.34 per MMBTU in 2000 to a high of $13.91 per MMBTU for 2005, averaging $5.25 per MMBTU during this period. At December 30, 2005, the NYMEX price of natural gas was $11.23 per MMBTU.
      We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our corn and natural gas requirements, ethanol contracts and the related exchange-traded contracts for 2005. Market risk is estimated as the potential loss in fair value, resulting from a hypothetical 10.0% adverse change in the fair value of our corn and natural gas requirements and ethanol contracts (based on average prices for 2005) net of the corn and natural gas forward and futures contracts used to hedge our market risk with respect to our corn and natural gas requirements. The results of this analysis, which may differ from actual results, are as follows:
                                 
            Hypothetical    
            Adverse    
    Volume       Change in   Change in Annual
    Requirements   Units   Price   Pre-Tax Income
                 
    (in millions)           (in millions)
Corn
    46.8       bushels       10.0 %   $ (9.9 )
Ethanol
    126.3       gallons       10.0 %     (20.0 )
Natural Gas
    4.1       MMBTU       10.0 %     (3.7 )
      We are also subject to interest rate risk in connection with our senior secured notes and borrowings under our Credit Agreement. Generally, the fair market value of fixed interest rate debt, such as our senior secured notes, will increase as interest rates fall and decrease as interest rates rise. The estimated fair value of our long-term fixed interest rate debt at December 31, 2005 was $213.2 million, compared to its $208.7 million carrying value. Fair values were determined from quoted market prices.
      Borrowings under the Credit Agreement bear interest at LIBOR plus the applicable margin, which initially was 3.0%. In addition to paying interest on the outstanding principal under the Credit Agreement, we are also required to pay a commitment fee to First National Bank of Omaha in respect of unused loan commitments at an initial rate of 0.25%. The interest rate and the commitment fee are subject to adjustment based on our working capital levels. Although we had $2.7 million in letters of credit outstanding, there were no borrowings outstanding under the Credit Agreement at February 28, 2006, and so a hypothetical increase in interest rates of 100 basis points would not have a material effect on our annual interest expense.

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Summary of Critical Accounting Policies and Estimates
      Our discussion and analysis of our financial condition and results of operations are based on the consolidated financial statements included in this prospectus, which have been prepared in conformity with generally accepted accounting principles in the United States. Note 1 to the Consolidated Financial Statements for 2003, 2004 and 2005 included in this prospectus contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. Accounting estimates are an integral part of the preparation of financial statements and are based upon management’s current judgment. The process used by management encompasses its knowledge and experience about past and current events and certain assumptions on future events. The judgments and estimates regard the effects of matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We believe that of our significant accounting policies, the following are noteworthy because changes in these estimates or assumptions could materially affect our financial position and results of operations.
      Revenue recognition. Revenue from the production of ethanol and its co-products is recorded when title transfers to customers. Ethanol and its co-products are generally shipped FOB our plants. Transportation costs incurred are recorded as a component of cost of goods sold. In accordance with our marketing agreement with Aventine, sales are recorded net of commissions retained by Aventine at the time payment is remitted.
      Derivative instruments and hedging activities. Derivatives are recognized on the balance sheet at their fair value. On the date the derivative contract is entered, we may designate the derivative as a hedge of a forecasted transaction or for the variability of cash flows to be received or paid related to a recognized asset or liability, which we refer to as a “cash flow” hedge. Changes in the fair value of derivatives that are highly effective as, and that are designated and qualify as, a cash flow hedge are recorded in other comprehensive income, net of tax effect, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable rate asset or liability are recorded in earnings). Effectiveness is measured on a quarterly basis, using the cumulative dollar offset method.
      To reduce price risk caused by market fluctuations, we generally follow a policy of using exchange traded futures contracts to reduce our net position of merchandisable agricultural commodity inventories and forward cash purchase and sales contracts and use exchange traded futures contracts to reduce price risk under fixed price ethanol sales. Forward contracts, in which delivery of the related commodity has occurred, are valued at market price with changes in market price recorded in cost of goods sold. Unrealized gains and losses on forward contracts, in which delivery has not occurred, are deemed “normal purchases and normal sales” under Financial Accounting Standards Board Statement No. 133, as amended, unless designated otherwise, and therefore are not marked to market in our financial statements.
      When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with subsequent changes in its fair value recognized in current-period income. Effective September 1, 2005, we de-designated all of our exchange traded futures contracts related to our corn positions.
      Put warrant. The value of the warrant is adjusted periodically to the formula-based put value of the warrant. An independent third party financial advisor provided the valuation at December 31, 2005 of the underlying common stock which was used in the formula based value. Changes in the value of the warrant are recognized on the balance sheet in the period of change and included in our statement of income as interest expense. Upon the closing of this offering, interest expense will include an adjustment of $           million based on an assumed initial public offering price of $          per share to adjust the outstanding put warrant to the initial public offering price of our common stock. The put feature is not expected to affect our earnings thereafter because it is expected to be terminated upon the completion of this offering. Upon completion of this offering, it is expected that the long-term liability associated with the put warrant, increased as described above, will be reclassified into shareholders’ equity so that the net impact on our shareholders’ equity will be an increase of $7.5 million. See “Description of Capital Stock — Put Warrant.”

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      Stock-based compensation. We account for stock-based compensation in accordance with Accounting Principles Board, or APB, Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. No stock-based employee compensation is 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, based on our discounted cash flow analysis and review of stock valuations for comparable companies. Stock-based compensation is recognized in connection with the issuance of variable performance-based stock options and restricted stock.
      We have implemented Statement of Financial Accounting Standards No. 123R “Share-based Payment,” or SFAS 123R, as of January 1, 2006 using the modified prospective transition method. SFAS 123R supersedes APB Opinion No. 25 and requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. See Note 1 to our Consolidated Financial Statements. The effect of our adoption of SFAS 123R on our results of operations cannot be predicted at this time, because it will depend on levels of share-based payments granted in the future and other factors. We do expect, however, that we will have compensation expense in future periods relating to option grants to our officers, directors and employees, which may affect the comparability of our 2006 results with prior periods.
      In connection with the completion of this offering, options and warrants to purchase 4,338,408 shares of our common stock will immediately vest, resulting in a non-cash charge of $           million that will be recorded as stock-based compensation expense in the period in which this offering is completed.
Inflation
      Since our inception, inflation has not significantly affected our operating results. However, costs for construction, taxes, repairs, maintenance and insurance are all subject to inflationary pressures and could affect our ability to maintain our facilities adequately, build new ethanol production facilities and expand our existing facilities.

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BUSINESS
Overview
      VeraSun Energy Corporation is the second largest ethanol producer in the U.S. based on production capacity, according to the RFA. We are also the largest “pure-play” ethanol producer, focusing primarily on the production and sale of ethanol and its co-products. This focus has enabled us to significantly grow our ethanol production capacity and to work with automakers, fuel distributors, trade associations and consumers to increase the demand for ethanol. As an industry leader, we play an active role in developments within the renewable fuels industry.
      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 140 billion gallons in 2005 according to the 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 20% from 2000 to 2005. We believe the ethanol market will continue to grow as a result of its favorable production economics relative to gasoline, ethanol’s clean burning characteristics, a shortage of domestic petroleum refining capacity, geopolitical concerns, and federally mandated renewable fuel usage. We also believe that E85, a fuel blend composed primarily of ethanol, will become increasingly important over time as an alternative to unleaded gasoline.
      We own and operate two of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 230 MMGY. As of January 1, 2006, our ethanol production capacity represented approximately 5% of the total ethanol production capacity in the U.S., according to the RFA. We expect to operate three facilities with an aggregate production capacity of 340 MMGY by the end of August 2007 and five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008.
      Our facilities operate on a continuous basis and utilize 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 WDGS and DDGS as ethanol co-products, which serve to partially offset our corn costs. In 2005, we produced approximately 128.0 million gallons of fuel ethanol and 402,000 tons of distillers grains, reflecting a full year of operations at our Aurora Facility and less than three months of operations at our Fort Dodge Facility.

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      Our Aurora Facility commenced operations in December 2003, and our Fort Dodge Facility commenced operations in October 2005. We have commenced construction of our Charles City Facility, and we expect to begin operations there in July or August of 2007. The table below provides an overview of our ethanol plants that are in operation or under construction as of March 2006.
             
    Aurora Facility   Fort Dodge Facility   Charles City Facility(1)
             
Location
  Aurora, South Dakota   Fort Dodge, Iowa   Charles City, Iowa
Year completed or scheduled to be completed
  2003 (expansion 2005)(2)   2005   2007
Annual ethanol capacity (in millions of gallons)
  120   110   110(3)
Ownership
  100%   100%   100%
Production process
  Dry-Milling   Dry-Milling   Dry-Milling
Primary energy source
  Natural Gas   Natural Gas   Natural Gas
Estimated distillers grains production (dry) per year
  390,000 tons   350,000 tons   350,000 tons
Estimated corn processed per year
  43 million bushels   39 million bushels   39 million bushels
Corn grown during 2004-2005 crop year within a 60-mile radius
  325 million bushels   598 million bushels   563 million bushels
 
(1)  Construction of our Charles City Facility commenced in 2006 and is being funded primarily with $125.0 million of the net proceeds from the sale of senior secured notes in December 2005.
(2)  In June 2005, our Aurora Facility was expanded from a production capacity of 100 MMGY to 120 MMGY.
(3)  Estimated upon completion of construction of our Charles City Facility.
     We plan to grow our ethanol production capacity significantly over the next several years. We are developing the following two sites:
  Northwestern Iowa Facility: We have options to purchase approximately 440 acres near Hartley, Iowa and approximately 440 acres near Everly, Iowa. We intend to begin construction of a 110 MMGY ethanol production facility at one of these sites, but not at both, based on a final siting decision, in the latter half of 2006. We expect that our Northwestern Iowa Facility will be completed by the end of the first quarter of 2008.
 
  Welcome Facility: The City of Welcome, Minnesota recently exercised options on our behalf to purchase approximately 370 acres near Welcome, Minnesota. We plan to begin construction of a new 110 MMGY ethanol production facility at this site in the latter half of 2006. We expect that our Welcome Facility will be completed by the end of the first quarter of 2008.
      We expect to finance the construction costs of our Northwestern Iowa Facility and our Welcome Facility with the net proceeds we receive from this offering and from our cash flow from operations. Depending on where we first acquire all the necessary permits, we expect to begin construction at either our Northwestern Iowa or Welcome site in the third quarter of 2006. We plan to begin construction at the other site in the fourth quarter of 2006. We intend to replicate our successful construction and production processes at these additional facilities.
      For the year ended December 31, 2005, our total revenues, EBITDA and net income were $236.4 million, $29.9 million and $253,000, respectively, reflecting a full year of operations at our Aurora Facility and less than three months of operations at our Fort Dodge Facility. See “Summary Consolidated Financial and Operating Data” for a discussion of the reconciliation of net income to EBITDA. See Note 17 to the Consolidated Financial Statements for a description of our business segments.

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Recent Developments
  In February 2006, VeraSun and General Motors announced a collaborative partnership to promote the awareness and use of E85 in FFVs and the installation of VE85tm fuel pumps at 20 service stations in the Chicago area. In March 2006, we announced that we are adding VE85tm fuel pumps at 14 service stations in the Minneapolis area.
 
  In February 2006, Ford announced the creation of a Midwest ethanol corridor through the planned conversion of fuel pumps to VE85tm in Illinois and Missouri. This plan is part of the initiative announced in November 2005 by Ford and VeraSun to raise awareness of the benefits of VE85tm and to expand the VE85tm distribution infrastructure.
 
  In February 2006, we acquired options to purchase approximately 440 acres of land near Hartley, Iowa and approximately 440 acres of land near Everly, Iowa as potential sites for the construction of our Northwestern Iowa Facility. In addition, the City of Welcome, Minnesota recently exercised options on our behalf to purchase land in Welcome for construction of our Welcome Facility.
 
  In March 2006, we commenced construction of our Charles City Facility, which is being funded primarily with a portion of the net proceeds from our issuance of senior secured notes in December 2005.
Competitive Strengths
      Our competitive strengths include the following:
        Industry leadership. We have established a leadership position within the renewable fuels industry by being the first company to:
  develop new, large-scale 100 MMGY or greater dry-mill ethanol facilities in an industry primarily composed of smaller-scale dry-mill facilities with capacities below 50 MMGY;
 
  design and site ethanol production facilities to strategically utilize unit trains as a means of reducing transportation costs and delivery cycle times; and
 
  create the only branded E85 fuel, VE85tm, and enter into strategic relationships with major automakers to increase awareness and availability of E85.
        We were also among the first ethanol producers to access the institutional capital markets to finance our growth strategy. As a result, the construction costs for our Charles City Facility construction are being funded primarily with a portion of the net proceeds from our $210.0 million senior secured notes offering completed in December 2005.
 
        As an industry leader focused solely on the ethanol industry, we have cultivated strong relationships with leading automakers, and engineering and construction firms. In addition, working with the RFA, NEVC and other industry trade groups, as well as key leaders from the oil industry, we actively participated in efforts leading to the passage of the RFS. Donald L. Endres, our Chief Executive Officer and our majority shareholder, serves on the board of directors and executive committee of the RFA, and William L. Honnef, our Senior Vice President, Sales and Marketing, serves on the board of directors of the NEVC. We believe our involvement with these two leading ethanol trade organizations provides us strategic insights into the industry. In the future, we believe our leadership and position in the ethanol industry will allow us to further develop market advantages and continue to shape both the industry and consumer markets.
 
        Low-cost operator. We believe our facilities provide us with an efficient cost structure for ethanol production. Our low cost operations are the result of our:
  Strategic locations. Each of our facilities is located near abundant, low-cost corn supplies with direct or indirect access to multiple rail carriers. Access to competing rail transportation reduces our delivery costs and enables us to access favorably-priced corn from other regions of the

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  country. These locational attributes also permit us to respond rapidly to changes in market supply and demand.

  Modern technology. We use the latest production technology, resulting in lower operating costs and more efficient conversion of corn to ethanol than older plants that use older technology. We believe our efficient energy systems and heat recovery technology require relatively less energy than older dry-mill ethanol plants. In addition, we believe that our advanced computer control systems and process automation increase our facilities’ operating rate, energy efficiency and product quality.
 
  Scale of facilities. According to the RFA, the average U.S. ethanol production facility capacity in 2005 was 45 MMGY. By comparison, our existing and planned facilities are each designed to have capacity of at least 110 MMGY of ethanol. As a result of the volume of our production and our access to multiple rail carriers, we are able to utilize unit trains to ship our finished ethanol product more efficiently. Our relatively large facilities are designed to store up to 30 days of corn, which allows us to take advantage of attractive corn purchasing opportunities. The available land at our existing facilities also provides for possible future expansion.
 
  Substantial production capacity. Our current production capacity is 230 MMGY, and is expected to increase to 340 MMGY by the end of 2007 and to 560 MMGY by the end of the first quarter of 2008. We believe our scale allows us to market and distribute our ethanol more efficiently and to manage our business more effectively than many other producers who operate individual or smaller facilities. In addition, we can deliver large quantities of ethanol to satisfy all or a large portion of our customers’ ethanol requirements.
 
  Construction and development experience. We believe our expertise and involvement in constructing and developing low cost, large facilities allow us to complete new construction and expansion projects more efficiently than many of our smaller competitors, whom we believe are not as involved in the design and construction process and typically contract for more costly “turn-key” facilities. We constructed our Aurora Facility five months ahead of schedule and 12% under budget and our Fort Dodge Facility three months ahead of schedule and within budget. In June 2005, we also successfully increased the production capacity of our Aurora Facility from 100 MMGY to 120 MMGY in under three weeks and at approximately one-third of the per gallon cost of building a new facility. We have operated our Aurora Facility and our Fort Dodge Facility at efficient levels with an excellent safety record. We believe we can replicate our success at our Charles City Facility and at our additional planned facilities.
        VE85™ branded ethanol fuel. We believe VeraSun’s branded VE85tm fuel gives us a significant advantage over our competitors in the market for E85. E85, a fuel blend composed of up to 85% ethanol, is used in FFVs. According to the NEVC, as of the end of the 2005 model year, 6.0 million FFVs capable of accepting VE85tm were in use in the U.S., including automobiles manufactured by Ford, DaimlerChrysler AG, General Motors, Isuzu Motors Limited, Mazda Motor Corporation and Nissan Motor Co., Ltd. We believe the number of FFVs will increase over the next several years. We recently entered into arrangements with Ford and General Motors to increase the number of VE85tm fuel pumps in various locations such as Chicago, Illinois and Minneapolis, Minnesota, which will enable us to expand our direct channel of branded fuel into the marketplace. Our VE85tm brand, the related marketing program and our strategic automotive and industry relationships offer comprehensive assistance to fuel retailers with fuel pump installations and conversions and also build consumer awareness to increase retail sales.
 
        Experienced and proven management team. Our management team, led by our chief executive officer and majority shareholder, Donald L. Endres, has extensive experience in the ethanol industry, and its core members have worked together successfully for over ten years. Our senior project management and operations executives, together with our two facility managers, have an average of over 20 years of experience in process operations in the ethanol, energy and chemical industries.

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Business Strategy
      Our objective is to maintain our leading market position in the U.S. renewable fuels industry and to continue to realize efficiencies in ethanol production. Key elements of our strategy to achieve this objective include:
        Add low-cost production capacity. We intend to capitalize on the growing U.S. demand for ethanol by expanding our production capacity rapidly over the next several years. We are focused on the development and construction of our Charles City Facility, our Northwestern Iowa Facility and our Welcome Facility. In pursuing our expansion strategy, we seek to build on the success of our operating facilities, continue to build large-scale facilities, leverage proven facility design, incorporate technology improvements and continue to locate facilities with access to multiple rail services. Using similar facility designs enables us to lower our costs relating to spare parts and to take advantage of our operations experience at our other facilities. We expect to operate three facilities with an aggregate production capacity of 340 MMGY by the end of August 2007 and to have five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008.
  •       Continue to focus on cost efficiency. We plan to continue to take advantage of our large production capacity and greater economies of scale to become more energy efficient and increase yield. We will also continue to use our on-site corn storage facilities to purchase corn during peak supply periods to reduce our corn costs. We intend to reduce our per-unit transportation costs by making greater use of unit trains to ship our finished ethanol and distillers grains products. We are also evaluating the benefits of expanding one or more of our existing facilities to take further advantage of economies of scale.
 
  •       Explore alternative technologies. We are studying the costs and feasibility of implementing biomass combustion systems at our facilities. These systems should allow us to reduce our energy costs by using biomass, such as switchgrass, straw, corn stover and other fibrous materials, as a substitute energy source in place of natural gas. Our research indicates that biomass combustion could potentially produce a majority of the energy needed to operate our facilities, thereby significantly reducing our reliance on natural gas. We are evaluating the capital costs and engineering challenges associated with implementation of biomass combustion.
  We have also conducted research and testing on extracting corn oil during the ethanol production process and selling corn oil or using it to produce biodiesel, a clean burning alternative fuel that can be used in diesel engines with petroleum diesel to lower emissions and improve lubricity. If we are able to improve corn oil extraction recovery rates, we may be able to produce biodiesel economically, which would increase the value of our co-products. We are still conducting research and development in this area.
  •       Expand market demand for ethanol. We plan to create additional demand for ethanol by continuing to work with refiners and blenders to introduce ethanol into new markets. We will also continue to pursue the development of partnerships to market VE85tm and expand the availability of VE85tm fuel with a variety of industry participants, including major automakers, such as those developed with Ford and General Motors; independent gasoline marketers, such as those developed with Erickson Oil Products, Inc., Olson Oil Co. and Gas City Ltd.; and other entities, such as the NEVC, the RFA, various corn grower groups, and state and federal agencies.
 
  •       Continue to use price mitigation strategies. 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 purchasing corn and natural gas futures contracts. To mitigate ethanol price risk, we sell a portion of our production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract such as unleaded gasoline on the NYMEX, and we may hedge a portion of the price risk associated with index contracts by selling exchange-traded

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  unleaded gasoline contracts. We believe our strategy of managing exposure to commodity price fluctuations reduce somewhat the volatility of our results.
 
  •       Pursue potential acquisition opportunities. We believe that opportunities for expansion of our business through industry acquisitions will arise as the ethanol industry matures. We evaluate opportunities to acquire additional ethanol production, storage or distribution facilities and related infrastructure. In addition to operational production facilities, we may also seek to acquire potential facility sites under development.

Industry Background and Market Opportunity
      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 140 billion gallons in 2005 according to the EIA. Refiners and marketers have historically blended ethanol with gasoline to increase octane and reduce tailpipe emissions. According to the RFA, 4.0 billion gallons of ethanol were produced in the U.S. in 2005, accounting for approximately 3% of the U.S. gasoline fuel supply. According to the RFA, total U.S. ethanol production capacity increased to more than 4.3 BGY in 2005. The substantial majority of U.S. fuel ethanol produced in 2005 was used as an additive to gasoline. According to the U.S. Department of Energy, refiners typically blend ethanol at 5.7% to 10.0% of volume in over 30% of the U.S. gasoline fuel supply. Ethanol is also used as the primary blend component for E85, a fuel blend composed of up to 85% ethanol. Although E85 represented substantially less than 1% of the U.S. gasoline supply in 2005, approximately 6.0 million vehicles on the road in the U.S. today are FFVs. Ethanol blends of up to 10% are approved for use under the warranties of all major motor vehicle manufacturers and are often recommended as a result of ethanol’s clean burning characteristics. In addition, all major manufacturers of power equipment, motorcycles, snowmobiles and outboard motors permit the use of ethanol blends in their products. The primary uses of ethanol are:
        Octane enhancer. On average, regular unleaded gasoline has an octane rating of 87 and premium unleaded has an octane rating of 91. In contrast, pure ethanol has an average octane rating of 113. Adding ethanol to gasoline enables refiners to produce greater quantities of lower octane blend stock with an octane rating of less than 87. Ethanol is typically added to the lower octane stock at the wholesale terminal as the final step before the gasoline is delivered to the retail station. By adding ethanol, the refiner or blender is able to increase the octane rating of the blend stock so that it conforms to gasoline standards, while also expanding the volume of fuel to be sold. Therefore, the refiner benefits from the ability to produce more fuel from a given barrel of oil and expands its ability to meet consumer demand, especially during times when refinery capacity and octane sources are limited. In addition, ethanol is commonly added to finished regular grade gasoline at the wholesale terminal as a means of producing higher octane midgrade and premium gasoline.
 
        Clean air additive. A clean air additive is a substance that, when added to gasoline, reduces tailpipe emissions, resulting in improved air quality characteristics. Ethanol contains 35% oxygen, approximately twice that of MTBE, an alternative oxygenate to ethanol, the use of which is being phased out. The additional oxygen in the ethanol results in more complete combustion of the fuel in the engine cylinder. This in turn results in reduced tailpipe emissions by as much as 30%, including a 12% reduction in volatile organic compound emissions when blended at a 10% level. Ethanol also displaces the use of some gasoline components like benzene, a known carcinogen. Ethanol is non-toxic, water soluble and quickly biodegradable.
 
        Valuable blend component. In addition to its performance and environmental benefits, ethanol is used to extend fuel supplies. As the U.S. need for automotive fuel increases and the U.S. dependence on foreign crude oil and refined products grows, the U.S. is increasingly seeking domestic sources of fuel. Much of the ethanol blending throughout the U.S. today is done for the purpose of extending the volume of fuel sold at the gas pump.
 
        E85, a gasoline alternative. Ethanol is the primary blend component in E85. The number of service stations that sell E85 has grown rapidly. As of February 2006, the U.S. Department of Energy stated that

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  over 500 service stations in the U.S. sell E85. Vehicles must be specially equipped to use E85 fuel. According to the NEVC, approximately 6.0 million U.S. vehicles are FFVs. Although E85 represents a small percentage of the motor vehicle fuel used in the U.S., the experience in Brazil suggests that E85 could capture a much greater portion of the U.S. market in the future. According to BBC News, sales of FFVs in Brazil represented more than half of the new vehicles sold in Brazil in 2005. U.S. automakers receive incentives under federal fuel economy standards for producing FFVs. E85 is generally priced lower per gallon than gasoline because most FFVs experience some reduction in mileage when running on E85.

Demand for Ethanol
      We believe the ethanol market will grow as a result of favorable economics; the replacement of MTBE; a shortage of domestic petroleum refining capacity; geopolitical concerns; and federally mandated renewable fuel usage. We also believe that E85 will become increasingly important over time as an alternative to unleaded gasoline.
      Favorable production economics relative to gasoline. Ethanol currently represents an economically attractive source of fuel. We believe that our cost of producing a gallon of ethanol is now significantly lower than the cost incurred by refiners to produce a gallon of gasoline.
      Replacement of MTBE. Because of their blend characteristics, availability and cost, ethanol and MTBE were the two primary additives used to meet the Clean Air Act’s oxygenate requirements. Because MTBE could be produced and blended with gasoline at the refinery and transported through a pipeline, it was initially the preferred oxygenate ingredient used by the petroleum industry in most reformulated gasoline. Before 2003, ethanol was used primarily as a fuel extender and octane enhancer, predominantly in the Midwest. In recent years, as a result of health and environmental concerns, 25 states, representing more than half of the MTBE consumed in the U.S., including California, New York and Connecticut, have banned or significantly limited the use of MTBE. Product liability concerns regarding MTBE increased following passage of the Energy Policy Act, which did not contain limitations on product liability claims relating to MTBE use. As a result, refiners are now expediting the phase-out of MTBE nationwide, creating additional demand for ethanol outside of the Midwest. As MTBE is replaced, ethanol is positioned to be the most likely substitute for MTBE because of its favorable production economics, high octane rating and clean burning characteristics.
      Shortage of domestic petroleum refining capacity. According to the EIA, the number of operable U.S. petroleum refineries has decreased from 319 in 1980 to 148 in 2005. Also according to the EIA, while domestic refining capacity has decreased approximately 6% from 1980 to 2005, domestic demand has increased 27% over the same period. The EIA expects growth in refining capacity to average 1.3% per year until 2025, with demand for refined petroleum products growing at 1.5% per year over the same period. Because ethanol is blended with gasoline after the refining process, it directly increases domestic fuel capacity. We believe that domestic fuel refining shortages will result in greater demand for ethanol.
      Geopolitical concerns. The U.S. is increasingly dependent on foreign oil. According to the EIA, crude oil imports represented 65% of the U.S. crude oil supply in 2005 and are estimated to rise to 71% 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, world oil prices topped $70 a barrel at times during 2005 and have averaged above $60 a barrel during 2006. 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. The RFA calculates that in 2004 alone, the use of ethanol reduced the U.S. trade deficit by $5.1 billion by eliminating the need to import 143.3 million barrels of oil.
      Renewable Fuels Standard. In August 2005, President Bush signed the Energy Policy Act establishing the RFS, which eliminated the mandated use of oxygenates and mandates annual use of 7.5 BGY of

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renewable fuels in the U.S. fuel supply by 2012. The RFS requires motor fuels sold in the U.S. to contain in the aggregate the following minimum volumes of renewable fuels in future years:
         
    Renewable Fuel Usage
Year   (in billions of gallons)
     
2006
    4.0  
2007
    4.7  
2008
    5.4  
2009
    6.1  
2010
    6.8  
2011
    7.4  
2012
    7.5  
      We expect this mandate will result in a significant increase in ethanol demand. The rules for implementation of the RFS and the Energy Policy Act are still under development. Although the RFS should provide for growing demand, we believe the actual use of ethanol and other renewable fuels will surpass the mandated requirements, especially in the early years of implementation of the RFS. Additional legislation that we believe affects the demand for ethanol, including the federal tax incentive program, is discussed below under “—Legislation.”
Supply of Ethanol
      Production in the ethanol industry remains fragmented. According to the RFA, while domestic ethanol production increased from 1.7 billion gallons in 1997 to 4.0 billion gallons in 2005, the top five producers accounted for approximately 37% of the industry’s total estimated production capacity as of February 2006. The remaining production generated by more than 50 smaller producers and farmer-owned cooperatives, most with production of 50 MMGY or less. Since a typical ethanol facility can be constructed in approximately 14-18 months from groundbreaking to operation, the industry is able to forecast capacity additions for up to 18 months in the future. As of March 20, 2006, the RFA estimates ethanol facilities with capacity of an aggregate of an additional 2.1 BGY were under construction.
      Although the ethanol industry continues to explore production technologies employing various feedstocks, such as biomass, corn-based production technologies remain the most practical and provide the lowest operating risks. Consequently, most U.S. ethanol is produced from corn grown in Illinois, Iowa, Minnesota, Nebraska and South Dakota, where corn is abundant. In addition to corn, the production process employs natural gas or, in some cases, coal to power the facility and 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 feature 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 being 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 enjoying economies of scale in both construction and operating costs per gallon. The largest ethanol production facilities are wet-mill facilities that have capacities of 200 to 300 MMGY. According to the RFA, 79% of the ethanol production capacity is generated from dry-mill facilities, with only 21% from wet-mill facilities.
      Over half of total U.S. ethanol production is consumed in the east- and west-coast markets, primarily as a result of the stricter air quality requirements in large parts of those markets. The primary means of transporting ethanol from the Midwest to the coasts is by rail transportation. 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

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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 the transportation of ethanol.
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.
(GRAPH)
Source: Renewable Fuels Association (RFA)
      1.     In the dry-mill ethanol process, the corn kernels are first ground into a flour, or “meal,” and mixed with water in cookers to form a 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, 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.

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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 “by-pass protein,” which results in more milk production. It is also used in poultry, swine 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 availability 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 of DDGS 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 with better nutritional characteristics than DDGS because it has not been exposed to the heat of drying. 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.
      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 selling corn oil or using it to produce biodiesel. If we are able to improve corn oil extraction recovery rates, we may be able to produce biodiesel economically, which would increase the value of our co-products. We are still conducting research and development in this area.
Overview of Raw Material Supply, Pricing and Hedging
      We seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn requirements on a fixed price basis and by purchasing corn and natural gas futures contracts. To mitigate ethanol price risk, we sell a portion of our production forward under fixed price and indexed contracts. The indexed contracts are typically referenced to a futures contract such as unleaded gasoline on the 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.
      A substantial number of our ethanol sales contracts are based on six-month contracting periods, typically April 1 through September 30 and October 1 through March 31 of each year. These six-month contracts are typically entered into months before the contract commences, so that April 1 through September 1 contracts often are entered into during the winter and October 1 through March 31 contracts are often entered into during the summer. We do not make raw material purchases in excess of our estimated production needs.
      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 utilize hedging positions in the corn futures market to manage the risk of excessive corn price fluctuations for a portion of our corn requirements.
      For our spot purchases, we post daily corn bids so that corn producers can sell to us on a spot basis. Our fixed-price forward contracts specify the amount of corn, the price and the time period over which the corn is to be delivered. These forward contracts are at fixed prices or prices based on 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

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delayed pricing contracts, producers will deliver corn to the plant, but the pricing for that corn and the related payment will occur at a later date.
      We buy futures positions on the CBOT to hedge a portion of our exposure to corn price risk. In addition, our facilities have significant corn storage capacity. To help protect against potential supply disruptions, we generally maintain inventories of corn at each of our facilities. This corn inventory ranges generally from 10 to 30 days of supply, depending on the time of year, the current market price for corn and other factors.
      Natural gas procurement and hedging strategy. We are subject to market risk with respect to our supply of natural gas that is consumed in the ethanol production process and has historically been subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions and overall economic conditions. Accordingly, we hedge a portion of our exposure to natural gas price risk from time to time by using fixed price or indexed exchange-traded futures contracts.
      Unleaded gasoline hedging strategy. Because some of our contracts to sell ethanol are priced based on the price of unleaded gasoline, we establish from time to time an unleaded gasoline hedge position using exchange-traded futures to reduce our exposure to unleaded gasoline price risk.
Marketing Arrangements
      Ethanol marketing. We have agreements with Aventine for the marketing, billing, receipt of payment and other administrative services for substantially all of the ethanol that we produce at our two facilities. We believe our ethanol constitutes over 35% of the ethanol pool that Aventine manages, which makes us the largest contributor to the pool. Under the terms of the agreements, we sell our ethanol to Aventine for the price at which Aventine resells the ethanol, less costs of distribution and a sales commission.
      On February 15, 2006, we notified Aventine that we will terminate our agreements with it on March 31, 2007. At the expiration of our agreements with Aventine, we intend to market and sell our ethanol directly to blenders, refiners and other end users. Up to this point in the development and expansion of our business, we have used our marketing arrangement with Aventine to pool our ethanol with other producers, allowing us to establish relationships with ethanol buyers seeking large suppliers. We believe our business has become large enough for us to market ethanol directly to customers, giving us the benefits of direct customer contact and control of contract negotiations.
      In connection with marketing and selling our own ethanol, we will need to establish our own marketing, distribution, transportation and storage infrastructure. This will involve obtaining sufficient numbers of railcars and storage depots near our customers and at other strategic locations to ensure efficient delivery of our finished ethanol product. We will also need to hire or outsource a marketing and sales force and logistical and other operational personnel to properly staff our distribution activities. In addition, we expect that our senior management will need to devote a larger portion of their time to the management of sales, marketing and distribution activities.
      We are increasingly seeking to market our VE85tm fuel through arrangements with gas distributors and retailers. We provide the retailers with an array of services, including signage, employee training and other marketing support to assist in this process.
      Distillers grains marketing. We market our distillers grains both nationally and locally through our sales force. Our DDGS is primarily marketed nationally to agricultural customers for use as animal feed. Our WDGS is sold to agricultural customers for use as animal feed. These sales are made pursuant to agreements typically lasting from six to twelve months. We sell more dry distillers grains than wet due to the limited markets for WDGS, which cannot be transported long distances. Our DDGS accounted for 88.4% of our co-product sales for 2005, and our sales of WDGS accounted for 11.6% of our co-product sales for 2005.

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Facilities
      The table below provides an overview as of March 2006 of our existing facilities and our Charles City Facility, which is under construction and anticipated to be completed by July or August of 2007.
             
    Aurora Facility   Fort Dodge Facility   Charles City Facility(1)
             
Location
  Aurora, South Dakota   Fort Dodge, Iowa   Charles City, Iowa
Year completed or scheduled to be completed
  2003 (expansion 2005)(2)   2005   2007
Annual ethanol capacity (in millions of gallons)
  120   110   110(3)
Ownership
  100%   100%   100%
Production process
  Dry-Milling   Dry-Milling   Dry-Milling
Primary energy source
  Natural Gas   Natural Gas   Natural Gas
Estimated distillers grains production (dry) per year
  390,000 tons   350,000 tons   350,000 tons
Estimated corn processed per year
  43 million bushels   39 million bushels   39 million bushels
Corn grown during 2004-2005 crop year within a 60-mile radius
  325 million bushels   598 million bushels   563 million bushels
 
(1)  Construction of our Charles City Facility commenced in 2006 and is being funded primarily with $125.0 million of the net proceeds from the sale of senior secured notes in December 2005.
(2)  In June 2005, our Aurora Facility was expanded from a production capacity of 100 MMGY to 120 MMGY.
(3)  Estimated upon completion of construction of our Charles City Facility.
     Our corporate headquarters building is located in Brookings, South Dakota. In addition, we plan to complete construction of our Northwestern Iowa Facility and our Welcome Facility by the end of the first quarter of 2008.
Site selection criteria and use of experienced engineering and construction firms
      We intend to replicate the successful site location and construction management of our Aurora Facility and our Fort Dodge Facility at our new facilities. Our site location criteria encompass many factors, including proximity of feedstocks and abundant corn supplies, good road and rail access, water, utility availability and space for equipment and truck movement. We site our facilities with direct or indirect access to multiple rail carriers. Other considerations include a qualified labor force, as well as community services that are capable of attracting and retaining top personnel.
      Fagen, Inc. and ICM, Inc., two of the most experienced and well regarded construction and engineering firms in the ethanol industry, designed, engineered and constructed our Aurora and Fort Dodge Facilities and are providing similar services in connection with the construction of our Charles City Facility. In addition, we intend to engage these firms to design, engineer and build our Northwestern Iowa Facility and our Welcome Facility. We collaborate with these firms in the design, engineering and construction of our facilities and we believe our expertise and involvement allow us to complete projects more efficiently than many of our competitors, who we believe are not as involved in the design, engineering and construction process and typically contract for more costly “turn-key” facilities.
Aurora Facility
      Our Aurora Facility commenced operations in December 2003 and was the first new-generation dry-mill ethanol plant built with a production capacity of 100 MMGY. The facility is located in Aurora, South Dakota, on a 420-acre site. We increased the capacity of our Aurora Facility to 120 MMGY in June 2005, and have incorporated the latest process control systems to increase production yields and quality.

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      Capacity. One of the largest ethanol facilities in the U.S. by production, our Aurora Facility processes more than 43 million bushels of corn per year and produces 120 MMGY of ethanol and approximately 390,000 tons of dry distillers grains per year. The facility is designed to operate on a continuous basis. The facility purchases corn from many different suppliers.
      Transportation and logistics. Our Aurora Facility transports ethanol by rail and truck, as needed, and has significant capacity for each form of transportation. Logistics include on-site rail loading and truck loading systems. Depending on relative costs and need, transportation methods can be easily changed. The facility is located on the Dakota, Minnesota & Eastern railway, or DM&E, and in close proximity to U.S. Highway 14 and Interstate 29.
      Rail agreements. We have entered into a rail transportation agreement with the DM&E, pursuant to which the DM&E transports our outbound ethanol shipments and inbound corn and grain shipments at fixed rates, subject to semi-annual adjustment based on a national index of rail costs. This contract does not have stated minimums and terminates on December 31, 2011.
      Energy agreements. We have entered into agreements for the purchase of electricity and natural gas. Our agreement with Sioux Valley Southwestern Electric Cooperative, Inc., or Sioux Valley, provides us with a fixed rate on electric service through December 2008. The agreement requires the payment of a minimum demand charge and the payment of a monthly facilities charge. The agreement may be terminated by Sioux Valley if we fail to make payments, breach any other obligations to Sioux Valley or become the subject of a bankruptcy or insolvency proceeding, and then subsequently fail to cure that default within 10 days.
      Our natural gas transportation agreement with NorthWestern Services Group, Inc., or NorthWestern, provides access to the Northern Border Gas Pipeline. The agreement, which expires in September 2018, requires the payment of a minimum transportation demand charge each year until the required natural gas volume under the contract has been reached. NorthWestern may terminate delivery under the contract if we fail to perform our obligations under the contract, become the subject of a bankruptcy or insolvency proceeding or otherwise become unable to pay our debts as they become due. We generally seek bids for gas supply from a number of parties, including NorthWestern.
Fort Dodge Facility
      Our 110 MMGY Fort Dodge Facility commenced operations in October 2005 and is located four miles west of Fort Dodge, Iowa at the intersection of the Union Pacific and the Chicago Central and Pacific railroads. The facility is located on a 270-acre site, and its layout and operations are similar to our Aurora Facility.
      Capacity. Our Fort Dodge Facility has the capacity to process more than 39 million bushels of corn per year and to produce 110 MMGY of ethanol and approximately 350,000 tons of dry distillers grains per year. The facility is designed to operate on a continuous basis.
      Transportation and logistics. Our Fort Dodge Facility transports ethanol by rail and truck, as needed, and has significant capacity for each form of transportation. Logistics include on-site rail loading and truck loading systems. Depending on relative costs and need, transportation methods can be easily changed. The facility’s location enables efficient delivery to customers by rail or highway.
      Rail agreements. We have entered into operating agreements with the Chicago Central and Pacific Railroad Company, or Chicago Central, and the Union Pacific Railroad Company, or Union Pacific, under which we obtain transportation services. Our agreement with Chicago Central may be terminated at any time by either party upon 60 business days’ prior notice. Our agreement with Union Pacific may be terminated at any time by us with 30 days’ prior notice. Union Pacific may terminate this agreement with 30 days’ prior notice for lack of rail use by our Fort Dodge Facility, an event of default by us that remains uncured for 30 days after receiving notice of the default from Union Pacific and impracticability of performance by Union Pacific.

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      Energy agreements. We have entered into an agreement for the purchase of electricity with MidAmerican Energy Company, or MidAmerican, which provides us with a fixed rate on electric service for a five-year term. The agreement requires that we pay a monthly demand charge based on an electrical demand of 10,000 kWh whether or not we use this amount of electricity. MidAmerican may terminate this agreement if we:
  become the subject of a bankruptcy or insolvency proceeding;
 
  make a general assignment for the benefit of creditors;
 
  are unable to pay our debts; or
 
  commit a material breach of any of the terms or provisions of the contract, and then subsequently fail to cure the default within 10 business days.
      We also have agreements in place for the transportation and delivery of natural gas to our Fort Dodge Facility. Our agreement with MidAmerican provides us with a fixed rate for transportation and delivery of natural gas from the Northern Natural Gas Pipeline Company, or NNG, system to our Fort Dodge Facility for a ten-year term. The agreement requires that we pay the monthly demand charges based on a demand of 10,000 MMBTUs per day whether or not we use this amount of gas. MidAmerican may terminate the contract if we fail to comply with or perform any condition or obligation and then subsequently fail to cure that default within 10 days.
      In addition, we have an agreement with NNG for the transportation of natural gas from various receipt points to the delivery point on the MidAmerican system for a ten-year term. The agreement requires that we pay a minimum monthly demand charge, whether or not we use that amount of gas. We generally seek bids for gas supply from a number of parties, including MidAmerican.
Charles City Facility
      In March 2006, we commenced construction of a 110 MMGY ethanol plant on approximately 370 acres near Charles City, Iowa. Construction is expected to be completed in July or August of 2007. Our Charles City Facility is expected to employ approximately 50 skilled workers, process approximately 39 million bushels of corn per year and produce approximately 110 MMGY of ethanol and 350,000 tons of dry distillers grains per year. Our Charles City Facility is being designed to operate on a continuous basis.
      In choosing the site for our Charles City Facility, we followed the same site selection strategy as we did for our Aurora Facility and our Fort Dodge Facility. We expect our Charles City Facility will transport ethanol and DDGS by rail and truck, as needed, and will have significant capacity for both forms of transportation. Planned logistics include on-site rail loading and truck loading systems. Depending on relative costs, transportation methods can be easily changed. It is located on the Iowa, Chicago and Eastern railway with direct access to the Chicago Central and Pacific railway.
      We expect to enter into contracts with MidAmerican for electricity and NNG for natural gas services for our Charles City Facility.
Northwestern Iowa and Welcome Facilities
      We expect to begin construction of two new 110 MMGY production facilities in 2006; one in Northwestern Iowa and one near Welcome, Minnesota. The City of Welcome, Minnesota recently exercised options on our behalf to purchase 370 acres near Welcome, Minnesota, and we have options to purchase 440 acres in Hartley, Iowa and 440 acres in Everly, Iowa. Because of the effect of a large facility on local infrastructure and corn costs, we will construct a facility either at Hartley or at Everly, Iowa but not at both. We are comparing the advantages of each location and expect to determine the facility site location in the second quarter of 2006.
      We expect to begin construction on our Northwestern Iowa Facility and our Welcome Facility in 2006 and we estimate that we will be able to finance the construction of both of these facilities with proceeds from

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this offering and from cash flow from operations. We expect to begin construction on these two facilities in the latter half of 2006 and to complete them by the end of the first quarter of 2008.
Potential future facility sites, acquisitions and facility expansions
      We continue to monitor our options for expansion of our business as ethanol market demand grows, and we may determine that further ethanol capacity is required. We will determine whether additional sites are suitable for construction of ethanol production facilities in the future. Because the ethanol industry is highly fragmented, we also may consider purchasing ethanol facilities if we believe such acquisitions would enhance our business or our strategic position in the industry. We also intend to evaluate opportunities to acquire additional ethanol storage or distribution facilities and related infrastructure.
      We are also investigating the feasibility of expanding existing facilities to significantly increase their production capacity. Such an expansion would entail constructing additional structures and systems adjacent to an existing facility and integrating certain processes. In connection with such an expansion, we also may install redundant systems to use biomass, such as switchgrass, straw, corn stover and other fibrous materials, as a substitute energy source in place of natural gas. Operating a large-scale, solid-fuel combustion system of this kind would impose significant challenges with respect to federal, state and local environmental and air quality laws and regulations. We would also face challenges in purchasing appropriate quantities of biomass materials from third parties to offset the costs of installing the solid-fuel combustion system. The infrastructure for harvesting, storing and transporting biomass is not well established and thus the acquisition of large quantities of biomass material may not be achieved on a cost-effective basis.
      In addition to these considerations, our analysis will depend greatly upon:
  the projected cost savings from integrated processes and from the use of a solid-fuel combustion system;
 
  the cost of construction and of integration, including the amount of time the facility would cease production to allow system integration; and
 
  the flexibility we would have under our existing debt covenants.
Competition
      The market in which we sell our ethanol is highly competitive. According to the RFA, world ethanol production rose to 12 billion gallons in 2005. Fuel ethanol accounted for 73% of world production. The U.S. and Brazil are the world’s largest producers of ethanol. As of March 20, 2006, industry capacity in the U.S. approximated 4.5 BGY, with an additional 2.1 BGY of capacity under construction. The ethanol industry in the U.S. consists of more than 90 production facilities and is primarily corn based, while the Brazilian ethanol production is primarily sugar cane based.
      We compete with ADM, which has approximately 24% of the production capacity in the U.S., as well as other large producers such as Aventine, which has 3% of the U.S. production capacity, Cargill, which has 3% of the U.S. production capacity, and Abengoa, which has 2% of the U.S. production capacity. The industry is otherwise highly fragmented, with many small, independent firms and farmer-owned cooperatives constituting the rest of the market. We compete with our competitors primarily on a national basis.
      We believe that our ability to compete successfully in the ethanol production industry depends on many factors, including the following principal competitive factors:
  price;
 
  reliability of our production processes and delivery schedule; and
 
  volume of ethanol produced and sold.

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      With respect to distillers grains, we compete with other suppliers (i.e., other ethanol producers) as well as a number of large and smaller suppliers of competing animal feed. We believe the principal competitive factors are price, proximity to purchasers and product quality.
Legislation
      Energy Policy Act. The Energy Policy Act established minimum annual volumes of renewable fuel to be used by petroleum refiners in the fuel supply. The annual requirement grows to 7.5 BGY by 2012. Also, the Energy Policy Act did not provide liability protection to refiners who use MTBE as a fuel additive. Given the extent of the environmental concerns associated with MTBE, we believe that this will serve as a catalyst to hasten the replacement of a significant portion of the remaining MTBE volumes with ethanol in the near future. Finally, the Energy Policy Act removed the oxygenate requirements that were put in place by the Clean Air Act. The Energy Policy Act also included anti-backsliding provisions, however, that require refiners to maintain emissions quality standards in the fuels that they produce, thus providing a source for continued need for ethanol.
      The federal blenders’ credit. First implemented in 1979, the federal excise tax incentive program allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax rate reduction of $0.51 per gallon of ethanol. The incentive program is scheduled to expire in 2010 (unless extended).
      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.
      State legislation banning or significantly limiting the use of MTBE. In recent years, due to environmental concerns, 25 states have banned, or significantly limited, the use of MTBE, including California, Connecticut and New York. Ethanol has served as a replacement for much of the discontinued MTBE volumes and is expected to continue to replace future MTBE volumes that are removed from the fuel supply.
      Federal tariff on imported ethanol. In 1980, Congress imposed a tariff on foreign produced ethanol, made from cheaper sugar cane, 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 tariff is $0.54 per gallon and is scheduled to expire in 2007 (unless extended).
      Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempted 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, we believe imports from the Caribbean region 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.
      Federal farm legislation. The U.S. Department of Agriculture’s, or the USDA’s, Commodity Credit Corporation Bioenergy Program pays cash to companies that increase their purchases of specified commodities, including corn, to expand production of ethanol, biodiesel or other biofuels. Payments are typically $0.20 to $0.30 per gallon of increased capacity and amounts must be refunded if decreases in production levels occur. This program is scheduled to expire on June 30, 2006 (unless extended).
      State incentives. In addition to USDA incentive payments, we also receive an incentive payment from the State of South Dakota to produce ethanol, based on gallons of ethanol produced.
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

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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. We also do not expect to incur material capital expenditures for environmental controls in this or the succeeding fiscal year.
      There is a risk of liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged 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 CERCLA or other environmental laws for all or part of the costs of investigation and/or remediation and for damage 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 these properties. Some of these matters may require us to expend significant amounts for investigation and/or cleanup or other costs. We do not have material environmental liabilities relating to contamination at or from our facilities or at off-site locations where we have transported or arranged for the disposal of hazardous substances.
      In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional significant expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our ongoing operations. Present and future environmental laws and regulations (and related interpretations) applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial capital and other expenditures. Our air emissions are subject to the federal Clean Air Act, the federal Clean Air Act Amendments of 1990 and similar state and local laws and associated regulations. The U.S. EPA has promulgated National Emissions Standards for Hazardous Air Pollutants, or NESHAP, under the federal Clean Air Act that could apply to facilities that we own or operate if the emissions of hazardous air pollutants exceed certain thresholds. If a facility we operate is authorized to emit hazardous air pollutants above the threshold level, then we are required to comply with the NESHAP related to our manufacturing process and would be required to come into compliance with another NESHAP applicable to boilers and process heaters by September 13, 2007. New or expanded facilities would be required to comply with both standards upon startup if they exceed the hazardous air pollutant threshold. In addition to costs for achieving and maintaining compliance with these laws, more stringent standards may also limit our operating flexibility. Because other domestic ethanol manufacturers will have similar restrictions, however, we believe that compliance with more stringent air emission control or other environmental laws and regulations is not likely to materially affect our competitive position.
      The hazards and risks associated with producing and transporting our products, such as fires, natural disasters, explosions, abnormal pressures, blowouts and pipeline ruptures also may 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. Our coverage includes physical damage to assets, employer’s liability, comprehensive general liability, automobile liability and workers’ compensation. We believe that our insurance is adequate and customary for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We do not currently have pending material claims for damages or liability to third parties relating to the hazards or risks of our business.
      See “Risk Factors— Risks Relating to Our Business— We may be adversely affected by environmental, health and safety laws, regulations and liabilities.”
Employees
      As of February 28, 2006, we had approximately 145 full time employees, including approximately 100 in operations and 45 who are responsible for companywide management, marketing, project management, logistics and administration. All of these employees are located in the U.S. None of our employees is covered by a collective bargaining agreement. We have had no labor-related work stoppages, and we believe we have positive relations with our employees.
Legal Proceedings
      As of the date of this prospectus, we are not party to any material pending or threatened legal proceedings.

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MANAGEMENT
Directors and Officers
      The following table sets out the names and ages of each of our officers and directors, followed by a description of their business experience. All positions shown are with VeraSun.
             
Name   Age   Position
         
Donald L. Endres*
    45     Chief Executive Officer and Director
Bruce A. Jamerson*
    54     President and Director
Danny C. Herron*
    51     Senior Vice President and Chief Financial Officer
Paul J. Caudill*
    52     Senior Vice President, Operations
William L. Honnef*
    39     Senior Vice President, Sales and Marketing
Paul A. Schock*
    47     Senior Vice President, Corporate Development and Director
John M. Schweitzer*
    61     Senior Vice President and General Counsel
Kevin T. Biehle
    42     Vice President, Plant Operations
Ginja R. Collins
    31     Vice President, Finance, Treasurer and Secretary
Matthew K.R. Janes
    49     Vice President, Technology
Mark L. First
    41     Director
D. Duane Gilliam
    61     Director
T. Jack Huggins III
    63     Director
Steven T. Kirby
    54     Director
 
     *Executive officer.
     Donald L. Endres. Mr. Endres has served as our Chief Executive Officer and director since 2001. He has more than 20 years of experience in investing in, building, operating and managing successful businesses. In 1985, Mr. Endres founded Special Teams, Inc. and served as its president and general manager until it was sold to the American Express Company in 1995. Special Teams was recognized by Inc. magazine as one of the fastest growing privately held companies in the U.S. on the annual Inc. 500 List for both 1994 and 1995. Mr. Endres subsequently served for two years as president of American Express Special Teams.
      In 1999, Mr. Endres became a principal investor and board member of CoEv, Inc., which merged with Tyco International Ltd. in 2000. Mr. Endres also co-founded and served as principal investor and chief executive officer of ExpressGold.com, Inc., an internet payments system company, which merged with CyberSource Corporation in January 2000.
      He also served as co-founder and vice-chairman of Glacial Lakes Energy, an ethanol production facility in Watertown, South Dakota, and he is an investor in and board member of Badger State Ethanol, an ethanol producer in Monroe, Wisconsin. Mr. Endres serves on the board of directors and on the executive committee of the Renewable Fuels Association and was recently awarded the 2005 Ernst & Young Entrepreneur of the Year Award for the Minnesota, South Dakota and North Dakota region.
      Mr. Endres earned a bachelor of science degree in animal science with minors in computer science and economics from South Dakota State University. He was recognized by South Dakota State University’s College of Engineering as “Entrepreneur of the Year” in 2000.
      Bruce A. Jamerson. Mr. Jamerson has been our President since November 2003 and a director since January 2004. Mr. Jamerson also served as our Chief Financial Officer from November 2003 until March 2006. Before joining the Company, Mr. Jamerson was president of Conifer Investments, LLC, or Conifer, where he acted as our financial advisor. Conifer, which provided corporate finance and merger and acquisition advisory services on a national basis, was founded by Mr. Jamerson in 1996. He previously served as vice president of U.S. Natural Resources, Inc., a manufacturing company affiliated with Kohlberg, Kravis,

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Roberts & Company, from 1991 to 1993. Mr. Jamerson worked in the investment banking department of Credit Suisse First Boston in New York from 1980 to 1990 and in the ship financing department at Citibank in New York from 1975 to 1980.
      Mr. Jamerson earned a masters degree from the Sloan School of Management at the Massachusetts Institute of Technology and a bachelor of general studies degree from the University of Michigan.
      Danny C. Herron. Mr. Herron serves as our Senior Vice President and Chief Financial Officer and joined VeraSun in March 2006. Before joining the Company, Mr. Herron was executive vice president and chief financial officer of Swift & Company (an HM Capital Partners LLC portfolio company), a processor of fresh beef and pork products headquartered in Greeley, Colorado, from 2002 to 2006. He previously served as vice president and senior financial officer of Conagra Beef Company, a beef products manufacturer headquartered in Greeley, Colorado, from 1998 to 2002. From 1991 to 1998, Mr. Herron was employed at Borden Foods Company where he acted as snacks controller from 1991 to 1993, the chief financial officer of Midwest Snacks from 1993 to 1995 and operations controller from 1995 to 1998. Mr. Herron also worked at Frito-Lay, Inc. in various capacities from 1983 to 1991.
      Mr. Herron earned a masters degree in business administration from New Hampshire College and a bachelor of science degree in business administration and accounting from Valdosta State College.
      Paul J. Caudill. Mr. Caudill serves as Senior Vice President, Operations and joined VeraSun in late February 2006. He has over 25 years experience in architecture and engineering design, procurement and construction project management and has held senior-level positions with electric utilities in power generation plant operations. Prior to joining VeraSun, Mr. Caudill held a management position with Nebraska Public Power District where he was responsible for the company’s entry into the ethanol plant energy services market.
      Mr. Caudill earned a bachelor of science degree in public management from the University of Arizona and in 2004 graduated from Northwestern University’s Kellogg Graduate School of Management with a masters of business administration.
      William L. Honnef. Mr. Honnef is one of our founders and serves as Senior Vice President, Sales and Marketing. He was president and co-founder of ExpressGold.com, Inc. until it merged with CyberSource Corporation in January 2000. Mr. Honnef served as sales director of CyberSource Corporation until leaving to start VeraSun in 2001. Prior to co-founding ExpressGold.com, Inc., he was sales director at Special Teams, Inc. from 1992 until it was sold to the American Express Company in 1995. Mr. Honnef worked for American Express as regional vice president of sales from 1995 until leaving to start ExpressGold.com in 1999. He spent five years with Marriott Corporation in the role of systems analyst before joining Special Teams, Inc. Mr. Honnef serves on the boards of directors of NEVC, the Ethanol Promotion and Information Council and the American Coalition for Ethanol.
      Mr. Honnef graduated from Indiana University of Pennsylvania with a bachelor of arts degree in information systems in 1988 and was recognized by the University as the “Eberly School of Business and Information 2000 Entrepreneur of the Year.”
      Paul A. Schock. Mr. Schock serves as Senior Vice President, Corporate Development and joined VeraSun in September 2005. He has been a director since January 2003. Mr. Schock was affiliated with Bluestem Capital Company, a manager of various investment funds, from 1989 to 2004. Mr. Schock was a commercial banker and manager with First Bank Systems of Minneapolis, Minnesota, from 1981 to 1988, and chief financial officer of American Western Corporation, a manufacturing company in Sioux Falls, South Dakota, from 1988 to 1989. In 1989, he formed Schock Financial Services, Inc., the predecessor of Bluestem Capital Company.
      Mr. Schock attended Stanford University and graduated magna cum laude from Augustana College with a degree in business.
      John M. Schweitzer. Mr. Schweitzer serves as Senior Vice President and General Counsel and joined VeraSun in September 2005. Prior to joining VeraSun, he had been a partner at Stoel Rives LLP for more

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than 25 years, where he acted as counsel to VeraSun since its organization in 2001. Mr. Schweitzer was a Professional Attorney Fellow at the SEC from 1974 to 1976.
      Mr. Schweitzer earned a bachelor of arts degree in business administration from the University of Wisconsin — Milwaukee and masters and juris doctorate degrees from the University of Wisconsin — Madison.
      Kevin T. Biehle. Mr. Biehle joined the Company as Vice President, Plant Operations in December 2005. Before joining the Company, Mr. Biehle had a 20-year career with BASF Corporation in operations leadership and management.
      Mr. Biehle earned a bachelor of science degree in chemical engineering from the University of Missouri and a masters degree in business administration from the Kellogg School of Management at Northwestern University.
      Ginja R. Collins. Ms. Collins has served as our Secretary and Treasurer since June 2004 and became Vice President, Finance in March 2006. Prior to joining the Company, she was vice president of Conifer, which served as VeraSun’s financial advisor in securing the financing for the Aurora Facility in 2001. While at Conifer, Ms. Collins focused on corporate finance and merger and acquisition transactions for the energy and financial services sectors. Before joining Conifer in 1997, Ms. Collins worked as an analyst for U.S. Bancorp in asset and money management.
      Ms. Collins earned a bachelor of arts in economics and mathematics from Smith College.
      Matthew K.R. Janes. Mr. Janes served as Chief Operating Officer from January 2002 through September 2004 when he became Vice President, Technology. Mr. Janes served as a director from January 2003 to January 2005. Prior to joining VeraSun, Mr. Janes worked for 11 years with Commercial Alcohols Inc., or CAI, a manufacturer of industrial-grade alcohol and fuel-grade ethanol in Canada. He was CAI’s Vice President of Operations and Technology and was responsible for the design and start up of CAI’s 40 MMGY plant in Chatham, Ontario. Mr. Janes previously spent 11 years with Seagrams Distillers in various positions supervising production, engineering and technology functions.
      Mr. Janes has also served as vice president of the Canadian Renewable Fuels Association and as a director of Agri-Development Kent, an advisory committee of the local municipal government.
      Mr. Janes earned a bachelor of science degree in applied chemistry from the University of Waterloo and holds a diploma in business administration from Wilfred Laurier University. Mr. Janes has also completed both an Operations Management Program and a Financial Analysis for Executives Program at the Richard Ivey School of Business at the University of Western Ontario.
      Mark L. First. Mr. First has been a director since January 2006. Mr. First is a Managing Director of Eos Management, Inc., an affiliate of Eos Capital Partners III, L.P. and Eos Partners SBIC III, L.P., where he has been employed since March 1994. Mr. First was previously an investment banker with Morgan Stanley & Co., Incorporated from August 1991 until March 1994. He is also a director of several privately owned companies.
      Mr. First is a graduate of The Wharton School of the University of Pennsylvania with a bachelor of science degree and a graduate of the Harvard Business School with a masters degree in business administration.
      D. Duane Gilliam. Mr. Gilliam has been a director since January 2005. Mr. Gilliam has over 38 years of experience in the petroleum industry. Mr. Gilliam joined Ashland Inc. in 1967 as a process engineer and, thereafter, was promoted to a number of positions of increasing responsibility, including executive assistant, director and vice president of administration for Scurlock Oil Company in 1984, president of the newly combined Scurlock Permian Corporation in 1991, and group vice president of Ashland Petroleum Company in 1992. In 1993, Mr. Gilliam began serving as executive vice president of petroleum operations and, thereafter, as senior vice president for Ashland Inc. and president of Ashland Petroleum Company. He became executive

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vice president of Marathon Ashland Petroleum LLC, Findlay, Ohio, in January 1998, and was named executive vice president of corporate affairs in January 2001.
      Mr. Gilliam is a member of the 25 Year Club of the Petroleum Industry. He is a member and director of the American Petroleum Institute and serves on that organization’s downstream committee. Mr. Gilliam is chairman of the board of directors, executive committee and issues committee of the National Petrochemical & Refiners Association, or NPRA. He serves as chairman on the owner representatives board of LOOP LLC. Mr. Gilliam also serves on the board of directors and compensation committee of Colonial Pipeline Company.
      Mr. Gilliam is a graduate of the University of Kentucky. He is a registered professional engineer in Kentucky, Louisiana and Texas. He is a graduate of Harvard University’s Advanced Management Program. Mr. Gilliam was selected as a 2003 inductee into the University of Kentucky Engineering Hall of Distinction.
      T. Jack Huggins III. Mr. Huggins has been a director since January 2003. Mr. Huggins is founder and president of TJ3, Inc., a business development consulting firm that focuses on the ethanol industry. He has 25 years’ experience with Corn Products International, Inc. and Diversified CPC International in a variety of management positions, including vice president of finance, vice president of business management and planning, and vice president and executive assistant to the president within the Corn Products Division. In 1985, Mr. Huggins moved to Pekin Energy Company, a producer and marketer of ethanol in the U.S. He became its president and chief executive officer in 1990. Mr. Huggins became president of Williams Ethanol, president of Nebraska Energy, L.L.C. and vice president of Williams Energy in 1995, when the Williams Companies, Inc. purchased Pekin Energy Company.
      Mr. Huggins was the Chair of the Renewable Fuels Association from 1992 to 1995. He has also served on the Illinois Water Resources and Land Use Priorities Task Force and the Federal Fleet Conversion Task Force. Mr. Huggins presently serves on several boards of directors, including Heartland Water Resource Council, Excel Foundry and Machine, Inc. and is a member of the External Advisory Committee to the Agricultural Economic department at the University of Illinois.
      Mr. Huggins graduated from Yale University with a bachelor of science degree in chemical engineering and holds a masters degree in business administration from Pace University.
      Steven T. Kirby. Mr. Kirby has been a director since January 2006. Mr. Kirby is a founding partner of Bluestem Capital Company. Mr. Kirby was secretary and senior claims counsel for Western Surety Company, a national surety bond company, from 1977 to 1992. He was the 35th Lieutenant Governor of the State of South Dakota from 1993 through 1995. Mr. Kirby was also a candidate for Governor of South Dakota in 2002. Mr. Kirby is a director of several privately owned companies and is a speaker at various entrepreneurial and college forums.
      Mr. Kirby is a graduate of Arizona State University with a bachelor of science degree in political science and a graduate of the University of South Dakota School of Law with a juris doctorate degree.
Composition of the Board of Directors
      The Board of Directors consists of seven members and is divided pursuant to our articles of incorporation into three classes. Each of the directors is elected for a three year term. Class I directors will be elected in 2007, Class II directors will be elected in 2008 and Class III directors will be elected in 2009. In all cases, the terms of the directors will continue until their respective successors are duly elected. Class I directors are Donald L. Endres, D. Duane Gilliam and Paul A. Schock. Class II directors are T. Jack Huggins III and Steven T. Kirby. Class III directors are Mark L. First and Bruce A. Jamerson.
Committees of the Board of Directors
      Our Board of Directors has an audit committee, a compensation committee and a nominating and governance committee, each of which has the composition and responsibilities described below.

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      Audit Committee. Messrs. First, Gilliam and Huggins, each of whom is a non-employee member of our Board of Directors, comprise our audit committee. Mr. Huggins is the chairman of our audit committee. Our board has determined that each member of our audit committee meets the requirements for independence and financial literacy under New York Stock Exchange requirements and SEC rules and regulations. The Board of Directors has also determined that Mr. Huggins is an “audit committee financial expert” as defined in SEC rules and satisfies the financial sophistication requirements of the New York Stock Exchange. The audit committee is responsible for, among other things:
  selecting and hiring our independent auditors, and approving the audit and non-audit services to be performed by our independent auditors;
 
  evaluating the qualifications, performance and independence of our independent auditors;
 
  monitoring the integrity of our financial statements and our compliance with legal and regulatory requirements as they relate to financial statements or accounting matters;
 
  reviewing the adequacy and effectiveness of our internal control policies and procedures; and
 
  preparing the audit committee report that the SEC requires in our annual proxy statement.
      Compensation Committee. Messrs. First, Gilliam and Huggins, each of whom is a non-employee member of our Board of Directors, comprise our compensation committee. Mr. Gilliam is the chairman of our compensation committee. Our board has determined that each member of our compensation committee meets the requirements for independence under New York Stock Exchange requirements. The compensation committee is responsible for, among other things:
  reviewing and approving our chief executive officer and other executive officers’ annual base salaries and annual incentive bonuses, including the specific goals and amount, equity compensation, employment agreements, severance arrangements and change in control agreements/provisions, and any other benefits, compensation or arrangements;
 
  evaluating and recommending to the board incentive compensation plans;
 
  administering our stock incentive plan; and
 
  preparing or reviewing disclosures regarding compensation that the SEC requires in our annual proxy statement.
      Nominating and Governance Committee. Messrs. First, Gilliam and Huggins, each of whom is a non-employee member of our Board of Directors, comprise our nominating and governance committee. Mr. First is the chairman of our nominating and governance committee. Our board has determined that each member of our nominating and governance committee meets the requirements for independence under New York Stock Exchange requirements. The nominating and governance committee is responsible for, among other things:
  assisting the board in identifying prospective director nominees and recommending to the board director nominees for each annual meeting of shareholders;
 
  developing and recommending to the board governance principles applicable to us;
 
  overseeing the evaluation of the Board of Directors and management; and
 
  recommending members for each board committee.
Compensation Committee Interlocks and Insider Participation
      None of the members of our compensation committee is an officer or employee of our company. None of our executive officers serves, or in the past year has served, as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on our Board of Directors or compensation committee.

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Executive Compensation
      The following table sets forth information concerning the compensation paid for each of 2003, 2004 and 2005 to our Chief Executive Officer and each of our other named executive officers as of the end of 2005.
     Summary Compensation Table
                                                           
        Annual Compensation   Long-Term Compensation
             
            Other   Restricted   Securities    
Name and Principal           Annual   Stock   Underlying   All Other
Position   Year   Salary   Bonus   Compensation   Awards   Options/SARS(1)   Compensation
                             
Donald L. Endres
    2005     $ 236,856     $ 273,079                          
  Chief Executive     2004       225,000       147,900             90,272       795,136        
  Officer     2003       181,256                         1,387,745        
Bruce A. Jamerson(2)
    2005       233,232       60,312                          
  President and Chief     2004       252,785       18,866             90,272       795,136        
  Financial Officer     2003                               96,376        
William L. Honnef
    2005       168,750       11,423                          
  Vice President of     2004       168,750       39,880                   442,704        
  Sales and Marketing     2003       142,051                         158,305        
Matthew K. R. Janes
    2005       178,047       30,890                          
  Vice President,     2004       165,000       33,537                   442,704        
  Technology     2003       138,511                         172,045        
 
(1)  The securities granted in 2003 were in the form of warrants issued to the founders of VeraSun.
(2)  Although Mr. Jamerson joined VeraSun in November 2003, his 2003 compensation was deferred until 2004.
Director Compensation
      As compensation for services as a director, Messrs. First, Gilliam, Huggins and Kirby each receives $5,000 per quarterly board meeting, an additional $1,500 per board meeting attended in person, $1,500 per day for other board or committee meetings and $2,000 per other meeting or conference attended in person at our request. Our independent directors also receive an annual grant of options to purchase 15,000 shares of our common stock, subject to a one-year vesting period. In March 2006, special option grants to purchase 10,000 shares of our common stock at our initial public offering price were made to each of Messrs. Gilliam and Huggins in recognition of their additional commitment of time and effort in connection with this offering.
      Directors are also reimbursed for reasonable travel expenses incurred in connection with meetings of the Board of Directors.
Stock Incentive Plan
      The VeraSun Aurora Corporation 2003 Stock Incentive Plan, which we refer to as the Incentive Plan, was adopted by our shareholders and Board of Directors as of October 14, 2005. The following description of the Incentive Plan is intended to be a summary and does not describe all of its provisions.
      Eligibility. Selected employees, officers and directors of VeraSun or any of its parents or subsidiaries and selected nonemployee agents, consultants, advisers and independent contractors are eligible to receive awards under the Incentive Plan.
      Types of Awards. Under the Incentive Plan, the Board of Directors may (i) grant Incentive Stock Options, as defined in Section 422 of the Internal Revenue Code of 1986, as amended, or the Code; (ii) grant options other than Incentive Stock Options, or Non-Statutory Stock Options; (iii) award shares as stock bonuses; (iv) award shares of restricted stock; and (v) award shares of our common stock or cash, or any combination thereof, as qualified performance-based compensation under Section 162(m) of the Code, or Performance-Based Awards.

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      Administration. The Board of Directors has delegated administration of the Incentive Plan to the Compensation Committee of the Board, which we refer to as the Committee, which may determine and designate the individuals to whom awards shall be made, the amount of the awards and the other terms and conditions of the awards. Subject to the provisions of the Incentive Plan, the Committee may adopt and amend rules and regulations relating to administration of the Incentive Plan, advance the lapse of any waiting period, accelerate any exercise date, waive or modify any restriction applicable to shares (except those restrictions imposed by law) and make all other determinations in the judgment of the Committee necessary or desirable for the administration of the Incentive Plan, except that only the Board of Directors may amend or terminate the Incentive Plan. The interpretation and construction of the provisions of the Incentive Plan and related agreements by the Committee shall be final and conclusive. The Committee, in its sole discretion, may correct any defect or supply any omission or reconcile any inconsistency in the Incentive Plan or in any related agreement in the manner and to the extent it deems expedient to effect the Incentive Plan.
      Shares Subject to the Incentive Plan. Subject to adjustment as discussed below, the maximum number of shares that may be granted to participants under the Incentive Plan will, subject to shareholder approval, be 9,000,000 shares of common stock, including those already granted. As of December 31, 2005, options to purchase 4,234,980 shares had been awarded (net of shares exercised and forfeited). Shares subject to an award under the Incentive Plan that are not issued to a participant as a result of the award being cancelled, forfeited or terminated again become available under the Incentive Plan. If shares awarded as a stock bonus or sold as restricted stock under the Incentive Plan are forfeited to or repurchased by VeraSun, the number of shares forfeited or repurchased again become available under the Incentive Plan.
      Adjustments. If the Board of Directors or the Committee determines that any corporate transaction or distribution affects our shares of common stock so that an adjustment is determined by the Board or the Committee to be appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made under the Incentive Plan, the Board or Committee may make adjustments in the number of shares subject to awards so that the optionee’s proportionate interest is maintained.
      Exercise Price; Vesting. The exercise price of any options granted under the Incentive Plan is set in the discretion of the Committee and, in the case of Incentive Stock Options, is not less than the fair market value of the stock as of the date the option is granted. The vesting of options is set by the Committee at the time of the option grant.
      Sale of VeraSun. In the event of a merger, consolidation, plan of exchange, acquisition of property or stock, split-up, split-off, spin-off, reorganization or liquidation to which VeraSun is a party or any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of our assets, each referred to herein as a Transaction, the Board of Directors, in its sole discretion and to the extent possible under the structure of the Transaction, selects one of the following alternatives for treating outstanding options under the Incentive Plan:
  outstanding options will remain in effect in accordance with their terms;
 
  outstanding options will be converted into options to purchase stock in one or more of the corporations, including VeraSun, that are the surviving or acquiring corporations in the Transaction, with the amount, type of securities subject thereto and exercise price of the converted options to be determined by the Board of Directors; or
 
  the Board of Directors will provide a period of 30 days or less before the completion of the Transaction during which outstanding options may be exercised to the extent then exercisable, and upon the expiration of that period, all unexercised options shall immediately terminate. The Board of Directors may, in its sole discretion, accelerate the exercisability of options so that they are exercisable in full during that period.
      Amendment and Termination. Only our Board of Directors may amend or terminate the Incentive Plan.

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Stock Option Awards
      In 2005, we awarded options to purchase a total of 885,000 shares of common stock under the Incentive Plan. None of these awards were to our named executive officers.
      The Compensation Committee is considering the possible grant of additional stock options and other awards.
Stock Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values
      The following table indicates (on an aggregated basis): (i) the number of shares subject to exercisable and unexercisable stock options as of our fiscal year end, December 31, 2005, and (ii) the value of “in-the-money” options at December 31, 2005. None of our executive officers exercised options during 2005.
                                 
        Value of Unexercised
    Number of Unexercised   In-the-Money Options
    Options at Year-End   At Year-End(1)
         
Name   Exercisable   Unexercisable   Exercisable   Unexercisable
                 
Donald L. Endres
    316,283       477,082     $ 1,371,645     $ 2,069,161  
Bruce A. Jamerson
    316,283       477,082       1,391,645       2,099,161  
William L. Honnef
    176,197       265,622       775,267       1,168,737  
Matthew K.R. Janes
    173,246       265,622       762,282       1,168,737  
 
(1)  Options are “in-the-money” at the fiscal year-end if the fair market value of the underlying securities on such date exceeds the exercise price of the option. The amounts set forth represent the difference between the fair market value of the securities underlying the options on December 31, 2005, based on the fair market valuation of $5.40 per share of common stock (that was made by an independent third party financial advisor in connection with the valuation of TIAA’s put warrant) and the exercise price of the options, multiplied by the applicable number of options.
Pension Plans
      We do not maintain any defined benefit pension or retirement plans for our executive officers, directors or employees.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Shareholder Agreement
      All of our existing shareholders, including TIAA, have entered into a shareholder agreement dated as of November 30, 2005, providing for various governance matters, restrictions on transfer of shares, tag-along rights, rights of first offer and best efforts registration rights. The shareholder agreement will terminate upon completion of this offering, except that TIAA will retain the registration rights described below until it no longer holds any common stock or warrants and each existing shareholder will retain the piggyback rights described below until the earlier to occur of: (i) such time when the shareholder can sell all its registrable securities in any three-month period without registration in compliance with SEC Rule 144, or (ii) three years following completion of this initial public offering. A summary of various provisions of the shareholder agreement is set forth below:
  Donald L. Endres has the right to nominate four directors, including himself. The Bluestem Funds and Eos Capital Partners, L.P. each have the right to nominate one director. The seventh director is to be nominated by an 80% vote of other directors. Each of the shareholders and TIAA have agreed to vote their shares for election of these nominees.
 
  Specified matters require the approval of at least 80% of the directors in office, including the approval or material amendment of our annual operating budget, approval of contractual obligations and transactions outside of the annual operating budget, selection of independent auditors and approval of any employment agreements requiring payment in excess of $125,000 per year.
 
  No shareholder may transfer any shares of VeraSun capital stock other than with the consent of holders of at least two-thirds of the aggregate voting power of all issued and outstanding shares of voting capital stock, except for specified permitted transfers and except that TIAA is not subject to this restriction.
 
  The holders of at least two-thirds of the fully diluted common stock may require each other shareholder to transfer their shares in connection with specified sales of shares, and our shareholders have tag-along rights in the event a 10% holder proposes to sell or otherwise dispose of shares.
 
  Each shareholder (so long as such shareholder holds at least 25% of the shares originally acquired by such shareholder) and TIAA have a right of first offer with respect to future issues of our capital stock, subject to specified exceptions.
 
  All holders of common stock may request the inclusion of their shares in any registration statement at our expense whenever we propose to register any of our equity securities under the Securities Act. The right to request inclusion of shares does not apply to a registration statement on Form S-4 or S-8, or, with respect to any shareholder other than TIAA, after the shareholder has had the opportunity to include its shares in one registration. TIAA also has one opportunity to require us to use our best efforts to register any or all of its shares of our common stock after we have completed an initial public offering. In connection with all of these registrations, we have agreed to indemnify the holders of registered securities against liabilities relating to the registration, including liabilities under the Securities Act.
 
  Each shareholder and TIAA have agreed not to sell any of our equity securities for a period of up to 180 days after our first underwritten registered public offering of equity securities.
Loans from Chief Executive Officer
      On March 16, 2004, we issued a $1.0 million promissory note under our unsecured line of credit to our Chief Executive Officer, Donald L. Endres. The promissory note was paid in full prior to December 31, 2004. Total interest expense incurred under the note was $10,000 in 2004.

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      In 2004, we issued a $1.0 million unsecured term note to Mr. Endres which bore interest at a rate of 10% per annum and was also paid in full in 2004. Total interest expense incurred under the note was $22,000 in 2004.
      On July 28, 2005, VeraSun, LLC entered into a line of credit of $1.0 million with Mr. Endres. VeraSun, LLC incurred $16,000 in related interest expense under the line of credit in 2005. All amounts outstanding under this line of credit were paid in full on November 30, 2005.
      On November 14, 2005, VeraSun Charles City, LLC issued a $1.3 million secured promissory note to Mr. Endres. VeraSun Charles City, LLC incurred $5,000 in related interest expense under this note in 2005. The promissory note was also paid in full on November 30, 2005.
      On November 14, 2005, VeraSun Biodiesel, LLC, our subsidiary, entered into an unsecured line of credit of $800,000 with Mr. Endres. VeraSun Biodiesel, LLC incurred $3,000 in related interest expense under the line of credit in 2005. All amounts outstanding under this line of credit were paid in full on November 30, 2005.
      We believe all of these transactions with Mr. Endres were on terms no less favorable then those that could have been obtained from an independent party.
Transactions with Bluestem
      We paid $67,000 in 2004 and $108,000 in 2005 to Bluestem Capital Company, LLC for consulting services. Bluestem Capital Company, LLC manages five funds which beneficially own, in the aggregate, 32.9% of our common stock. Steven T. Kirby, a director of our company, is the president and 85% owner of Bluestem Capital Company, LLC. We no longer obtain these services from Bluestem Capital Company, LLC.
      In May 2004, the Bluestem Growth & Income Fund, LLC loaned $1.0 million to VeraSun Fort Dodge, LLC, which bore interest at a rate of 10% per annum. In August 2004, this loan was converted into 579,359 shares of common stock. Accrued interest of $22,000 was paid in cash to the Bluestem Growth & Income Fund, LLC during 2004.
The Business Combination
      In October 2005, we completed a business combination with VeraSun, LLC. In connection with that transaction, holders of membership interests in VeraSun, LLC received an aggregate of 5,140,800 shares of our common stock. Among these holders were Donald L. Endres, an affiliate of Bruce A. Jamerson, William L. Honnef, Matthew K.R. Janes, John M. Schweitzer and the Bluestem Funds, who received an aggregate of 3,404,490; 37,209; 43,539; 56,583; 4,219; and 1,411,383 shares, respectively, in exchange for their respective investments in VeraSun, LLC of $993,374; $10,857; $12,704; $16,510; $1,231; and $411,818. In addition, holders of Class B membership interests in VeraSun Fort Dodge, LLC received an aggregate of 8,690,383 shares of our common stock in a transaction completed in November 2005. Among these holders were Donald L. Endres, Bruce A. Jamerson, William L. Honnef and the Bluestem Funds, who received an aggregate of 2,665,050, 173,808, 28,968, and 3,765,833 shares, respectively, in exchange for their respective investments in Class B interests of $4,600,000; $300,000; $50,000; and $6,500,000.

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PRINCIPAL AND SELLING SHAREHOLDERS
      The following table sets forth information with respect to the beneficial ownership of VeraSun Energy Corporation as of December 31, 2005 and after giving effect to the completion of this offering by (a) any person or group who beneficially owns more than 5% of any class of our capital stock; (b) each of our executive officers and directors; and (c) all executive officers and directors as a group.
      Unless otherwise indicated, the address for each person or entity named below is c/o VeraSun Energy Corporation, 100 22nd Avenue, Brookings, South Dakota 57006.
      Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Except as indicated by footnote, and except for community property laws where applicable, the persons named in the table below have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them.
                                           
    Shares Beneficially       Shares Beneficially
    Owned Prior to the       Owned After the
    Offering(1)       Offering(1)
        Number of Shares    
Name of Beneficial Owner   Number   Percent   Being Offered   Number   Percent
                     
Donald L. Endres
    31,589,883       50.3 %           33,429,710          
Bruce A. Jamerson
    958,148       1.5 %           1,410,230          
Danny C. Herron
                               
Paul J. Caudill
                               
William L. Honnef
    429,222       0.7 %           693,827          
Paul A. Schock
                      125,000          
John M. Schweitzer
    80,910       0.1 %           300,000          
Mark L. First(2)
                               
D. Duane Gilliam
    15,000       0.0 %           15,000          
T. Jack Huggins III
    25,000       0.0 %           25,000          
Steven T. Kirby(3)
                               
All Executive Officers and Directors (11 Persons)
    33,098,163       53.0 %           35,998,767          
Bluestem Funds(4)
    20,571,672       32.9 %                        
  122 S. Phillips Ave.                                        
  Sioux Falls, SD 57104                                        
Eos Funds(5)
    5,745,868       9.2 %           5,745,868          
  320 Park Ave.
New York, NY 10022
                                       
 
(1)  Includes shares that the named person has the right to acquire through options or warrants that become exercisable within 60 days after January 31, 2006.
(2)  As managing director of Eos Management, Inc., Mr. First may be considered the beneficial owner of stock owned by the Eos Funds.
(3)  As a founding partner and manager of Bluestem Capital Company, Mr. Kirby may be considered the beneficial owner of stock owned by the Bluestem Funds.
(4)  Various investment funds managed by Bluestem Capital Company own our capital stock. These funds include Bluestem Ethanol, LLC, Bluestem Capital Partners, III, LP, Bluestem Ethanol II, LLC, Bluestem Growth & Income Fund, LLC, I, and Bluestem Growth & Income Fund, LLC, II. We refer to these funds in this prospectus as the Bluestem Funds.
(5)  Two funds affiliated with Eos Partners, L.P. own our capital stock. These funds include Eos Capital Partners III, L.P. and Eos Partners SBIC III, L.P.

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DESCRIPTION OF CERTAIN INDEBTEDNESS
      Senior Secured Notes. On December 21, 2005, we completed a private offering of 97/8% Senior Secured Notes due December 15, 2012. The notes were sold for an aggregate purchase price of $210.0 million, the net proceeds of which were used to repay indebtedness relating to our Aurora Facility and our Fort Dodge Facility, deposit $125.0 million into an escrow account to finance the costs of construction and start-up costs of our Charles City Facility, and finance general corporate activities.
      The notes
  bear interest at 97/8 % per year, payable semi-annually in arrears on June 15 and December 15 of each year, beginning on June 15, 2006;
 
  are guaranteed on a senior secured basis by certain of our existing and future domestic subsidiaries;
 
  and the note guarantees are secured on a first priority basis by liens on the escrow account into which $125.0 million has been deposited pending application to the construction and start-up costs of our Charles City Facility and on substantially all of our and our restricted subsidiaries’ assets other than our and our restricted subsidiaries’ accounts receivable, inventory, commodities accounts and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which the proceeds are deposited), and subject to various other exceptions;
 
  rank equally in right of payment with all of our existing and future senior debt; and
 
  rank senior in right of payment to all our existing and future subordinated debt.
      We entered into a registration rights agreement with the initial purchasers of the notes in which we agreed to complete an exchange offer in which the notes will be exchanged for notes with substantially identical terms that are registered for issuance under the Securities Act. As of the date of this prospectus, we have filed a registration statement with the SEC to register the exchange notes but we have not completed the exchange offer.
      If we decide not to complete the construction of our Charles City Facility, we will be required to redeem $125.0 million (or a lesser amount that is equal to the amount held in the escrow account at the time of redemption) in the aggregate principal amount of the notes outstanding, at a redemption price equal to 100% of the offering price of the notes plus accrued interest to, but not including, the redemption date. The funds held in the escrow account are subject to a security interest granted to the trustee for the benefit of the holders of the notes and will be disbursed by the trustee, acting as an agent and securities intermediary, in accordance with a separate escrow agreement.
      Before December 15, 2008, we may redeem up to 35% of the aggregate principal amount of the notes at 109.875% of the principal amount plus accrued and unpaid interest to, but not including, the redemption date, with the net proceeds of one or more equity offerings; provided that at least 65% of the aggregate principal amount of the notes issued under the indenture remain outstanding after the redemption.
      Before December 15, 2009, we may redeem the notes, in whole or in part, by paying a make-whole premium as provided in the notes. At any time on or after December 15, 2009, we may redeem the notes, in whole or in part, at certain redemption prices as provided in the notes.
      If we experience a change of control, each holder of notes will have the right to require us to purchase all or a portion of the notes at 101% of the principal amount of the notes on the date of purchase, plus any accrued and unpaid interest to, but not including, the date of such purchase.
      In addition, the terms of the indenture under which the notes were issued include certain covenants that limit our ability and the ability of our restricted subsidiaries to:
  incur additional debt;
 
  pay dividends or make other distributions;

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  make investments or other specified restricted payments;
 
  repurchase or redeem capital stock or prepay subordinated indebtedness;
 
  enter into transactions with shareholders or affiliates;
 
  guarantee debts;
 
  create liens;
 
  restrict dividends or other payments to us from our subsidiaries; and
 
  consolidate, merge or sell assets.
      These covenants are subject to important qualifications and exceptions pursuant to the terms of the notes, and this summary does not purport to be a complete description of the covenants or the terms of the notes.
      The holders of any indebtedness that we incur in the future and designate as first priority lien indebtedness will benefit from first priority liens on the collateral securing our and the subsidiary guarantors’ obligations under the notes. The indenture governing the notes permits up to $500.0 million aggregate principal amount of debt to be secured by the collateral on a first priority lien basis, subject to certain conditions. Accordingly, we may, in addition to the notes already outstanding, issue an additional $290.0 million of parity lien indebtedness per the terms of the indenture.
      The Credit Agreement. On December 21, 2005, in connection with, and as a condition to, the offering of the notes, we entered into a $30.0 million borrowing base operating line of credit, with a $10.0 million sublimit for letters of credit, with First National Bank of Omaha, for general corporate purposes. Our obligations under the Credit Agreement are guaranteed by all of our existing and future ethanol production subsidiaries and are secured by first priority security interests in our and some of our subsidiaries’ accounts receivable and inventory, and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which the proceeds are deposited). Borrowings under the Credit Agreement bear interest at LIBOR plus the applicable margin, which initially was 3.0%. In addition to paying interest on the outstanding principal under the Credit Agreement, we are also required to pay a commitment fee to First National Bank of Omaha in respect of unused loan commitments at an initial rate of 0.25%. The interest rate and the commitment fee are subject to adjustment based on our working capital levels. The Credit Agreement contains customary covenants, including minimum tangible net worth, working capital requirements and negative pledges. The Credit Agreement also contains certain customary events of default including defaults based on cross-defaults to other material indebtedness. The Credit Agreement matures on December 31, 2008. As of February 28, 2006, there was no outstanding balance and $26.9 million was available to borrow under the Credit Agreement. Letters of credit in an aggregate amount of $2.7 million have been issued under the Credit Agreement, leaving $24.2 million of remaining borrowing capacity at February 28, 2006. As of the date of this prospectus, we and our subsidiaries have no debt outstanding other than the senior secured notes described above.

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DESCRIPTION OF CAPITAL STOCK
General
      Our authorized capital stock consists of 250,000,000 shares of common stock, having a par value of $0.01 per share, and 100,000,000 shares of preferred stock, having a par value of $0.01 per share. As of December 31, 2005, we had 62,492,722 shares of common stock issued and outstanding and no shares of preferred stock issued or outstanding. Upon completion of this offering, we will have                      shares of common stock issued and outstanding and no shares of preferred stock issued or outstanding, whether or not the underwriters’ over-allotment option is exercised in full.
      The following description of our capital stock is intended as a summary only and is qualified in its entirety by reference to our articles of incorporation, as amended, and our bylaws, which are filed as exhibits to the registration statement, of which this prospectus forms a part, and to the applicable provisions of the South Dakota Codified Laws. We refer in this section to our articles of incorporation, as amended, as our articles.
Common Stock
      Holders of common stock are entitled to one vote per share on all matters on which they are entitled to vote, provided, however, that shareholders are allowed to use cumulative votes for the election of directors. Holders of common stock are entitled to receive dividends as may from time to time be declared by our Board of Directors out of funds legally available for that purpose, after any preferential amount with respect to the preferred stock has been paid or set aside and subject to participation by preferred shareholders entitled to do so. Under South Dakota law, a dividend may not be paid if, after giving effect to the dividend, we would not be able to pay our debts as they become due in the usual course of business, or our total assets would be less than the sum of our total liabilities plus the amount needed to satisfy the preferential rights of shareholders with rights superior to those receiving the dividend.
      Holders of common stock have no preemptive rights, conversion rights, redemption rights or rights to a fund whose assets and their earnings are earmarked to pay for the common stock. Upon liquidation, dissolution or winding up, holders of common stock are entitled to share equally and proportionately in any of our assets remaining after the payment of all of our liabilities and after any preferential distribution with respect to the preferred stock. The outstanding shares of common stock are validly issued, fully paid and nonassessable.
Preferred Stock
      Our Board of Directors is authorized, subject to limitations prescribed by the South Dakota Business Corporation Act, as amended from time to time, and by the provisions of our articles, to provide for the issuance of shares of preferred stock in series, to establish the number of shares to be included in each series and to determine the designations, preferences, limitations and relative rights, including voting rights, conversion rights, redemption rights and dividend rights, of the shares of each series. As of the date of this prospectus, our Board of Directors has not provided for the issuance of a series of preferred stock and no shares of preferred stock are outstanding.
Registration Rights
      Pursuant to the shareholders’ agreement, dated November 30, 2005, by and among us and our existing shareholders, our existing shareholders may request the inclusion of their shares in any registration statement at our expense whenever we propose to register any of our equity securities under the Securities Act. The right to request inclusion of shares does not apply to a registration statement on Form S-4 or S-8, or, with respect to any shareholder other than TIAA, after the shareholder has had the opportunity to include its shares in one registration. These piggyback registration rights terminate at the earlier of (i) such time when the shareholder can sell all its registrable securities in any three month period without registration in compliance with SEC Rule 144 or (ii) three years following completion of this offering. TIAA also has one opportunity to require us to use our best efforts to register any or all of its shares of our common stock attributable to its warrant after

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we have completed an initial public offering. In connection with all of these registrations, we have agreed to indemnify the holders of registered securities against liabilities relating to the registration, including liabilities under the Securities Act. With respect to our existing shareholders, these registration rights are subject to certain restrictions in the lock-up agreements discussed more fully under “Shares Eligible for Future Sale.”
Pre-emptive Rights
      Our articles expressly state that our shareholders shall not have pre-emptive rights to purchase our stock or securities convertible into or carrying a right to subscribe for or acquire our stock, unless we expressly agree otherwise.
Anti-Takeover Provisions
      Our articles, our bylaws and South Dakota law contain certain provisions that might be characterized as anti-takeover provisions. These provisions may make it more difficult to acquire control of us or remove our management.
      Articles and Bylaws. Our articles, bylaws and South Dakota law contain provisions that may have the effect of delaying, deferring or preventing a change in control. These provisions include: (i) the ability of our Board of Directors, without further shareholder approval, to issue shares of common stock or preferred stock, provided the issuance involves less than 20 percent of the voting power of the outstanding shares immediately before the issuance, (ii) allowing the Board of Directors to fill vacancies on the Board of Directors, and (iii) the ability of our Board of Directors to increase our indebtedness up to an aggregate of $1.0 billion without seeking shareholder approval.
      Classified Board. The Board of Directors consists of seven members and is divided pursuant to our articles of incorporation into three classes. Each of the directors is elected for a three year term. Class I directors will be elected in 2007, Class II directors will be elected in 2008 and Class III directors will be elected in 2009. In all cases, the terms of the directors will continue until their respective successors are duly elected. The directors may be removed only for “cause,” as defined in our articles. A vote of 75% of our outstanding voting securities is required to amend the section of our articles providing for staggered terms of directors.
      Control Share Acquisitions. The control share acquisition provisions of the South Dakota Domestic Public Corporation Takeover Act provide generally that the shares of a publicly-held South Dakota corporation acquired by a person that exceed the thresholds of voting power described below will have the same voting rights as other shares of the same class or series only if approved by:
  the affirmative vote of the majority of all outstanding shares entitled to vote, including all shares held by the acquiring person; and
 
  the affirmative vote of the majority of all outstanding shares entitled to vote, excluding all interested shares.
      Each time an acquiring person reaches a threshold, an election must be held as described above before the acquiring person will have any voting rights with respect to shares in excess of such threshold. The thresholds which require shareholder approval before voting powers are obtained with respect to shares acquired in excess of such thresholds are 20%, 331/3 % and 50%, respectively.
      The restricted shareholder may, but is not required to, submit to the corporation a statement setting forth information about itself and its plans with respect to the corporation. The statement may request that the corporation call a special meeting of shareholders to determine whether voting rights will be granted to the shares acquired. If a special meeting of shareholders is not requested, the issue of voting rights of the acquired shares will be considered at the next annual or special meeting of shareholders. If the acquired shares are granted voting rights and they represent a majority of all voting power, shareholders who do not vote in favor of granting voting rights will have the right to receive the appraised fair value of their shares. The appraised fair

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value will, at a minimum, be equal to the highest price paid per share by the acquiring person for the shares acquired in the transaction subject to this law.
      Business Combinations. We are subject to the provisions of Section 47-33-17 of the South Dakota Domestic Public Corporation Takeover Act. In general, Section 47-33-17 prohibits a publicly-held South Dakota corporation from engaging in a “business combination” with an “interested shareholder” for a period of four years after the date that the person became an interested shareholder unless the business combination or the transaction in which the person became an interested shareholder is approved in a prescribed manner. After the four-year period has elapsed, the business combination must still be approved, if not previously approved in the manner prescribed, by the affirmative vote of the holders of a majority of the outstanding voting shares exclusive, in some instances, of those shares beneficially owned by the interested shareholder. Generally, a “business combination” includes a merger, a transfer of 10% or more of the corporation’s assets, the issuance or transfer of stock equal to 5% or more of the aggregate market value of all of the corporation’s outstanding shares, the adoption of a plan of liquidation or dissolution, or other transaction resulting in a financial benefit to the interested shareholder. Generally, an “interested shareholder” is a person who, together with affiliates and associates, owns 10% or more of the corporation’s voting stock. This provision may delay, defer or prevent a change in control of us without the shareholders taking further action.
      The South Dakota Domestic Public Corporation Takeover Act further provides that our board, in determining whether to approve a merger or other change of control, may take into account both the long-term as well as short-term interests of us and our shareholders, the effect on our employees, customers, creditors and suppliers, the effect upon the community in which we operate and the effect on the economy of the state and nation. This provision may permit our board to vote against some proposals that, in the absence of this provision, it would have a fiduciary duty to approve.
Put Warrant
      We entered into a subordinated note purchase agreement in 2002, which provided for a commitment to issue subordinated secured notes in an aggregate principal amount of up to $20.0 million. During 2005, these notes were paid in full. To induce TIAA to enter into the note purchase agreement, we granted a warrant to TIAA to acquire 1,180,000 shares of common stock at an exercise price of $0.01 per share. The warrant expires December 23, 2012, provided that we give TIAA at least 30 days’ notice of the expiration of the warrant.
      The warrant provides TIAA with various rights, including put rights (the right to require us to purchase the warrant at a price related to the fair market value of the underlying common stock), tag-along rights (the right to participate in sales by other current shareholders) and anti-dilution protections. The anti-dilution protections provide for the adjustment of the number of shares issuable upon exercise of the warrant if certain events occur. Such events include stock splits, stock dividends, reclassifications, mergers, consolidations and share exchanges and issuance or sale of shares of common stock or rights with respect thereto (such as certain options, warrants, convertible securities or exchangeable securities) for less than market price (as measured over specified trading periods).
      TIAA’s put rights are expected to terminate upon termination of this offering, assuming that the offering is a “Qualified Public Offering” as defined in the warrant agreement. TIAA will retain its tag-along rights and anti-dilution protections.
Transfer Agent and Registrar
      The transfer agent and registrar for our common stock is Wells Fargo Shareowner Services. The transfer agent’s address is 161 N. Concord Exchange, South St. Paul, Minnesota 55075 and its telephone number is (800) 468-9716.
New York Stock Exchange Listing
      We have applied to have our common stock listed on the New York Stock Exchange under the symbol “VSE.”

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SHARES ELIGIBLE FOR FUTURE SALE
      As described below, no shares outstanding immediately before this offering will be available for sale immediately after this offering as a result of various contractual and securities law restrictions on resale. Sales of substantial amounts of our common stock in the public market after the restrictions lapse could adversely affect the prevailing market price and our ability to raise equity capital in the future.
      Upon completion of this offering, we will have                      outstanding shares of common stock, assuming no exercise of outstanding stock options. Of these shares, the                      shares offered hereby will be freely tradable without restriction under the Securities Act, unless purchased by our affiliates or covered by a separate lock-up agreement with the underwriters.
      The remaining                      shares of common stock are held by existing shareholders and are restricted securities. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under the Securities Act. As a result of the lock-up agreements, these restricted shares will generally be eligible for sale in the public market as follows:
  substantially all of these shares will be subject to lock-up agreements with the underwriters, and none of these shares may be sold prior to the expiration of 180 days from the date of this prospectus without the prior written consent of the underwriters; and
 
  the remaining                      shares may be sold under Rule 144 promulgated under the Securities Act beginning the 181st day from the date of this prospectus and provided that they have been held for the required period of time and are sold pursuant to applicable volume and manner limitations of Rule 144.
      Lock-up Agreements. We, our directors and executive officers, substantially all of our existing shareholders and all holders of options exercisable within 180 days from the date of this prospectus will enter into lock-up agreements with the underwriters. Under these agreements, subject to exceptions, we may not issue any new shares of common stock, and those holders of stock and options may not, directly or indirectly, offer, sell, contract to sell, pledge or otherwise dispose of or hedge any common securities convertible into or exchangeable for shares of common stock, or publicly announce the intention to do any of the foregoing, without the prior written consent of the underwriters for a period of 180 days from the date of this prospectus. This consent may be given at any time without public notice. In addition, during this 180-day period, we have also agreed not to file any registration statement for, and each of our officers and shareholders has agreed not to make any demand for, or exercise any right of, the registration of, any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock without the prior written consent of the underwriters. Transfers or dispositions can be made sooner only with the prior written consent of the underwriters. The underwriters have no present intent to release us or any of our directors, executive officers or option holders from the lock-up agreements.
      Rule 144. In general, under Rule 144, a person who has beneficially owned restricted securities for at least one year would be entitled to sell the securities without registration under the Securities Act within any three-month period a number of shares that does not exceed the greater of:
  1% of the number of shares of our common stock then outstanding, which will equal approximately                      shares immediately after this offering; or
 
  the average weekly trading volume of our common stock on the New York Stock Exchange for the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.
      Sales under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.
      Rule 144(k). Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the securities proposed to be sold for at least two years, is entitled to sell these shares without registering such securities under the Securities Act and without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144 mentioned above.

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      Rule 701. Further, in general, under Rule 701 of the Securities Act, any of our employees, consultants or advisors who purchased shares from us in connection with a qualified compensatory stock plan or other written agreement are eligible to resell those shares 90 days after the effective date of this offering in reliance on Rule 144, but without compliance with various restrictions, including the holding period, contained in Rule 144. Subject to the 180-day lock-up period described below, approximately                      shares of our common stock will be eligible for sale pursuant to Rule 701.
      Registration Rights. Holders of                      shares of our common stock will be entitled to rights with respect to the registration of their shares under the Securities Act pursuant to the terms and subject to the conditions set forth in the shareholders’ agreement, dated November 30, 2005, by and among us and our existing shareholders. See “Certain Relationships and Related Party Transactions” and “Description of Capital Stock—Registration Rights.” Except for shares held by our shareholders or holders of options that are subject to the lock-up agreements described above, registration of these shares under the Securities Act would result in these shares becoming freely tradable without restriction under the Securities Act immediately upon the effectiveness of the registration statement.
      Stock Options. Immediately after completion of this offering, we intend to file a registration statement on Form S-8 under the Securities Act, which will become effective upon filing, covering                      shares of common stock reserved for issuance upon exercise of stock options awarded under our stock incentive plan. Accordingly, shares registered under the Form S-8 registration statement will be available for sale in the open market after the expiration of the agreed-upon lock-up period described above, which is the 181st day from the date of this prospectus.

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U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS
      The following is a general discussion of material U.S. federal income and estate tax consequences of the acquisition, ownership and disposition of our common stock purchased pursuant to this offering by a beneficial owner that, for U.S. federal income tax purposes, is treated as a non-U.S. holder. As used in this prospectus, the term “non-U.S. holder” is a person that is not, for U.S. federal income tax purposes:
  an individual who is a citizen or resident of the United States;
 
  a corporation or partnership (including any entity treated as such for U.S. federal tax purposes) created or organized in the United States or under the laws of the United States or of any political subdivision of the United States;
 
  an estate the income of which is subject to U.S. federal income taxation regardless of its source; or
 
  a trust (i) the administration of which is subject to the primary supervision of a U.S. court and one or more U.S. persons have the authority to control all of its substantial decisions, or (ii) that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person.
      An individual may be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes by being present in the United States on at least 31 days in that calendar year and for an aggregate of at least 183 days during a 3-year period ending in the current calendar year. For purposes of determining days present in the United States, certain days that an individual is actually present in the United States are not taken into account. In addition, the 183-day test is determined by counting all of the days the individual is treated as being present in the current year, one-third of such days in the immediately preceding year and one-sixth of such days in the second preceding year.
      If a partnership is a beneficial owner of our common stock, the treatment of a partner in the partnership generally will depend upon the status of the partner and the activities of the partnership. A beneficial owner of our common stock that is a partnership and partners in such a partnership should consult their tax advisors regarding the U.S. federal income tax consequences of acquiring, owning, and disposing of our common stock.
      This discussion assumes that you will hold our common stock issued pursuant to this offering as a capital asset within the meaning of the Internal Revenue Code of 1986, as amended (the “Code”), which will generally be the case if you hold the stock for investment.
      This discussion does not address all aspects of U.S. federal taxation that may be relevant to a particular non-U.S. holder in light of the holder’s individual investment or tax circumstances, or to non-U.S. holders that are subject to special tax rules. In addition, this description of U.S. tax consequences does not address:
  U.S. state and local or non-U.S. tax consequences;
 
  the tax consequences for the shareholders, partners, beneficiaries or other owners of a non-U.S. holder; and
 
  special tax rules that may apply to non-U.S. holders subject to special tax treatment under U.S. federal tax laws, including:
  former citizens or residents of the Untied States subject to tax as expatriates;
 
  partnerships or other pass-through entities;
 
  tax-exempt entities;
 
  banks and insurance companies;
 
  dealers in securities;
 
  holders of securities held as part of a “straddle,” “hedge,” “conversion transaction” or other risk-reduction or integrated transaction; and
 
  persons who hold or receive our common stock as compensation.

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      This discussion is based on current provisions of the Code, final, temporary and proposed U.S. Treasury regulations, judicial opinions, published positions of the U.S. Internal Revenue Service (the “IRS”), and other applicable authorities, all as in effect on the date hereof and all of which are subject to differing interpretations or change, possibly with retroactive effect. We have not requested a ruling from the IRS or an opinion of counsel with respect to the tax consequences discussed herein, and there can be no assurance that the IRS will not take a position contrary to the tax consequences discussed below or that any position taken by the IRS would not be sustained.
      In view of the foregoing and because the following is intended as a general summary only, we urge you to consult your tax advisor regarding the U.S. federal tax consequences of acquiring, owning or disposing of our common stock, as well as any tax consequences that may arise under the laws of any foreign, state, local or other taxing jurisdiction or under any applicable tax treaty.
Distributions
      As described under “Dividend Policy” above, we do not anticipate making distributions with respect to our common stock in the foreseeable future. If, however, distributions are made with respect to shares of our common stock, such distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. (References in the remainder of this discussion to “dividends” will be to distributions that are treated as dividends for U.S. federal tax purposes.) Distributions in excess of our current or accumulated earnings and profits generally will constitute a return of capital to the extent of the recipient’s adjusted tax basis in our common stock (and will be applied against and reduces such adjusted tax basis). To the extent that a non-dividend distribution exceeds the recipient’s adjusted tax basis in our common stock, the excess will be treated as gain realized on the sale or other disposition of the common stock and will be treated, for non-U.S. holders, as described under “—Disposition of Common Stock” below.
      Dividends we pay to a non-U.S. holder that are not treated as effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States generally will be subject to U.S. federal income withholding tax at a rate of 30% of the gross amount of the dividend, or such lower rate as may be specified by an applicable income tax treaty.
      Dividends we pay to a non-U.S. holder that are treated as effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States, or (if an applicable income tax treaty applies) that are attributable to a permanent establishment or fixed base maintained by the non-U.S. holder in the United States, generally are not subject to the U.S. withholding tax. Instead, such dividends, together with other U.S. trade or business income, net of specified deductions and credits, generally are subject to U.S. federal income tax at rates applicable to U.S. persons. Any such dividends and other U.S. trade or business income received by a non-U.S. holder that is treated as a foreign corporation for U.S. tax purposes may be subject to an additional “branch profits tax” at a 30% rate, or such lower rate as may be specified by an applicable income tax treaty.
      Regardless of whether the distribution is treated as effectively connection with the non-U.S. holder’s conduct of a trade or business in the United States, if we are, or have been at any time during the five-year period preceding such distribution (or the non-U.S. holder’s holding period, if shorter), a “United States real property holding corporation” (see “—Disposition of Common Stock” below), we may be required to withhold 10% of the gross amount of a non-dividend distribution. Consequently, we may withhold at a 10% rate in circumstances in which withholding at a 30% rate (or lower rate as specified in an applicable income tax treaty) does not apply or may not apply.
      To claim the benefit of a tax treaty with respect to a dividend not effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States, or an exemption from withholding because a dividend is effectively connected with the conduct of a trade or business in the United States, a non-U.S. holder generally must provide a properly executed IRS Form W-8BEN, for treaty benefits, or W-8ECI, for effectively connected income, before the payment of a dividend. These forms must be periodically

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updated. Special rules apply in the case of common stock held by a foreign entity treated as a partnership for U.S. federal tax purposes or by a foreign trust.
      A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the IRS.
Disposition of Common Stock
      A non-U.S. holder generally will not be subject to U.S. federal income tax, including by way of withholding, on gain recognized on a sale, exchange or other taxable disposition of our common stock unless any one of the following applies:
  The non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the sale, exchange or other taxable disposition (but nevertheless is treated as a nonresident because some or all of those days were not taken into account for purposes of determining whether the individual is a U.S. resident under the 183-day test described in the definition of “non-U.S. holder” above);
 
  The gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States or (if an applicable tax treaty requires) attributable to a U.S. permanent establishment or fixed base of such non-U.S. holder; or
 
  We are, or have been at any time during the five-year period preceding such disposition (or the non-U.S. holder’s holding period, if shorter), a “United States real property holding corporation,” unless (i) our common stock is regularly traded on an “established securities market,” as defined in applicable U.S Treasury regulations, and (ii) the non-U.S. holder holds no more than 5% of our outstanding common stock, directly or indirectly, during the relevant period (the “5% exception”). Generally, we will be a United States real property holding corporation if the fair market value of our U.S. real property interests equals or exceeds 50% of the sum of the fair market values of our worldwide real property interests and our other assets used or held for use in a trade or business, all as determined under applicable U.S Treasury regulations. Although we believe that we are not currently a United States real property holding corporation, and we do not expect to become a United States real property holding corporation, no assurances can be made in this regard.
      Non-U.S. holders described in the first bullet above are taxed on their gains (including gains from sales of our common stock and net of applicable U.S. losses from sales or exchanges of other capital assets incurred during the year) at a flat rate of 30% (which may be offset by U.S. source capital losses of the non-U.S. holder, if any). Non-U.S. holders to which the second or third bullet points above apply will be subject to tax on the net gain from the sale under regular U.S. federal income tax rates. If a non-U.S. holder to which the second or third bullet points apply is a corporation, it may be subject to the additional branch profits tax at a rate equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty. In addition, if we are determined to be a United States real property holding corporation and the 5% exception does not apply, then a purchaser may be required to withhold 10% of the proceeds payable to a non-U.S. holder from a sale or other taxable disposition of our common stock. This 10% withholding, if applicable, is not an additional tax, and amounts withheld may be credited against the non-U.S. holder’s federal income tax liability.
U.S. Federal Estate Taxes
      Our common stock beneficially owned or treated as beneficially owned by an individual who at the time of death is a non-U.S. holder, and certain lifetime transfers of an interest in our common stock made by such an individual, will be included in his or her gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise and, therefore, may be subject to U.S. federal estate tax. Estates of non-resident aliens are generally allowed a statutory credit that has the effect of offsetting the U.S. federal estate tax imposed on the first $60,000 of the taxable estate.

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Information Reporting and Backup Withholding
      For distributions paid to certain non-U.S. holders, we must report annually to the IRS and the non-U.S. holder the amount of the distributions and the tax withheld, if any. The information reporting requirement applies regardless of whether withholding was required. Copies of the information returns reporting those distributions and withholding, if any, may also be made available to the tax authorities in the country in which the non-U.S. holder is a resident under the provisions of an applicable income tax treaty or agreement. The gross amount of dividends paid to a non-U.S. holder subject to information reporting that fails to certify its non-U.S. holder status in accordance with applicable U.S. Treasury regulations may be subject to backup withholding at the applicable rate (currently 28%).
      U.S. information reporting and backup withholding generally will not apply to a payment of proceeds of a disposition of common stock where the transaction is effected outside the United States through a non-U.S. office of a non-U.S. broker. Information reporting, but not backup withholding, may apply to a payment effected outside the United States through a broker if the broker is (i) a U.S. person, including a non-U.S. branch of a U.S. person; (ii) a “controlled foreign corporation” as defined in the Code; (iii) a foreign partnership with certain U.S. connections, (iv) a foreign person for which 50% or more of its gross income for certain periods is treated as effectively connected with the conduct of a trade or business in the United States; or (v) a U.S. branch of a foreign bank or foreign insurance company.
      Backup withholding is not an additional tax. Amounts withheld under the backup withholding rules may be refunded or credited against the non-U.S. holder’s U.S. federal income tax liability, if any, provided that certain required information is furnished to the IRS in a timely manner.
      The foregoing discussion is only a summary of certain U.S. federal income and estate tax consequences of the acquisition, ownership and disposition of our common stock by non-U.S. holders. You are urged to consult your own tax advisor with respect to the particular tax consequences to you of ownership and disposition of our common stock, including the effect of any U.S., state, local, non-U.S. or other tax laws and any applicable income or estate tax treaty.

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UNDERWRITERS
      Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., are acting as representatives, have severally agreed to purchase, and we and the selling shareholders have agreed to sell to them, severally, the number of shares indicated below:
           
Name   Number of Shares
     
Morgan Stanley & Co. Incorporated
       
Lehman Brothers Inc. 
       
A.G. Edwards & Sons, Inc. 
       
       
 
Total
       
       
      The underwriters are offering the shares subject to their acceptance of the shares from us and the selling shareholders and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares offered by this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the shares offered by this prospectus if any such shares are taken. However, the underwriters are not required to take or pay for the shares covered by the underwriters’ over-allotment option described below.
      The underwriters initially propose to offer part of the shares directly to the public at the public offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $           per share under the public offering price. After the initial offering of the shares, the offering price and other selling terms may from time to time be varied by the representatives.
      The selling shareholders have granted to the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase up to an aggregate of                     additional shares of common stock at the public offering price shown on the cover page of this prospectus, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase about the same percentage of the additional shares of common stock as the number listed next to the underwriter’s name in the preceding table bears to the total number of shares of common stock listed next to the names of all underwriters in the preceding table. If the underwriters’ option is exercised in full, the total price to the public would be $          , the total underwriting discounts and commissions paid by us and by the selling shareholders would be $ and $          , respectively, and the total proceeds to us and the selling shareholders would be $          and $          , respectively.
      The underwriters have informed us that they do not intend sales to discretionary accounts to exceed five percent of the total number of shares of common stock offered by them.
      We and all of our executive officers and directors and all of our shareholders have agreed with the underwriters that, without the prior written consent of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., on behalf of the underwriters, we will not, during the period ending 180 days after the date of the final prospectus:
  offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend, or otherwise transfer or dispose of, directly or indirectly, any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock; or
 
  enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock,

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whether any such transaction described above is to be settled by delivery of common stock or such other securities, in cash or otherwise. The restrictions described in this paragraph do not apply to:
  the sale of shares by us to the underwriters;
 
  the issuance by us of shares of common stock upon the exercise of an option or a warrant or the conversion of a security outstanding on the date of this prospectus of which the underwriters have been advised in writing;
 
  the issuance by the Company of options or warrants to purchase shares of Common Stock under the Company’s Stock Incentive Plan, provided, however, that any shares issued pursuant to such plan shall be subject to the restrictions contained in the preceding paragraph;
 
  the issuance of not more than                      shares of Common Stock in connection with acquisitions of ethanol production sites, businesses, companies or assets by the Company;
 
  transactions by any person other than us relating to shares of common stock or other securities acquired in open market transactions after the completion of the offering of the shares;
 
  the transfer by any person other than us of shares of common stock or securities convertible into or exchangeable or exercisable for common stock as a bona fide gift;
 
  the transfer by any person of shares of common stock or securities convertible into or exercisable or exchangeable for common stock to us;
 
  the transfer by any person other than us of shares of common stock or securities convertible into common stock to limited partners or stockholders of that person;
 
  transfers of shares of Common Stock to any trust, partnership or limited liability company solely for the direct or indirect benefit of the undersigned or the immediate family of the undersigned;
 
  transfers of shares of Common Stock to any beneficiary of the undersigned pursuant to a will or other testamentary document or applicable laws of descent;
 
  transfers of shares of Common Stock to any wholly owned subsidiary of the undersigned or to the parent corporation of the undersigned or any wholly owned subsidiary of such parent corporation; and
 
  transfers of shares of Common Stock with the prior written consent of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc.
      With respect to the last nine bullets, it will be a condition to the transfer or distribution that the transferee execute a copy of the lock-up agreement, no filing by any party (donor, donee, transferor or transferee) under Section 16(a) of the Exchange Act, reporting a reduction in beneficial ownership of shares of common stock, shall be required or will be made voluntarily in connection with such transfer or distribution (other than a filing on Form 5 made after the expiration of the lock-up period), and that no such transfer or distribution may include a disposition for value.
      The lock-up period described in the preceding paragraph will be extended if:
  during the last 17 days of the lock-up period we issue a release about earnings or material news or events relating to us occurs; or
 
  prior to the expiration of the lock-up period, we announce that we’ll release earnings results during the 16-day period beginning on the last day of the lock-up period;
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the release or the occurrence of the material news or material event.
      The following table shows the per share and total underwriting discounts and commissions that we and the selling shareholders are to pay to the underwriters in connection with this offering. These amounts are

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shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares of our common stock.
                                                   
        Paid by Selling    
    Paid by Us   Shareholders   Total
             
    No   Full   No   Full   No   Full
    Exercise   Exercise   Exercise   Exercise   Exercise   Exercise
                         
Per share
  $       $       $       $       $       $    
 
Total
  $       $       $       $       $       $    
      In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. The underwriters may sell more shares than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of shares available for purchase by the underwriters under their over-allotment option. The underwriters can close out a covered short sale by exercising their over-allotment option or purchasing shares in the open market. In determining the source of shares to close out a covered short sale, the underwriters will consider, among other things, the open market price of shares compared to the price available under their over-allotment option. The underwriters may also sell shares in excess of their over-allotment option, creating a naked short position. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. In addition, to stabilize the price of the common stock, the underwriters may bid for, and purchase, shares of common stock in the open market. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer for distributing the common stock in the offering, if the syndicate repurchases previously distributed common stock to cover syndicate short positions or to stabilize the price of the common stock. These activities may raise or maintain the market price of the common stock above independent market levels or prevent or retard a decline in the market price of the common stock. The underwriters are not required to engage in these activities, and may end any of these activities at any time.
      We have applied to list our common stock on the New York Stock Exchange under the symbol “VSE.”
      From time to time, certain of the underwriters and their affiliates have provided and continue to provide investment banking and other services to us.
      A prospectus in electronic format may be made available on the websites maintained by one or more underwriters. The lead underwriters may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the lead underwriters to underwriters that may make internet distributions on the same basis as other allocations.
      We and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. The underwriters have agreed to reimburse us for certain identifiable expenses associated with this offering.
Directed Share Program
      At our request, the underwriters have reserved for sale, at the initial public offering price, up to                      shares of common stock offered in this prospectus for our directors, officers, employees, business associates and other related persons. Persons who purchase such reserved shares will be required to agree, during the period ending 180 days after purchasing such shares, not to sell, transfer, assign, pledge or hypothecate such shares. This lock-up period will be extended if, during the last 17 days of the lock-up period we issue a release about earnings or material news or events relating to us occurs; or, prior to the expiration of the lock-up period, we announce that we will release earnings results during the 16-day period beginning on the last day of the lock-up period, in which case the restrictions described above will continue to apply until the expiration of the 18-day period beginning on the issuance of the release or the occurrence of the material news or material event.

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      The number of shares of common stock available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered in this prospectus.
Pricing of the Offering
      Prior to this offering, there has been no public market for the shares of our common stock. The initial public offering price was determined by negotiations among us and the representatives of the underwriters. Among the factors considered in determining the initial public offering price were our future prospects and those of our industry in general, our sales, earnings and other financial operating information in recent periods, and the price-earnings ratios, market prices of securities and certain financial and operating information of companies engaged in activities similar to ours.

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LEGAL MATTERS
      The validity of the shares of common stock offered in this prospectus will be passed upon for us by Stoel Rives LLP, Portland, Oregon. Cadwell Sanford Deibert & Garry LLP will pass upon matters of South Dakota law. Sidley Austin LLP, Chicago, Illinois, will pass upon certain legal matters in connection with this offering for the underwriters.
EXPERTS
      The consolidated financial statements of VeraSun Energy Corporation and its subsidiaries as of December 31, 2004 and 2005 and for each of the three years in the period ended December 31, 2005, included in this prospectus, have been audited by McGladrey & Pullen, LLP, independent auditors, as stated in their report appearing herein.
WHERE YOU CAN FIND MORE INFORMATION
      We have filed with the Securities and Exchange Commission a registration statement on Form S-1 under the Securities Act with respect to this offering of common stock. This prospectus, which is a part of the registration statement, omits certain information included in the registration statement and the exhibits thereto. For further information with respect to us and the securities, we refer you to the registration statement and its exhibits. The descriptions of each contract and document contained in this prospectus are summaries and as such, may not provide all of the information necessary to fully evaluate each contract or document described in this prospectus. For this reason, we refer you to the copy of each such contract or document filed as an exhibit to the registration statement.
      You may read and copy any document we file with or furnish to the SEC at the SEC’s Public Reference Room at 100 F. Street, NE, Room 1580, Washington, DC 20549. You may also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F. Street, NE, Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room. In addition, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. You can review our SEC filings, including the registration statement by accessing the SEC’s Internet site at http://www.sec.gov.
      Upon the completion of this offering, unless we are earlier required to do so under the terms of the indenture governing our senior secured notes or upon the completion of the exchange offer involving the notes, we will file with the SEC periodic reports, proxy statements and other information required by the Exchange Act. Our SEC filings are also available at the New York Stock Exchange. For further information on obtaining copies of our public filings at the New York Stock Exchange, please call (212) 656-5060.
      Our website is www.verasun.com. The content of our website is not part of this prospectus.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
           
    Page
     
Financial Statements
       
      F-2  
      F-3  
      F-4  
      F-5  
      F-6  
      F-7  

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(MCGLADREY & PULLEN LOGO)
Report of Independent Registered Public Accounting Firm
To the Board of Directors
VeraSun Energy Corporation
Brookings, South Dakota
      We have audited the accompanying consolidated balance sheets of VeraSun Energy Corporation and subsidiaries as of December 31, 2004 and 2005, and the related consolidated statements of income, shareholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of VeraSun Energy Corporation and subsidiaries as of December 31, 2004 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.
  /s/ McGladrey & Pullen, LLP
Sioux Falls, South Dakota
March 8, 2006
McGladrey & Pullen, LLP is a member firm of RSM International,
an affiliation of separate and independent legal entities.

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VERASUN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2005
                     
    2004   2005
         
    (dollars in
    thousands, except
    per share data)
Assets (Note 7)
               
Current Assets
               
 
Cash and cash equivalents
  $ 10,296     $ 29,714  
 
Receivables (Notes 3, 6, 11, 15 and 16)
    14,748       28,663  
 
Inventories (Notes 4 and 6)
    12,448       19,291  
 
Prepaid expenses
    956       4,611  
 
Deferred income taxes (Note 9)
    2,877       5,839  
             
   
Total current assets
    41,325       88,118  
             
Other Assets
               
 
Restricted cash held in escrow (Note 7)
          124,750  
 
Interest rate swap (Note 11)
    94        
 
Debt issuance costs, net of amortization of $105 in 2004 and $39 in 2005 (Note 7)
    2,156       6,449  
 
Goodwill (Note 2)
          6,129  
             
      2,250       137,328  
             
Property and Equipment, net (Note 5)
    106,753       179,683  
             
    $ 150,328     $ 405,129  
             
 
Liabilities and Shareholders’ Equity
Current Liabilities
               
 
Current maturities of long-term debt (Note 7)
  $ 5,846     $  
 
Current portion of deferred revenue (Note 10)
    95       95  
 
Accounts payable
    20,561       20,055  
 
Accrued expenses
    1,229       1,991  
 
Derivative financial instruments (Note 11)
    3,815       4,426  
             
   
Total current liabilities
    31,546       26,567  
             
Long-Term Liabilities
               
 
Long-term debt, less current maturities (Note 7)
    52,535       208,719  
 
Deferred revenue, less current portion (Note 10)
    1,806       1,710  
 
Convertible put warrant (Note 8)
    4,649       7,458  
 
Deferred income taxes (Note 9)
    12,416       15,757  
             
      71,406       233,644  
             
Minority Interest in Subsidiary (Note 2)
    2,900        
             
Commitments and Contingencies (Notes 11 and 15)
               
Shareholders’ Equity (Notes 2, 9, 12 and 13)
               
 
Preferred stock, $0.01 par value; authorized 100,000,000 shares; none issued or outstanding
           
 
Common stock, $0.01 par value; authorized 250,000,000 shares; 43,254,539 and 62,492,722 shares issued and outstanding as of December 31, 2004 and 2005, respectively
    433       625  
 
Additional paid-in capital
    32,828       132,848  
 
Retained earnings
    13,609       13,862  
 
Deferred compensation (Note 12)
    (143 )     (107 )
 
Accumulated other comprehensive loss (Note 11)
    (2,251 )     (2,310 )
             
      44,476       144,918  
             
    $ 150,328     $ 405,129  
             
See Notes to Consolidated Financial Statements.

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VERASUN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31, 2003, 2004 and 2005
                             
    2003   2004   2005
             
    (dollars in thousands,
    except per share data)
Revenues:
                       
 
Net sales (Note 15)
  $ 10,884     $ 186,029     $ 235,440  
 
Other revenues, incentive income (Note 15)
    1,776       7,723       919  
                   
   
Total revenues
    12,660       193,752       236,359  
                   
Cost of goods sold:
                       
 
Costs and expenses of production
    8,450       154,021       198,183  
 
Loss on disposal of equipment
          1       2,640  
                   
   
Total cost of goods sold
    8,450       154,022       200,823  
                   
   
Gross profit
    4,210       39,730       35,536  
Selling, general and administrative expenses
    2,233       6,140       11,874  
                   
   
Operating income
    1,977       33,590       23,662  
                   
Other income (expense):
                       
 
Interest expense, including change in fair value of convertible put warrant of $566 in 2003, $3,481 in 2004 and $2,809 in 2005 (Notes 6, 7 and 8)
    (839 )     (8,892 )     (7,609 )
 
Other interest expense, loss on extinguishment of debt (Note 7)
                (15,744 )
 
Interest income
    11       182       448  
 
Other income
    14       33       17  
                   
      (814 )     (8,677 )     (22,888 )
                   
   
Income before income taxes and minority interest
    1,163       24,913       774  
Income taxes (Note 9)
    571       10,242       582  
                   
   
Income before minority interest
    592       14,671       192  
Minority interest in net loss of subsidiary (Note 2)
          100       61  
                   
   
Net income
  $ 592     $ 14,771     $ 253  
                   
Earnings per common share:
                       
 
Basic
  $ 0.02     $ 0.40     $ 0.01  
 
Diluted
    0.02       0.39       0.01  
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, 2003, 2004 AND 2005
                                                     
                    Accumulated    
        Additional   Retained       Other    
    Common   Paid-In   Earnings   Deferred   Comprehensive    
    Stock   Capital   (Deficit)   Compensation   Loss   Total
                         
    (dollars in thousands)
Balance, December 31, 2002
  $ 181     $ 10,140     $ (1,754 )   $     $     $ 8,567  
 
Issuance of 12,899,675 shares of common stock
    129       8,529                         8,658  
 
Comprehensive income:
                                               
   
Net income
                592                      
   
Unrealized loss on hedging activities
                            (223 )        
   
Comprehensive income
                                            369  
                                     
Balance, December 31, 2003
    310       18,669       (1,162 )           (223 )     17,594  
 
Issuance of 12,093,106 shares of common stock
    121       13,303                         13,424  
 
Issuance of restricted stock (Note 12)
    2       178             (180 )            
 
Amortization of deferred compensation
                      37             37  
 
Stock-based compensation (Note 12)
          678                         678  
 
Purchase of treasury stock
    (3 )     (210 )                       (213 )
 
Reissuance of treasury stock
    3       210                         213  
 
Comprehensive income:
                                               
   
Net income
                14,771                      
   
Unrealized loss on hedging activities
                            (2,028 )        
   
Comprehensive income
                                            12,743  
                                     
Balance, December 31, 2004
    433       32,828       13,609       (143 )     (2,251 )     44,476  
 
Issuance of 19,238,183 shares of common stock
    192       98,914                         99,106  
 
Stock-based compensation (Note 12)
          1,106                         1,106  
 
Amortization of deferred compensation
                      36             36  
 
Comprehensive income:
                                               
   
Net income
                253                      
   
Unrealized loss on hedging activities
                            (59 )        
   
Comprehensive income
                                            194  
                                     
Balance, December 31, 2005
  $ 625     $ 132,848     $ 13,862     $ (107 )   $ (2,310 )   $ 144,918  
                                     
See Notes to Consolidated Financial Statements.

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VERASUN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2003, 2004 AND 2005
                                 
    2003   2004   2005
             
    (dollars in thousands)
Cash Flows from Operating Activities
                       
 
Net income
  $ 592     $ 14,771     $ 253  
 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                       
   
Depreciation
    348       3,926       5,692  
   
Amortization of debt issuance costs and debt discount
    27       171       325  
   
Accretion of deferred revenue
    (8 )     (95 )     (96 )
   
Minority interest in net loss of subsidiary
          (100 )     (61 )
   
Debt issuance costs and debt discount expensed on extinguishment of debt
                2,387  
   
Change in fair value of convertible put warrant
    566       3,481       2,809  
   
Deferred income taxes
    571       10,127       410  
   
Loss on disposal of equipment
          1       2,640  
   
Stock-based compensation
          715       1,142  
   
Changes in current assets and liabilities:
                       
     
(Increase) decrease in:
                       
       
Receivables
    (10,216 )     (4,532 )     (13,915 )
       
Inventories
    (5,378 )     (7,070 )     (6,843 )
       
Derivative financial instruments
    (700 )     1,011       615  
       
Prepaid expenses
    (618 )     (338 )     (3,655 )
     
Increase (decrease) in:
                       
       
Accounts payable
    4,099       (1,761 )     5,020  
       
Accrued expenses
    76       551       762  
                   
       
Net cash provided by (used in) operating activities
    (10,641 )     20,858       (2,515 )
                   
Cash Flows from Investing Activities
                       
 
Investment in restricted cash
                (125,000 )
 
Proceeds from sale of equipment
          1       46  
 
Purchases of property and equipment
    (63,974 )     (25,215 )     (87,095 )
                   
       
Net cash used in investing activities
    (63,974 )     (25,214 )     (212,049 )
                   
Cash Flows from Financing Activities
                       
 
Outstanding checks in excess of bank balance
    738       (738 )      
 
Proceeds from long-term debt
    59,085       27,626       208,711  
 
Principal payments on long-term debt
          (27,822 )     (58,890 )
 
Net borrowings on notes payable
          1,000        
 
Net proceeds from issuance of common stock
    8,589       12,493       90,138  
 
Proceeds from issuance of minority interest in subsidiary
          3,000        
 
Proceeds from tax increment financing grant
    2,004              
 
Debt issuance costs paid
    (35 )     (938 )     (5,977 )
                   
       
Net cash provided by financing activities
    70,381       14,621       233,982  
                   
       
Net increase (decrease) in cash and cash equivalents
    (4,234 )     10,265       19,418  
Cash and Cash Equivalents
                       
 
Beginning
    4,265       31       10,296  
                   
 
Ending
  $ 31     $ 10,296     $ 29,714  
                   
See Note 19 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, 2005: VeraSun Aurora Corporation (“VAC”) (formerly known as VeraSun Energy Corporation), VeraSun Fort Dodge, LLC (“VFD”), VeraSun Charles City, LLC (“VCC”), VeraSun Welcome, LLC (“VW”), VeraSun Marketing, LLC (“VM”), and VeraSun BioDiesel, LLC (“VBD”). VFD was 91% owned as of December 31, 2004.
      VAC owns and operates an ethanol plant located near Aurora, South Dakota with a capacity of 120 million gallons per year. VFD owns and operates an ethanol plant located near Fort Dodge, Iowa with a capacity of 110 million gallons per year. VCC is a development stage company that is constructing an ethanol plant near Charles City, Iowa with a capacity of 110 million gallons per year. VW is a development stage company with no activities since its formation. VM markets and distributes E85 to gasoline retailers. VBD is also a development stage company that is researching the extraction of corn oil as an additional co-product in the ethanol production process. VEC and its subsidiaries are collectively referred to as the “Company”.
      A summary of the Company’s significant accounting policies follows:
      Principles of consolidation: The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation.
      Use of estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include the determination of the value of stock-based compensation and the value of the convertible put warrant.
      Revenue recognition: Revenue from the production of ethanol and related products is recorded when title transfers to customers. Ethanol and related products are generally shipped FOB shipping point.
      The Company receives incentives to produce ethanol from the State of South Dakota and from the United States Department of Agriculture. In accordance with the terms of these arrangements, incentive income is recorded based on the production of ethanol.
      Shipping costs incurred by the Company are recorded as a component of cost of goods sold. 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 $60, $1,001 and $1,037 in 2003, 2004 and 2005, respectively.
      Cash and cash equivalents: For the purposes of reporting cash flows, the Company considers all cash and money market accounts to be cash equivalents, except cash restricted for the construction of property and equipment. Cash and cash equivalents as of December 31, 2005 included amounts in money market mutual funds which are not federally insured and deposit accounts in excess of federally insured limits. The Company has not experienced any losses in such accounts.
      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

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
receivable is considered to be past due if any portion of the receivable balance is outstanding for more than 90 days.
      Inventories: Corn, chemicals, supplies and work in process inventories are stated at the lower of cost or market on the first-in first-out method. Ethanol and distillers grains are stated at the lower of average cost (determined quarterly) or market.
      Derivatives and hedging activities: Derivatives are recognized on the balance sheet at their fair value and are included in the accompanying balance sheets as “derivative financial instruments”. On the date the derivative contract is entered into, the Company may designate the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (“cash flow” hedge). Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income, net of tax effect, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable rate asset or liability are recorded in earnings). Changes in the fair value of undesignated derivative instruments are reported in current period earnings. For the statement of operations, the Company categorizes the cash flows relating to hedging activities in the same category as the item being hedged.
      The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedged transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
      The Company discontinues hedge accounting prospectively when (1) it is determined that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item (including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; or (3) the derivative is de-designated as a hedge instrument because it is unlikely that a forecasted transaction will occur or when management determines that designation of the derivative as a hedge instrument is no longer appropriate.
      When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with subsequent changes in its fair value recognized in current-period income. Effective September 1, 2005, the Company de-designated all of its exchange traded futures contracts related to its corn positions. Changes in the fair value of these economic hedges are included in cost of goods sold in the income statements. The Company continues to designate 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 designated as cash flow hedges are included in net sales and cost of goods sold, respectively.
      Income taxes: VeraSun, LLC (“VSL”) and VFD’s operations were taxed as partnerships under the provisions of the Internal Revenue Code through September 30, 2005 and November 30, 2005, respectively. Under these provisions, their net income (loss) was reported on the individual income tax returns of their members. Accordingly, no provision/benefit or asset/liability for income taxes was reflected in these financial statements relative to the income or loss of VSL or VFD through those dates for interests in those activities held by members other than VAC. Effective with the Company’s reorganization in 2005 (Note 2), income taxes payable to (refundable from) the Internal Revenue Service are calculated based on the consolidated

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
income of the Parent and all its subsidiaries. Prior to the reorganization, the income tax provision only related to the income of VAC.
      Deferred taxes are provided on an asset and liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carryforwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
      Debt issuance costs: Debt issuance costs are stated at cost, less accumulated amortization. Debt issuance costs are amortized over the term of the related debt by a method which approximates the interest method. Amortization of debt issuance costs was $8, $97 and $278 during 2003, 2004 and 2005, respectively. Future amortization of debt issuance costs, based on debt outstanding as of December 31, 2005, is expected to be approximately $927 for each upcoming year until 2012. The amounts outstanding in relation to the existing debt at the time of the refinancing in December 2005 of $1,917 were fully expensed in 2005 as part of loss on extinguishment of debt in the statement of income.
      Property and equipment: Property and equipment are stated at cost. Depreciation is computed by the straight-line method over the following estimated useful lives:
         
    Years
     
Land improvements
    15 - 39  
Buildings and improvements
    7 - 40  
Machinery and equipment
    5 - 39  
Office furniture and equipment
    3 - 10  
      Construction in progress will be depreciated upon the commencement of operations of the property, which is expected to occur in 2006.
      Goodwill: Goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually, or more frequently if certain impairment conditions arise.
      Convertible put warrant: The value of the convertible warrant is adjusted to the formula based put value. Changes in the put price are recognized on the balance sheet in the period of change and are included in the Company’s statements of income as interest expense.
      Deferred revenue: Proceeds received from the issuance of tax increment bonds are recorded as deferred revenue and are being amortized into income over the life of the related property and equipment, which is 21 years.
      Earnings per common share (“EPS”): Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur, using the treasury stock method, if securities or other obligations to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that shared in the Company’s earnings.

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
      A reconciliation of the income and common stock share amounts used in the calculation of basic and diluted EPS for the years ended December 31, 2005 follows:
                             
        Weighted    
        Average    
    Net   Shares   Per Share
    Income   Outstanding   Amount
             
2003:
                       
 
Basic EPS
  $ 592       30,380,082     $ 0.02  
 
Effects of dilutive securities:
                       
   
Exercise of stock options and warrants
          197,879        
                   
 
Diluted EPS
  $ 592       30,577,961     $ 0.02  
                   
2004:
                       
 
Basic EPS
  $ 14,771       36,738,191     $ 0.40  
 
Effects of dilutive securities:
                       
   
Exercise of stock options and warrants
          1,170,560       (0.01 )
                   
 
Diluted EPS
  $ 14,771       37,908,751     $ 0.39  
                   
2005:
                       
 
Basic EPS
  $ 253       44,810,490     $ 0.01  
 
Effects of dilutive securities:
                       
   
Exercise of stock options and warrants
          2,768,379        
                   
 
Diluted EPS
  $ 253       47,578,869     $ 0.01  
                   
      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 each of the three years in the period ended December 31, 2005 because the related performance conditions had not been met.
      Performance stock option awards of 972,785 at a weighted average exercise price of $1.02 during 2004 and performance stock option awards of 912,078 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 employee stock-based compensation in accordance with Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. No stock-based employee compensation is 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. Stock-based compensation is recognized in connection with the issuance of variable performance-based stock options and restricted stock. The following table illustrates the effect on net income on a proforma basis if the Company had applied the fair value recognition provisions of

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
Financial Accounting Standards Board (“FASB”) Statement No. 123, Accounting for Stock-Based Compensation, to stock-based employee compensation.
                           
    Years Ended December 31,
     
    2003   2004   2005
             
Net income, as reported
  $ 592     $ 14,771     $ 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
          472       754  
 
Deduct proforma employee stock-based compensation expense determined under fair value based method for all awards, net of related tax effects
    (40 )     (670 )     (1,713 )
                   
Pro forma net income (loss)
  $ 552     $ 14,573     $ (706 )
                   
Basic EPS:
                       
 
As reported
  $ 0.02     $ 0.40     $ 0.01  
 
Proforma
    0.02       0.40       (0.02 )
Diluted EPS:
                       
 
As reported
    0.02       0.39       0.01  
 
Proforma
    0.02       0.38       (0.02 )
      Recent accounting pronouncements: In November 2004, the FASB issued FASB Statement No. 151, Inventory Costs. FASB Statement No. 151 amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. FASB Statement No. 151 requires that those items be recognized as current period charges regardless of whether they meet the criterion of “so abnormal”. In addition, FASB Statement No. 151 requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. The provisions of FASB Statement No. 151 are effective for fiscal years beginning after June 15, 2005. The Company does not expect the implementation of FASB Statement No. 151 to have a material effect on the Company’s consolidated financial position or results of operations.
      In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), Share-Based Payment (“Statement No. 123R”) which is a revision of FASB Statement No. 123. FASB Statement No. 123R supersedes APB Opinion No. 25, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in FASB Statement No. 123R is similar to the approach described in FASB Statement No. 123. However, FASB Statement No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. FASB Statement No. 123R was adopted by the Company effective January 1, 2006 using the modified prospective application method described in FASB Statement No. 123R.
      As permitted by FASB Statement No. 123, the Company currently accounts for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognizes no compensation cost for fixed employee stock options. Accordingly, the adoption of FASB Statement No. 123R’s fair value method will have an impact on the Company’s results of operations, although it will have no impact on the Company’s overall financial position. The ultimate impact of the adoption of FASB Statement No. 123R cannot be predicted at this time because it will depend on levels of share-based payments granted in the future and other factors. However, had the Company adopted FASB Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of FASB Statement No. 123 as described in the disclosure of pro forma net income and earnings per share above. FASB Statement

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow rather than as an operating cash flow, as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. The Company is currently analyzing the impact of these provisions.
      Advertising costs: Advertising and promotion costs are expensed when incurred. Advertising costs during 2003, 2004 and 2005 were $74, $240 and $468, respectively.
      Research and development costs: Research and development costs are charged against income 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 $0, $11 and $217 for 2003, 2004 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 $10,296 and $29,714 at December 31, 2004 and 2005, respectively. The carrying amounts approximate their fair values due to the relatively short maturity of these instruments.
 
        Restricted cash held in escrow: The carrying value of restricted cash was $124,750 at December 31, 2005. The carrying amount approximates the fair value due to the relatively short maturity of the instruments.
 
        Long-term debt: The carrying value of fixed rate long-term debt was $26,202 at December 31, 2004. It is not practicable to estimate the fair value of fixed rate long-term debt at December 31, 2004 since these agreements contain unique terms, conditions and restrictions, which were negotiated at arm’s length and there is no readily determinable similar instrument on which to base an estimate of fair value. The carrying value of variable rate long-term debt of $32,179 at December 31, 2004, approximated fair value because the interest rates fluctuate with market rates. The carrying value and fair value of long-term debt was $208,719 and $213,150, respectively, at December 31, 2005. The fair value of the Company’s long-term debt at December 31, 2005 was estimated based on quoted market prices.
 
        Derivatives and warrants: The carrying values of commodity-based derivative financial instruments, the interest rate swap and convertible put warrant are $3,815, $94 and $4,649, respectively, at December 31, 2004 and $4,426, $0 and $7,458, respectively, at December 31, 2005. These instruments are recorded at fair value on the accompanying balance sheet, with such fair value determined based on quoted market prices or formula value.
      Segment reporting: Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company’s operating segments are aggregated into the “Ethanol Production” and “All Other” reportable segments because the long-term financial performance of these reportable segments is affected by similar economic conditions.
Note 2. Reorganization
      In October 2005, VAC shareholders approved a reorganization transaction in which its name was changed to VeraSun Aurora Corporation and VEC, a newly formed company, became its sole shareholder. As a result of this reorganization transaction, an aggregate of 31,161,539 shares of VEC’s common stock were issued in exchange for all outstanding shares of VAC common stock on a share for share basis. VEC assumed VAC’s stock incentive plan and all of VAC’s outstanding options and warrants.

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
      The shareholders of Parent subsequently approved a business combination with VSL, the former parent of VFD, under which VSL became a wholly owned subsidiary of the Parent and VFD became its indirect subsidiary. As a result of this business combination, an aggregate of 5,140,800 shares of Parent’s common stock were issued in exchange for all outstanding membership units of VSL based on the fair market value of common stock calculated on a discounted cash flows basis.
      On November 30, 2005, the Parent acquired 120 of the outstanding VFD Class B membership units by issuing approximately 7.0 million shares of its common stock to the holders of those Class B units based on the fair market value of common stock calculated on a discounted cash flows basis supplemented by the price received from sales of Company stock to outside interests.
      In addition, the Parent acquired 30 VFD Class B membership units held by minority interests in the consolidated subsidiary by issuing approximately 1.7 million shares. The Company recorded equity of $8,968 in conjunction with the acquisition of the minority interest of VFD using the purchase method of accounting, of which $6,129 is goodwill and $2,839 is the historical cost of the minority interest acquired. Goodwill was allocated to the “All Other” segment. On December 15, 2005, VSL was dissolved and the Parent acquired all of the Class A membership interests of VFD previously owned by VSL.
      All of the above transactions, with the exception of the acquisition of minority interests of VFD Class B units, were exchanges of ownership interests between entities under common control and were accounted for at historical cost in a manner similar to a pooling of interests. Shareholders’ equity was retroactively restated as if the exchanges were made on December 31, 2002.
Note 3. Receivables
      A summary of receivables at December 31 is as follows:
                 
    2004   2005
         
Trade and other, less allowance for doubtful accounts of $5 and $10 for 2004 and 2005, respectively
  $ 8,090     $ 20,074  
Incentive
    1,415       561  
Broker
    5,043       7,385  
Insurance claim
          500  
Restricted interest
          143  
Federal income taxes
    200        
             
    $ 14,748     $ 28,663  
             
Note 4. Inventories
      A summary of inventories at December 31 is as follows:
                 
    2004   2005
         
Corn
  $ 7,472     $ 9,023  
Supplies
    2,076       3,890  
Chemicals
    491       1,231  
Work in process
    561       1,150  
Distillers grains
    296       396  
Ethanol
    1,552       3,601  
             
    $ 12,448     $ 19,291  
             

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
Note 5. Property and Equipment
      A summary of property and equipment at December 31 is as follows:
                 
    2004   2005
         
Land and land improvements
  $ 6,202     $ 10,351  
Construction in progress
    26,875       991  
Buildings and improvements
    975       3,721  
Machinery and equipment
    76,209       172,688  
Office furniture and equipment
    766       1,681  
             
      111,027       189,432  
Less accumulated depreciation
    4,274       9,749  
             
    $ 106,753     $ 179,683  
             
      The Company incurred loss on disposal of equipment of $2,640 as the result of the VAC plant expansion in 2005.
Note 6. Notes Payable
      Credit facility: On December 21, 2005, the Company entered into an agreement for a $30,000 revolving credit agreement with a bank, with a $10,000 sublimit for letters of credit. Loan advances under the agreement have a borrowing base limitation based on a percentage of eligible receivables and outstanding inventory. As of December 31, 2005, funds of $24,070 were available to be drawn as computed under the borrowing base limitation, of which $2,710 in irrevocable stand-by letters of credit were outstanding, leaving $21,360 remaining borrowing capacity as of December 31, 2005. The agreement bears interest at 3.0% above the 3 month LIBOR rate (7.53% as of December 31, 2005) and has a final maturity of December 31, 2008. The agreement is secured by a first priority lien on all of the Parent’s and certain of its subsidiaries’ accounts receivable, inventory and the cash proceeds therefrom (including amounts received from insurance policies in respect thereof and deposit and securities accounts into which such proceeds are deposited). The agreement contains restrictive covenants relating to certain financial measurements and ongoing financial reporting requirements to the lender. In addition, the agreement provides for an unused commitment fee ranging from 0.15% to 0.25% (based on working capital levels) of the average unused portion of the $30,000 commitment after deducting any letters of credit outstanding under the agreement and a letter of credit fee equal to 2.25% of the amount of outstanding letters of credit. As of December 31, 2005, no loans were outstanding under the agreement.
      Related party notes: During 2004, the Company entered into a $1,000 unsecured line of credit promissory note and an unsecured term note with its Chief Executive Officer. These notes were paid in full in 2004. Total interest incurred under the notes was $32 during 2004.
      On July 28, 2005, the Company entered into a line of credit agreement of $1,000 with its Chief Executive Officer. On November 14, 2005, the Company issued a secured promissory note of $1,300 to its Chief Executive Officer. On November 14, 2005, the Company also issued an unsecured promissory note of $800 to its Chief Executive Officer. All of the notes were paid in full by December 2005. Total interest incurred under the notes was $24 during 2005.
      The Company paid $67 in 2004 and $108 in 2005 to a related party for consulting services. The Company no longer obtains these services with this related party.

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
      During 2004, a related party loaned the Company $1,000. This loan was converted into shares of common stock during 2004. Total interest incurred under the loan was $22 during 2004.
Note 7. Long-Term Debt and Restricted Cash
      Long-term debt at December 31 consists of:
                 
    2004   2005
         
9.875% Senior secured notes, due in semi-annual interest only payments for seven years commencing June 15, 2006, collateralized by a first priority lien on an initial $125,000 escrow and substantially all the assets of the Company except for assets pledged as security for the revolving credit agreement(a)
  $     $ 208,719  
Variable rate term note due to a bank (5.36% at December 31, 2004), paid in full in 2005
    28,810        
Variable rate term note due to a bank (5.86% at December 31, 2004), paid in full in 2005
    3,369        
13.5% Subordinated notes payable, paid in full in 2005
    19,491        
11.5% Subordinated notes payable, paid in full in 2005
    6,711        
             
      58,381       208,719  
Less current maturities
    5,846        
             
    $ 52,535     $ 208,719  
             
 
(a)  On December 21, 2005, the Company issued $210,000 of senior secured notes. The notes bear interest at a fixed rate of 9.875% and were issued with a debt discount in the amount of $1,289. During 2005, $8 of debt discount amortization was recognized. The notes mature in full on December 15, 2012 and may be prepaid prior thereto with a penalty. Interest is paid on a semi-annual basis in the amount of $10,369 on June 15 and December 15 of each year. The proceeds of the debt offering were used to refinance a portion of the Company’s existing debt and $125,000 was placed in escrow for the purpose of constructing a 110 million gallon per year ethanol plant near Charles City, Iowa. The indenture relating to the notes contains a number of restrictive covenants that limit the ability of the Parent and its subsidiaries to, among other things, incur additional indebtedness, pay dividends, make investments, enter into transactions with affiliates and other restrictions. The notes are collateralized by substantially all the assets of the Parent and certain of its subsidiaries, except for accounts receivable, inventory, commodities accounts and the cash proceeds therefrom and subject to various other exceptions.
     Restricted cash held in escrow as of December 31, 2005 consists of $124,750 of cash proceeds from the senior notes held for the construction of the VCC facility. Restricted cash held in escrow is held in one bank. Escrow funds are released upon the Company receiving permits and commencing construction on the VCC facility. If the Company does not meet the restrictions for breaking escrow or decides not to proceed with construction, the Company will be required to redeem the senior secured notes in an amount equal to the lesser of $125,000 or the balance remaining in escrow.
      In December 2005, the Company extinguished certain long-term debt with proceeds from the senior secured notes. The Company incurred prepayment penalties of $13,357 and expensed unamortized debt issuance costs and debt discount of $2,387, which are included as other interest expense, loss on extinguishment of debt, in the accompanying statement of income.
Note 8. Convertible Put Warrant
      The Company entered into a subordinated note purchase agreement in 2002, which provided for a commitment to issue subordinated secured notes in an aggregate principal amount of up to $20,000. During 2005, these notes were paid in full (Note 7). To induce the subordinated note holder (SNH) to enter into the note purchase agreement and to make extensions of credit thereunder, the Company granted warrants to

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VERASUN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(dollars in thousands, except per share data)
acquire 1,180,000 shares of common stock under the terms of the warrant agreement at an exercise price of $0.01 per share. The warrant expires December 23, 2012, provided that the Company gives the SNH at least 30 days notice of the expiration of the warrant. The warrant provides for the adjustment of the number of shares to be purchased if certain dilutive events occur. In accordance with the warrant agreement, at any time on or after the earlier of December 23, 2008 or a triggering event, but prior to the earlier of the expiration date of the warrants or the consummation of a qualified public offering, the SNH has a put right to require the Company to purchase all of the warrants at a value as determined under the agreement. The computed value of the warrant was $1,168, $4,649 and $7,458 at December 31, 2003, 2004 and 2005, respectively, primarily based upon the fair value of the related common stock. During 2003, 2004 and 2005, the change in the computed value of the warrant of $566, $3,481 and $2,809, respectively, was included in interest expense in the accompanying statements of income.
Note 9. Income Tax Matters
      Net deferred tax liabilities consist of the following components as of December 31, 2004 and 2005:
                     
    2004   2005
         
Deferred tax assets:
               
 
Loss carryforward
  $ 4,661     $ 6,096  
 
Derivative financial instruments
    1,191       1,261  
 
Organizational expenses
    656       2,509  
 
Other
    463       796  
             
      6,971       10,662  
             
Deferred tax liabilities:
               
 
Property and equipment
    (16,126 )     (19,640 )
 
Prepaid expenses
    (201 )     (898 )
 
Other
    (183 )     (42 )
             
      (16,510 )     (20,580 )
             
   
Net deferred tax liabilities
  $ (9,539 )   $ (9,918 )
             
      The components giving rise to the net deferred tax liabilities described above have been included in the accompanying balance sheets