Red Trail Energy (REGX) 10-K 2006 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934.

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

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

FOR THE TRANSITION PERIOD FROM            TO

COMMISSION FILE NUMBER: 000-1359687

RED TRAIL ENERGY, LLC

(Exact name of registrant as specified in its charter)

NORTH DAKOTA	76-0742311
(State or other jurisdiction	(IRS Employer
of incorporation or organization)	Identification No.)

P.O. Box 11
3682 Highway 8 South
Richardton, ND 58652
(Address and Zip Code of Principal Executive Offices)

(Registrant’s telephone number, including area code):(701) 974-3308

Securities register pursuant to Section 12(b) of the Exchange Act:None

Securities registered under Section 12(g) of the Exchange Act:None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

Indicated by checkmark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

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

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

Large accelerated filero      Accelerated Filero      Non-accelerated filerþ

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

     The aggregate market value of the member unit held by non-affiliates of the registrant was $29,678,494 as of December 31, 2006.

     As of April 17, 2007, the Company has issued 40,373,973 Class A Membership Units.

DOCUMENTS INCORPORATED BY REFERENCE:

     Pursuant to General Instruction G (3), we omit Part III, Items 10, 11, 12, 13, and 14 and incorporate such items by reference to an amendment to this Annual Report on Form 10-K or to a definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year covered by this Annual Report (December 31, 2006).

TABLE OF CONTENTS

	Page
PART I		1
ITEM 1. BUSINESS		1
ITEM 1A. RISK FACTORS		16
ITEM 2. PROPERTIES		24
ITEM 3. LEGAL PROCEEDINGS		24
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		25
PART II		25
ITEM 5. MARKET FOR REGISTRANT’S MEMBER UNITS, RELATED MEMBER MATTERS AND ISSUER PURCHASED OF EQUITY SECURITIES		25
ITEM 6. SELECTED FINANCIAL DATA		26
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION		26
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		38
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		38
ITEM 9A. CONTROLS AND PROCEDURES.		38
ITEMS 9B. OTHER INFORMATION		38
PART III		39
PART IV		40
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		40
Operating Agreement
Membership Control Agreement
First Amendment to Construction Loan Agreement
Revolving Promissory Note
Security Agreement and Deposit Account Control Agreement
Equity Grant Agreement
Option to Purchase
Audit Committee Charter
Senior Financial Officer Code of Conduct
Certification
Certification
Certification
Certification

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

     This annual report contains historical information, as well as forward-looking statements. These forward-looking statements include any statements that involve known and unknown risks and relate to future events and our expectations regarding future performance or conditions. Words such as “may,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,” “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions are intended to identify forward-looking statements, but are not the exclusive means of identifying such statements. These forward-looking statements, and others we make from time to time, are subject to a number of risks and uncertainties. Many factors could cause actual results to differ materially from those projected in forward-looking statements, including the risks described in Part I of this Annual Report. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include, but are not limited to:

• Projected growth, overcapacity or contraction in the ethanol market in which we operate;

• Fluctuations in the price and market for ethanol and distillers grains;

• Changes in plant production capacity, variations in actual ethanol and distillers grains production from expectations or technical difficulties in operating the plant;

• Availability and costs of products and raw materials, particularly corn and coal;

• Changes in our business strategy, capital improvements or development plans for expanding, maintaining or contracting our presence in the market in which we operate;

• Costs of equipment;

• Changes in interest rates and the availability of credit to support capital improvements, development, expansion and operations;

• Our ability to market and our reliance on third parties to market our products;

• Our ability to distinguish ourselves from our current and future competition;

• Changes to infrastructure, including

- expansion of rail capacity,

- possible future use of ethanol dedicated pipelines for transportation

- increases in truck fleets capable of transporting ethanol within localized markets,

- additional storage facilities for ethanol, expansion of refining and blending facilities to handle ethanol,

- growth in service stations equipped to handle ethanol fuels, and

- growth in the fleet of flexible fuel vehicles capable of using E85 fuel;

• Changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices such as:

- national, state or local energy policy;

- federal ethanol tax incentives;

- legislation mandating the use of ethanol or other oxygenate additives;

- state and federal regulation restricting or banning the use of MTBE;

- environmental laws and regulations that apply to our plant operations and their enforcement; or

- reduction or elimination of tariffs on foreign ethanol.

• Increased competition in the ethanol and oil industries;

• Fluctuations in US oil consumption and petroleum prices;

• Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agriculture, oil or automobile industries;

• Anticipated trends in our financial condition and results of operations;

• The availability and adequacy of our cash flow to meet our requirements, including the repayment of debt;

• Our liability resulting from litigation;

• Our ability to retain key employees and maintain labor relations;

• Changes and advances in ethanol production technology; and

• Competition from alternative fuels and alternative fuel additives.

     The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We do not undertake any duty to update forward-looking statements after the date they are made or to conform them to actual results or to changes in circumstances or expectations. Furthermore, we cannot guarantee future results, events, levels of activity, performance, or achievements. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. You should read this report and the documents that we reference in this report and have filed as exhibits, completely and with the understanding that our actual future results may be materially different from what we currently expect. We qualify all of our forward-looking statements by these cautionary statements.

PART I

ITEM 1. BUSINESS.

Overview

     Red Trail Energy, LLC (“Red Trail” or “Company”) owns and operates a 50 million gallon per year (“MMGY”) corn-based ethanol manufacturing plant located near Richardton, North Dakota in Stark County in western North Dakota (the “Plant”). (Red Trail is referred to in this report as “we,” “our,” or “us.”)

     Fuel grade ethanol is our primary product, accounting for the majority of our revenue. In late December 2006, the Plant processed approximately 97,490 bushels of corn, though we had not produced any ethanol by December 31, 2006. In fiscal year 2007, we anticipate that the Plant will produce approximately 50 million gallons of ethanol from approximately 18 million bushels of corn. However, there is no guarantee that we will be able to operate at these levels.

General Development of Business since January 1, 2006

     Red Trail was formed as a North Dakota limited liability company on July 16, 2003 and through December 2006 had spent substantially all of its efforts towards raising capital and debt financing and constructing its manufacturing Plant. On December 26 2006, we ground our first corn to start ethanol production. On January 1, 2007, we produced our first gallon of ethanol, and produced approximately 2.6 million gallons of ethanol during January 2007.

     Construction of the Plant was substantially completed and preliminary production operations commenced in December 2006. Production activities were minimal during 2006, and the Company exited its development stage in January 2007 when we began generating substantial revenues from ethanol production.

Available Information

     The public may read and copy materials we file with the Securities and Exchange Commission at the SEC’s Public Reference Room at 100 F Street NE, Washington, D.C., 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. 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. Reports we file electronically with the SEC may be obtained atwww.sec.gov.

     In addition, information about us is also available at our website atwww.redtrailenergyllc.com.The contents of our website are not incorporated by reference in this Annual Report on Form 10-K.

Financial Information

     Please refer to “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations”for information about our revenues, profit and loss measurements and total assets. Our consolidated financial statements and supplementary data are included beginning at page F-1 of this Annual Report.

Principal Products and Their Markets

     The principal products we produce at our Plant are fuel grade ethanol and distillers grains.

     Ethanol

     Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains. However, according to the Renewable Fuels Association, approximately 85 percent of ethanol in the United States today is produced from corn, and approximately 90 percent of ethanol is produced from corn and other input mix. Corn produces large quantities of carbohydrates, which convert into glucose more easily than most other kinds of

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biomass. The Renewable Fuels Association estimates current domestic ethanol production at approximately 5.28 billion gallons as of December 2006.

     An ethanol plant is essentially a fermentation plant. Ground corn and water are mixed with enzymes and yeast to produce a substance called “beer,” which contains about 10% alcohol and 90% water. The “beer” is boiled to separate the water, resulting in ethyl alcohol, which is then dehydrated to increase the alcohol content. This product is then mixed with a certified denaturant to make the product unfit for human consumption and commercially saleable.

     Ethanol can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based gasoline substitute. Approximately 95% of all ethanol is used in its primary form for blending with unleaded gasoline and other fuel products. Used as a fuel oxygenate, ethanol provides a means to control carbon monoxide emissions in large metropolitan areas. The principal purchasers of ethanol are petroleum terminals in the continental United States.

     For our fiscal year ended December 31, 2006, revenue from the sale of ethanol was approximately 0% of total revenues. We began generating revenues when ethanol shipments began in January 2007.

     Distillers Grains

     A principal co-product of the ethanol production process is distillers grains, a high protein, high-energy animal feed supplement primarily marketed to the dairy and beef industry. Distillers grains contain by-pass protein that is superior to other protein supplements such as cottonseed meal and soybean meal. By-pass proteins are more digestible to the animal, thus generating greater lactation in milk cows and greater weight gain in beef cattle. The dry mill ethanol processing used by the Plant results in two forms of distiller grains: Distillers Modified Wet Grains (“DMWG”) and Distillers Dried Grains with Solubles (“DDGS”). DMWG is processed corn mash that has been dried to approximately 50% moisture. DMWG have a shelf life of approximately ten days and are often sold to nearby markets. DDGS is processed corn mash that has been dried to 10% to 12% moisture. DDGS has an almost indefinite shelf life and may be sold and shipped to any market regardless of its vicinity to an ethanol plant. At our Plant, the composition of the distillers grains we produce is approximately 40% DMWG and 60% DDGS.

     For our fiscal year ended December 31, 2006, revenues from sale of distillers grains was approximately 0% of total revenues. We began generating revenues when distillers grains shipments began in January 2007.

Marketing and Distribution of Principal Products

     Our ethanol Plant is located near Richardton, North Dakota in Stark County, in the western section of North Dakota. We selected the Richardton site because of its location to existing coal supplies and accessibility to road and rail transportation. Our Plant is served by the Burlington Northern and Santa Fe Railway Company.

     We sell and market the ethanol and distillers grains produced at the Plant through normal and established markets, including local, regional and national markets. We have entered into a marketing agreement with Renewable Products Marketing Group (“RPMG”) to sell our ethanol. Whether or not ethanol produced by our Plant is sold in local markets will depend on decisions made by our marketer. Local ethanol markets may be limited and must be evaluated on a case-by-case basis. We have also entered into a marketing agreement with Commodity Specialist Company (“CSC”) for our dried distillers grains. We market and sell our wet distillers grains. Although local ethanol and distillers grains markets will be the easiest to service, they may be oversold, particularly in North Dakota. Oversold markets depress ethanol and distillers grains prices.

     Ethanol

     We have a marketing agreement with RPMG for the purposes of marketing and distributing all of the ethanol we produce at the Plant.

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     Distillers Grains

     We have a marketing agreement with CSC for the purpose of marketing and selling our dried distillers grains. For our dried distillers grains marketed and sold by CSC, we receive a percentage of the selling price actually received by CSC from its customers. We market and sell our wet distillers grains. Through the marketing of CSC and our relationships with local farmers, we are not dependent upon one or a limited number of customers for our distillers grains sales.

Dependence on One or a Few Major Customers

     We are substantially dependent upon RPMG for the purchase, marketing and distribution of our ethanol. RPMG purchases 100% of the ethanol produced at the Plant, all of which is marketed and distributed to its customers. Therefore, we are highly dependent on RPMG for the successful marketing of our ethanol. In the event that our relationship with RPMG is interrupted or terminated for any reason, we believe that another entity to market the ethanol could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale of ethanol and adversely affect our business and operations.

     We are substantially dependent on CSC for the purchase, marketing and distribution of our dried distillers grains. CSC purchases 100% of the dried distillers grains produced at the Plant, all of which are marketed and distributed to its customers. Therefore, we are highly dependent on CSC for the successful marketing of our dried distillers grains. In the event that our relationship with CSC is interrupted or terminated for any reason, we believe that another entity to market the dried distillers grains could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale of dried distillers grains and adversely affect our business and operations.

Seasonal Factors in Business

     In an effort to improve air quality in regions where carbon monoxide and ozone are a problem, the Federal Oxygen Program of the Federal Clean Air Act requires the sale of oxygenated motor fuels during the winter months in certain major metropolitan areas to reduce carbon monoxide pollution. Gasoline that is blended with ethanol has a higher oxygen content than gasoline that does not contain ethanol. As a result, we expect fairly light seasonality with respect to our gross profit margins on our ethanol, allowing us to, potentially, be able to sell our ethanol at a slight premium during the mandated oxygenate period. Conversely, we expect our average sales price for fuel grade ethanol during the summer, when fuel grade ethanol is primarily used as an octane enhancer or a fuel supply extender, to be a little lower.

Financial Information about Geographic Areas

     All of our operations and all of our long-lived assets are domiciled in the United States. We believe that all of the products we will sell to our customers in the future will be produced in the United States.

Sources and Availability of Raw Materials

     Corn Feedstock Supply

     The major raw material required for our ethanol plant to produce ethanol and distillers grain is corn. To operate at a name-plate capacity of 50 million gallons, the Plant requires a supply of approximately 18 million bushels of corn annually. We have entered into a Grain Origination Agreement with New Vision Coop to supply corn. To date, however, our Commodities Manager is buying our corn directly from other shuttle loaders, elevators and farmers. The New Vision Coop contract is in place in case we need someone to originate corn for us.

     Currently, we do not anticipate difficulty securing sufficient grain to operate the Plant. In January 2007, the United States Department of Agriculture’s 2006 Crop Production Summary listed national corn production at approximately 10.5 billion bushels, which would be the third largest corn crop on record, and North Dakota production at 15.54 million bushels. However, we expect that the increased demand of corn resulting from

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additional ethanol plants will lead to greater competition for corn in our geographic area, which we expect will lead to higher corn prices. A recent USDA report entitled “World Agricultural Supply and Demand Estimates” (February 9, 2007) states that U.S. corn prices could increase in year 2007 to as much as $3.40 per bushel or more. As of December 31, 2006, our average price per bushel was $3.23. While our surrounding area produces a significant amount of corn, our profitability may be negatively impacted if long-term corn prices remain high.

     In order to reduce the risk caused by marked fluctuations of corn prices, we enter into option and futures contracts. These contracts are used to fix the purchase price of our anticipated requirements of corn in production activities.

     Coal

     Coal is also an important input to our manufacturing process. During the year ended December 31, 2006, we used 650 tons of coal. We estimate that our current coal usage will be approximately 133,000 tons per year (375 tons of coal per operating day). We have a ten-year contract with General Industries, Inc., d/b/a Center Coal Company to deliver this coal. We use coal for all our energy needs which produces steam for distillation and all other corn processing, including drying our distillers grains products to moisture contents at which they can be stored for long periods and transported greater distances, so that we can market them to broader livestock markets, including poultry and swine markets in the continental United States.

     Since we started operations in January 2007, the Plant has experienced a number of shut-downs as a result of issues related to lignite quality and our coal combustor. We continue to discuss quality, delivery and other issues with Center Coal Company. We are working with our contractors on both short and long-term solutions. As a short-term solution, we are considering using powder river basin (“PRB”) coal as an alternative to lignite. We believe PRB coal may work better with the current coal combustor design. As a long-term solution, we are working with our contractors to find ways to modify the coal combustor so that we can continue using lignite. If we cannot modify the coal combustor to use lignite, we may have to use PRB coal instead of lignite as a long-term solution. Regardless of the resolution, we expect higher coal costs, either due to using the PRB coal, which costs more than lignite, or due to the possible increases in the cost to obtain lignite.

     Assuming we can utilize lignite, and despite the Center Coal Company contract, there can be no assurance that the coal we need will always be delivered as we need it, that we will receive the proper size or quality of coal or that our coal combustor will always work properly with lignite coal. Any disruption could either force us to reduce our operations or shut down the Plant, both of which would reduce our revenues.

     At least four other sources of lignite coal exist in the western portion of North Dakota and the total lignite coal production within North Dakota in 2003 was 30,750,000 tons, 29,943,000 tons in 2004 and 29,956,000 tons in 2005, according to the U.S. Energy Information Administration. Our needs constitute less than half of one percent of the total state production.

     We believe we could obtain alternative sources of coal if necessary, though we could suffer delays in delivery and higher prices that could hurt our business and reduce our revenues and profits. We believe there is sufficient supply of coal from the Powder River Basin coal regions in Wyoming and Montana to meet our demands. According to the U.S. Energy Information Administration in April 2006, Wyoming has estimated total coal reserves of 7,053 million tons and Montana has estimated total coal reserves of 1,140 millions tons. According to the U.S. Energy Information Administration, in 2004 Wyoming produced 396,493 thousand tons of coal and Montana produced 39,989 thousand tons of coal. If there is an interruption in the supply or quality of coal for any reason, we may be required to halt production. If production is halted for an extended period of time, it may have a material adverse affect on our operations, cash flows and financial performance.

     In addition to coal, we could use natural gas as a fuel source if our coal supply is significantly interrupted. There is a natural gas line within three miles of our Plant and we believe we could contract for the delivery of enough natural gas to operate our Plant. Natural gas tends to be significantly more expensive than coal and we would also incur significant costs to adapt our power systems to natural gas. Because we are already operating on coal, we do not expect to need natural gas.

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     Recently, the price of coal has risen along with other energy sources. Coal prices are considerably higher than the ten-year average, due to increased economic and industrial activity in the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. If we are unable to obtain coal through our contract with Center Coal Company, any ongoing increases in the price of coal will increase our cost of production and may negatively impact our future profit margins.

     Electricity

     The production of ethanol is a very energy intensive process that uses significant amounts of electricity. We have entered into a contract with West Plains Electric Cooperative, Inc. to provide our needed electrical energy. Despite this contract, there can be no assurance that they will be able to reliably supply the electricity that we need. If there is an interruption in the supply of energy for any reason, such as supply, delivery or mechanical problems, we may be required to halt production. If production is halted for an extended period of time, it may have a material adverse affect on our operations, cash flows and financial performance.

     Water

     Water supply is also an important consideration. To meet the Plant’s full operating requirements for water, we have entered into a ten-year contract with Southwest Water Authority (the “Authority”) to purchase raw water. Under the contract, we are required to purchase a minimum of 200 million gallons per year. Prior to connection, we were required to deposit with the Authority a prepayment of $80,000. After three years, if we have a consistent payment record, we may be allowed to apply $40,000 of the $80,000 to our water bill. The other $40,000 must remain in escrow until the end of the contract. Our cost for water under the contract is based on our proportionate share of the Authority’s operation, maintenance and replacement costs, excluding the cost of treatment, plus capital costs. The base rate for capital costs is $.72 per each 1,000 gallons of water. This base rate is subject to increase or decrease based on consumer price index changes. If there is an interruption in the supply of water for any reason, such as supply, delivery or mechanical problems, we may be required to halt production. If production is halted for an extended period of time, our revenues and profits will be reduced and it may have a material adverse affect on our operations, cash flows and financial performance.

     Much of the water used in an ethanol plant is recycled back into the process. There are, however, certain areas of production where fresh water is needed. Those areas include boiler makeup water and cooling tower makeup water. Boiler makeup water is treated on-site to minimize all elements that will harm the boiler and recycled water cannot be used for this process. Cooling tower water is deemed non-contact water because it does not come in contact with the mash and, therefore, can be regenerated back into the cooling tower process. The makeup water requirements for the cooling tower are primarily a result of evaporation. We expect that much of the water can be recycled back into the process, which will minimize the discharge water. This will have the long-term effect of lowering wastewater treatment costs.

Federal Ethanol Supports

     Various federal and state laws, regulations, and programs have led to an increasing use of ethanol in fuel, including subsidies, tax credits, policies and other forms of financial incentives. Some of these laws provide economic incentives to produce and blend ethanol, and others mandate the use of ethanol.

     The most recent ethanol supports are contained in the Energy Policy Act of 2005 (the “Act”). Most notably, the Act creates a 7.5 billion gallon renewable fuels standard (“RFS”). The RFS requires refiners, importers and blenders (“obligated parties”) to show that a required volume of renewable fuel is used in the nation’s fuel supply. The RFS began at 4 billion gallons in 2006 and will increase to 7.5 billion gallons by 2012. The RFS for 2007 is 4.7 billion gallons. The RFS is a national flexible program that does not require that any renewable fuels be used in any particular area or state, allowing refiners to use renewable fuel blends in those areas where it is most cost-effective. According to the Renewable Fuel Association, the RFS program is expected to lead to about $6 billion in new investment in ethanol plants across the country. An increase in the number of new plants will bring an increase in the supply of ethanol. Thus, while the Act may cause ethanol prices to increase in the short term due to additional demand, future supply could outweigh the demand for ethanol in the future. This would have a negative impact on our earnings.

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     On December 30, 2005, the Environmental Protection Agency (“EPA”) published an interim Direct Final Rule in the Federal Register imposing a 2.78% default provision (equating to 4 billion gallons of renewable fuel) of the RFS. The Direct Final Rule applies a collective compliance approach, meaning no refiner individually has to meet the standard, but that the industry as a whole will have to blend at least 2.78% renewable fuels into gasoline during 2006. Any shortfall in meeting this requirement would be added to the 4.7 billion gallon RFS requirement for 2007. There are no other consequences for failure to collectively meet the 2006 standard. Although there is not a requirement for individual parties to demonstrate compliance in 2006, the EPA found that increases in ethanol production and projections for future demand indicate that the 2006 volume is likely to be met and that more than 4 billion gallons of ethanol and biodiesel will be blended in 2006. An EPA brief explaining this action can be viewed on the EPA website located in the renewable fuels section.

     On September 7, 2006, the EPA published proposed final rules implementing the RFS program. The RFS program will apply in 2007 prospectively from the effective date of the final rule. The RFS for 2007 is 3.71% or 4.7 billion gallons of renewable fuel. The RFS must be met by obligated parties. Compliance with the RFS program will be shown through the acquisition of unique Renewable Identification Numbers (“RINs”) assigned by the producer to every batch of renewable fuel produced. The RIN shows that a certain volume of renewable fuel was produced. Obligated parties must acquire sufficient RINs to demonstrate compliance with their performance obligation. In addition, RINs can be traded and a recordkeeping and electronic reporting system for all parties that have RINs ensures the integrity of the RIN pool.

     RINs are valid for compliance purposes for the calendar year in which they were generated, or the following calendar year. No more than 20% of the current year obligation could be satisfied using RINs from the previous year. An obligated party may carry a deficit over from one year into the next if it cannot generate or purchase sufficient RINs to meet its renewable volume obligation. However, deficits cannot be carried over from one year into the next.

     The RFS system will be enforced through a system of registration, record keeping and reporting requirements for obligated parties and renewable fuels producers (“RIN generators”), as well as any party that procures or trades RINs either as part of their renewable fuels purchases or separately. Any person who violates any prohibition or requirement of the RFS program may be subject to civil penalties for each day of each violation. For example, under the proposed rule, a failure to acquire sufficient RINs to meet a party’s renewable fuels obligation would constitute a separate day of violation for each day the violation occurred during the annual averaging period. The enforcement provisions are necessary to ensure the RFS program goals are not compromised by illegal conduct in the creation and transfer of RINs.

     Historically, ethanol sales have also been favorably affected by the Federal Clean Air Act amendments of 1990, particularly the Federal Oxygen Program which became effective November 1, 1992. The Federal Oxygen Program requires the sale of oxygenated motor fuels during the winter months in certain major metropolitan areas to reduce carbon monoxide pollution. Ethanol use has increased due to a second Federal Clean Air Act program, the Reformulated Gasoline Program. This program became effective January 1, 1995, and requires the sale of reformulated gasoline in nine major urban areas to reduce pollutants, including those that contribute to ground level ozone, better known as smog.

     The two major oxygenates added to reformulated gasoline pursuant to these programs are Methyl Tertiary Butyl Ether (“MTBE”) and ethanol; however, MTBE has caused groundwater contamination and has been banned from use by many states. The Energy Policy Act of 2005 (the “Act”) did not impose a national ban of MTBE but it also did not include liability protection for manufacturers of MTBE. The failure to include liability protection for manufacturers of MTBE has resulted in refiners and blenders using ethanol as an oxygenate rather than MTBE to satisfy the reformulated gasoline oxygenate requirement. While this may create increased demand in the short-term, we do not expect this to have a long term impact on the demand for ethanol as the Act repeals the Federal Clean Air Act’s 2% oxygenate requirement for reformulated gasoline immediately in California and 270 days after enactment elsewhere. However, the Act did not repeal the 2.7% oxygenate requirement for carbon monoxide nonattainment areas which are required to use oxygenated fuels in the winter months. While we expect ethanol to be the oxygenate of choice in these areas, there is no assurance that ethanol will, in fact, be used.

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     The use of ethanol as an alternative fuel source has been aided by federal tax policy, which directly benefits gasoline refiners and blenders, and increases demand for ethanol. On October 22, 2004, President Bush signed H.R. 4520, which contained the Volumetric Ethanol Excise Tax Credit (“VEETC”) and amended the federal excise tax structure effective as of January 1, 2005. Prior to VEETC, ethanol-blended fuel was taxed at a lower rate than regular gasoline (13.2 cents on a 10% blend). Under VEETC, the ethanol excise tax exemption has been eliminated, thereby allowing the full federal excise tax of 18.4 cents per gallon of gasoline to be collected on all gasoline and allocated to the highway trust fund. We expect the highway trust fund to add approximately $1.4 billion to the highway trust fund revenue annually. In place of the exemption, the bill creates a new volumetric ethanol excise tax credit of 5.1 cents per gallon of ethanol blended at 10%. Refiners and gasoline blenders apply for this credit on the same tax form as before, only it is a credit from general revenue, not the highway trust fund. Based on volume, the VEETC is expected to allow much greater refinery flexibility in blending ethanol since it makes the tax credit available on all ethanol blended with all gasoline, diesel and ethyl tertiary butyl ether (“ETBE”), including ethanol in E85 and the E20 in Minnesota. The VEETC is scheduled to expire on December 31, 2010.

     The Energy Policy Act of 2005 expands who qualifies for the small ethanol producer tax credit. Historically, small ethanol producers were allowed a 10-cents-per-gallon production income tax credit on up to 15 million gallons of production annually. The size of the plant eligible for the tax credit was limited to 30 million gallons. Under the Energy Policy Act of 2005, the size limitation on the production capacity for small ethanol producers increases from 30 million to 60 million gallons. The credit can be taken on the first 15 million gallons of production. The tax credit is capped at $1.5 million per year per producer. The small ethanol producer tax credit is set to expire December 31, 2010.

     In addition, the Energy Policy Act of 2005 creates a new tax credit that permits taxpayers to claim a 30% credit (up to $30,000) for the cost of installing clean-fuel vehicle refueling equipment, such as an E85 fuel pump, to be used in a trade or business of the taxpayer or installed at the principal residence of the taxpayer. Under the provision, clean fuels are any fuel of at least 85% of the volume of which consists of ethanol, natural gas, compressed natural gas, liquefied natural gas, liquefied petroleum gas, and hydrogen and any mixture of diesel fuel and biodiesel containing at least 20% biodiesel. The provision is effective for equipment placed in service after December 31, 2005 and before December 31, 2010. While it is unclear how this credit will affect the demand for ethanol in the short term, we expect it will help raise consumer awareness of alternative sources of fuel and could positively impact future demand for ethanol.

Other Factors Affecting Demand and Supply

     In addition to government supports that encourage production and the use of ethanol, demand for ethanol may increase as a result of increased consumption of E85 fuel. E85 fuel is a blend of 70% to 85% ethanol and gasoline. According to the Energy Information Administration, E85 consumption is projected to increase from a national total of 11 million gallons in 2003 to 47 million gallons in 2025. The demand for E85 is largely driven by flexible fuel vehicle penetration of the US vehicle fleet, the retail price of E85 compared to regular gasoline and the availability of E85 at retail stations. In the U.S., there are currently about 6 million flexible fuel vehicles capable of operating on E85 and automakers have indicated plans to produce an estimated 2 million more flexible fuel vehicles per year. In addition, Ford and General Motors have national campaigns to promote ethanol and flexible fuel vehicles. Because flexible fuel vehicles can operate on both ethanol and gasoline, if the price of regular gasoline falls below E85, demand for E85 will decrease as well. In addition, gasoline stations offering E85 are relatively scarce. As of October 2006, just over 940 of the country’s 170,000 gas stations offered E85 as an alternative to ordinary gasoline (National Ethanol Vehicle Coalition, October 6, 2006). The Energy Policy Act of 2005 established a tax credit of 30% for infrastructure and equipment to dispense E85. This tax credit became effective in 2006 and is expected to encourage more retailers to offer E85 as an alternative to regular gasoline. The tax credit, unless renewed, will expire December 31, 2010.

     On October 5, 2006, Underwriters Laboratories (“UL”) suspended authorization for manufacturers to use UL Markings on components for fuel-dispensing devices that specifically reference compatibility with alcohol-blended fuels that contain greater than 15% ethanol. Published studies on ethanol indicate that, in higher concentrations, it may have significantly-enhanced corrosive effects versus traditional gasoline. While there have been no documented reports of corrosion for UL listed or recognized components used with E85, Underwriters Laboratories has suspended authorization to use the UL Mark on components used in dispensing devices that will

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dispense any alcohol-blended fuels containing over 15% alcohol until updated certification requirements are established and the effected components have been found to comply with them. The lack of a UL seal for filling station pumps carrying E85 means that some of these stations may be violating fire codes, and that new stations intending to install E85 systems may need waivers from local or state fire marshals. It is the decision of each authority having jurisdiction as to whether existing E85 dispensing equipment is allowed to remain in service or is taken out of service until additional supporting information is received. UL has not set a deadline for creating standards that could lead to certification, which could result in the closure of some existing E85 fueling stations and delay in opening others.

Our Competition

     We will be in direct competition with numerous other ethanol producers, many of whom have greater resources than we do. We also expect that additional ethanol producers will continue to enter the market if the demand for ethanol continues to increase. Ethanol is a commodity product, like corn, which means our ethanol Plant competes with other ethanol producers on the basis of price and, to a lesser extent, delivery service. We believe we compete favorably with other ethanol producers due to our proximity to coal supplies and multiple modes of transportation. In addition, we believe our Plant’s location offers an advantage over other ethanol producers in that it has ready access by rail to growing ethanol markets, which reduces our cost of sales.

     According to the RFA, the ethanol industry has grown to approximately 110 production facilities in the United States with current estimates of current domestic ethanol production at approximately 5.28 billion gallons as of December 2006. As reported by the RFA, excluding our Plant, North Dakota currently has four ethanol plants with the capacity to produce approximately 133.5 gallons annually. In addition, there are at least two ethanol plants under construction, expansion, or nearing construction within three (3) months in North Dakota, which will add over 200 million gallons of annual capacity. There are also numerous other producer and privately owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. The largest ethanol producers include Abengoa Bioenergy Corp., ADM, ASAlliances Biofuels, LLC, Aventine Renewable Energy, Inc., Cargill, Inc., The Andersons, US Bio Energy and VeraSun Energy Corporation, all of which are each capable of producing more ethanol than we expect to produce.

     The following table identifies most of the ethanol producers in the United States along with their production capacities.

			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
Abengoa Bioenergy Corp.	York, NE	Corn/milo		55
	Colwich, KS			25
	Portales, NM			30
	Ravenna, NE					88
Aberdeen Energy*	Mina, SD	Corn				100
Absolute Energy, LLC*	St. Ansgar, IA	Corn				100
ACE Ethanol, LLC	Stanley, WI	Corn		41
Adkins Energy, LLC*	Lena, IL	Corn		40
Advanced Bioenergy	Fairmont, NE	Corn				100
AGP*	Hastings, NE	Corn		52
Agra Resources Coop. d.b.a. EXOL*	Albert Lea, MN	Corn		40		8
Agri-Energy, LLC*	Luverne, MN	Corn		21
Alchem Ltd. LLLP	Grafton, ND	Corn		10.5
Al-Corn Clean Fuel*	Claremont, MN	Corn		35		15

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			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
Amaizing Energy, LLC*	Denison, IA	Corn		40
Archer Daniels Midland	Decatur, IL	Corn		1,070		275
	Cedar Rapids, IA	Corn
	Clinton, IA	Corn
	Columbus, NE	Corn
	Marshall, MN	Corn
	Peoria, IL	Corn
	Wallhalla, ND	Corn/barley
Arkalon Energy, LLC	Liberal, KS	Corn				110
ASAlliances Biofuels, LLC	Albion, NE	Corn				100
	Linden, IN	Corn				100
	Bloomingburg, OH	Corn				100
Aventine Renewable Energy, LLC	Pekin, IL	Corn		207
	Aurora, NE	Corn
Badger State Ethanol, LLC*	Monroe, WI	Corn		48
Big River Resources, LLC*	West Burlington, IA	Corn		52		50
Big River Resources Grinnell, LLC (joint venture with US Bio)	Grinnell, IA	Corn
Blue Flint Ethanol	Underwood, ND	Corn		50
Bonanza Energy, LLC	Garden City, KS	Corn/milo				55
Bushmills Ethanol, Inc.*	Atwater, MN	Corn		40
Cardinal Ethanol	Harrisville, IN	Corn				100
Cargill, Inc.	Blair, NE	Corn		85
	Eddyville, IA	Corn		35
Cascade Grain	Clatskanie, OR	Corn				108
CassCo Amaizing Energy, LLC	Atlantic, IA	Corn				110
Castle Rock Renewable Fuels, LLC	Necedah, WI	Corn				50
Center Ethanol Company	Sauget, IL	Corn				54
Central Indiana Ethanol, LLC	Marion, IN	Corn				40
Central Illinois Energy, LLC	Canton, IL	Corn				37
Central MN Ethanol Coop*	Little Falls, MN	Corn		21.5
Central Wisconsin Alcohol	Plover, WI	Seed corn		4
Chief Ethanol	Hastings, NE	Corn		62
Chippewa Valley Ethanol Co.*	Benson, MN	Corn		45
Commonwealth Agri-Energy, LLC*	Hopkinsville, KY	Corn		33
Corn, LP*	Goldfield, IA	Corn		50
Cornhusker Energy Lexington, LLC	Lexington, NE	Corn		40
Corn Plus, LLP*	Winnebago, MN	Corn		44
Coshoctan Ethanol, OH	Coshoctan, OH	Corn				60
Dakota Ethanol, LLC*	Wentworth, SD	Corn		50
DENCO, LLC	Morris, MN	Corn		21.5
Dexter Ethanol, LLC	Dexter, IA	Corn				100
E Energy Adams, LLC	Adams, NE	Corn				50
E3 Biofuels	Mead, NE	Corn				24
E Caruso (Goodland Energy Center)	Goodland, KS	Corn				20

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			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
East Kansas Agri-Energy, LLC*	Garnett, KS	Corn		35
Elkhorn Valley Ethanol, LLC	Norfolk, NE	Corn				40
ESE Alcohol Inc.	Leoti, KS	Seed corn		1.5
Ethanol2000, LLP*	Bingham Lake, MN	Corn		32
Ethanol Grain Processors, LLC	Obion, TN	Corn				100
First United Ethanol, LLC (FUEL)	Mitchell Co., GA	Corn				100
Frontier Ethanol, LLC	Gowrie, IA	Corn		60
Front Range Energy, LLC	Windsor, CO	Corn		40
Gateway Ethanol	Pratt, KS	Corn				55
Glacial Lakes Energy, LLC*	Watertown, SD	Corn		50		50
Global Ethanol/Midwest Grain Processors	Lakota, IA	Corn		95
	Riga, MI	Corn				57
Golden Cheese Company of California*	Corona, CA	Cheese whey		5
Golden Grain Energy, LLC*	Mason City, IA	Corn		60		50
Golden Triangle Energy, LLC*	Craig, MO	Corn		20
Grand River Distribution	Cambria, WI	Corn				40
Grain Processing Corp.	Muscatine, IA	Corn		20
Granite Falls Energy, LLC*	Granite Falls, MN	Corn		52
Great Plains Ethanol, LLC*	Chancellor, SD	Corn		50
Greater Ohio Ethanol, LLC	Lima, OH	Corn				54
Green Plains Renewable Energy	Shenandoah, IA	Corn				50
	Superior, IA	Corn				50
Hawkeye Renewables, LLC	Iowa Falls, IA	Corn		105
	Fairbank, IA	Corn		115
	Menlo, IA	Corn				100
Heartland Corn Products*	Winthrop, MN	Corn		35
Heartland Grain Fuels, LP*	Aberdeen, SD	Corn		9
	Huron, SD	Corn		12		18
Heron Lake BioEnergy, LLC	Heron Lake, MN	Corn				50
Holt County Ethanol	O'Neill, NE	Corn				100
Horizon Ethanol, LLC	Jewell, IA	Corn		60
Husker Ag, LLC*	Plainview, NE	Corn		26.5
Illinois River Energy, LLC	Rochelle, IL	Corn		50
Indiana Bio-Energy	Bluffton, IN	Corn				101
Iowa Ethanol, LLC*	Hanlontown, IA	Corn		50
Iroquois Bio-Energy Company, LLC	Rensselaer, IN	Corn		40
James Valley Ethanol, LLC	Groton, SD	Corn		50
KAAPA Ethanol, LLC*	Minden, NE	Corn		40
Kansas Ethanol, LLC	Lyons, KS	Corn				55
Land O’ Lakes*	Melrose, MN	Cheese whey		2.6
Levelland/Hockley County Ethanol, LLC	Levelland, TX	Corn				40
Lincolnland Agri-Energy, LLC*	Palestine, IL	Corn		48
Lincolnway Energy, LLC*	Nevada, IA	Corn		50
Liquid Resources of Ohio	Medina, OH	Waste Beverage		3
Little Sioux Corn Processors, LP*	Marcus, IA	Corn		52

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			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
Marquis Energy, LLC	Hennepin, IL	Corn				100
Marysville Ethanol, LLC	Marysville, MI	Corn				50
Merrick & Company	Golden, CO	Waste beer		3
MGP Ingredients, Inc.	Pekin, IL	Corn/wheat starch		78
	Atchison, KS
Michigan Ethanol, LLC	Caro, MI	Corn		50
Mid America Agri Products/Wheatland	Madrid, NE	Corn				44
Mid-Missouri Energy, Inc.*	Malta Bend, MO	Corn		45
Midwest Renewable Energy, LLC	Sutherland, NE	Corn		25
Millennium Ethanol	Marion, SD	Corn				100
Minnesota Energy*	Buffalo Lake, MN	Corn		18
Missouri Ethanol	Laddonia, MO	Corn		45
Missouri Valley Renewable Energy, LLC*	Meckling, SD	Corn				60
NEDAK Ethanol	Atkinson, NE	Corn				44
New Energy Corp.	South Bend, IN	Corn		102
North Country Ethanol, LLC*	Rosholt, SD	Corn		20
Northeast Biofuels	Volney, NY	Corn				114
Northeast Missouri Grain, LLC*	Macon, MO	Corn		45
Northern Lights Ethanol, LLC*	Big Stone City, SD	Corn		50
Northstar Ethanol, LLC	Lake Crystal, MN	Corn		52
Northwest Renewable, LLC	Longview, WA	Corn				55
Otter Creek Ethanol, LLC*	Ashton, IA	Corn		55
Otter Tail Ag Enterprises	Fergus Falls, MN	Corn				57.5
Pacific Ethanol	Madera, CA	Corn		35
	Boardman, OR	Corn				35
	Burley, ID	Corn				50
Panda Energy	Hereford, TX	Corn/milo				100
Panhandle Energies of Dumas, LP	Dumas, TX	Corn/Grain Sorghum				30
Parallel Products	Louisville, KY	Beverage waste		5.4
	R. Cucamonga, CA
Patriot Renewable Fuels, LLC	Annawan, IL	Corn				100
Penford Products	Ceder Rapids, IA	Corn				45
Permeate Refining	Hopkinton, IA	Sugars & starches		1.5
Phoenix Biofuels	Goshen, CA	Corn		25
Pinal Energy, LLC	Maricopa, AZ	Corn				55
Pine Lake Corn Processors, LLC*	Steamboat Rock, IA	Corn		20
Pinnacle Ethanol, LLC	Corning, IA	Corn				60
Plainview BioEnergy, LLC	Plainview, TX	Corn				100
Platinum Ethanol, LLC*	Arthur, IA	Corn				110
Plymouth Ethanol, LLC*	Merrill, IA	Corn				50
Poet*	Scotland, SD	Corn		11
Prairie Ethanol, LLC	Loomis, SD	Corn		60
Prairie Horizon Agri-Energy, LLC	Phillipsburg, KS	Corn		40

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			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
Premier Ethanol	Portland, IN	Corn				60
Pro-Corn, LLC*	Preston, MN	Corn		42
Quad-County Corn Processors*	Galva, IA	Corn		27
Red Trail Energy, LLC	Richardton, ND	Corn		50
Redfield Energy, LLC *	Redfield, SD	Corn				50
Reeve Agri-Energy	Garden City, KS	Corn/milo		12
Renew Energy	Jefferson Junction, WI	Corn				130
Siouxland Energy & Livestock Coop*	Sioux Center, IA	Corn		25		40
Siouxland Ethanol, LLC	Jackson, NE	Corn				50
Sioux River Ethanol, LLC*	Hudson, SD	Corn		50
Southwest Iowa Renewable Energy, LLC *	Council Bluffs, IA	Corn				110
Sterling Ethanol, LLC	Sterling, CO	Corn		42
Summit Ethanol	Leipsic, OH	Corn				60
Tall Corn Ethanol, LLC*	Coon Rapids, IA	Corn		49
Tama Ethanol, LLC	Tama, IA	Corn				100
Tate & Lyle	Loudon, TN	Corn		67		38
	Ft. Dodge, IA	Corn				105
The Andersons Albion Ethanol LLC	Albion, MI	Corn		55
The Andersons Clymers Ethanol, LLC	Clymers, IN	Corn				110
The Andersons Marathon Ethanol, LLC	Greenville, OH	Corn				110
Trenton Agri Products, LLC	Trenton, NE	Corn		40
United Ethanol	Milton, WI	Corn				52
United WI Grain Producers, LLC*	Friesland, WI	Corn		49
US BioEnergy Corp.	Albert City, IA	Corn		250		400
	Woodbury, MI	Corn
	Hankinson, ND	Corn
	Central City, NE	Corn
	Ord, NE	Corn
	Dyersville, IA	Corn
	Janesville, MN	Corn
U.S. Energy Partners, LLC (White Energy)	Russell, KS	Milo/wheat starch		48
Utica Energy, LLC	Oshkosh, WI	Corn		48
VeraSun Energy Corporation	Aurora, SD	Corn		230		330
	Ft. Dodge, IA	Corn
	Charles City, IA	Corn
	Welcome, MN	Corn
	Hartely, IA	Corn
Voyager Ethanol, LLC*	Emmetsburg, IA	Corn		52
Western New York Energy, LLC	Shelby, NY	Corn				50
Western Plains Energy, LLC*	Campus, KS	Corn		45
Western Wisconsin Renewable Energy, LLC*	Boyceville, WI	Corn		40
White Energy	Hereford, TX	Corn/Milo				100

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			Current		Under Construction/
			Capacity		Expansions
Company	Location	Feedstock	(mgy)		(mgy)
Wind Gap Farms	Baconton, GA	Brewery waste		0.4
Renova Energy	Torrington, WY	Corn		5
Xethanol BioFuels, LLC	Blairstown, IA	Corn		5		35
Yuma Ethanol	Yuma, CO	Corn				40
Total Current Capacity at 114 ethanol biorefineries				5,633.4
Total Under Construction (80)/Expansions (7)						6,394.9
Total Capacity				12,028.3

*	locally-owned
Updated: March 13, 2007

Competition from Alternative Ethanol Production Methods

     Alternative ethanol production methods are continually under development. New ethanol products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages and harm our business.

     Most ethanol is currently produced from corn and other raw grains, such as milo or sorghum - especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. Additionally, the enzymes used to produce cellulose-based ethanol have recently become less expensive. Furthermore, the Department of Energy and the President of the United States have announced support for the development of cellulose-based ethanol, including a $160 million Department of Energy program for pilot plants producing cellulose-based ethanol. Several large companies, including Iogen Corporation, Abengoa, Royal Dutch Shell Group, Goldman Sachs Group, Dupont and Archer Daniels Midland, have all indicated that they are interested in research and development in this area. In addition, Xethanol Corporation has stated plans to convert a six million gallon per year plant in Blairstown, Iowa to implement cellulose-based ethanol technologies after 2007. Poet Companies has also announced plans to expand Voyager Ethanol in Emmetsburg, Iowa to include cellulose to ethanol commercial production.

     Although current technology is not sufficiently efficient to be competitive on a large-scale, a 2005 report by the U.S. Department of Energy entitled “Outlook for Biomass Ethanol Production and Demand” indicates that new conversion technologies may be developed in the future. If an efficient method of collecting biomass for ethanol production and producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. We may not be able to cost-effectively convert the Plant into a plant that will use cellulose-based biomass to produce ethanol. As a result, it is possible we could be unable to produce ethanol as cost-effectively as cellulose-based producers.

     Competition with Ethanol Imported from Other Countries

     Ethanol production is also expanding internationally. Brazil has long been the world’s largest producer and exporter of ethanol; however, since 2005, U.S. ethanol production slightly exceeded Brazilian production. Ethanol is produced more cheaply in Brazil than in the United States because of the use of sugarcane, a less expensive raw material alternative to corn. However, in 1980, Congress imposed a tariff on foreign produced ethanol to make it more expensive than domestic supplies derived from corn. This tariff was designed to protect the benefits of the federal tax subsidies for United States farmers. In December 2006, legislation was passed in both the U.S. House of Representatives and U.S. Senate to extend the $0.54 per gallon tariff beyond its current expiration in December 2007 through 2008. We do not know the extent to which the volume of imports would increase or the effect on U.S. prices for ethanol if the tariff is not renewed.

     Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempted from this tariff under the Caribbean Basin Initiative. Under the terms of the Caribbean Basin Initiative, exports from member

13

nations are capped at 7.0% of the total United States production from the previous year (with additional exemptions from ethanol produced from feedstock in the Caribbean region over the 7.0% limit). However, as total production in the United States grows, the amount of ethanol produced from the Caribbean region and sold in the United States will also grow, which could impact our ability to sell ethanol.

     Competition from Alternative Fuels

     Our Plant also competes with producers of other gasoline additives having similar octane and oxygenate values as ethanol, such as producers of MTBE, a petrochemical derived from methanol that costs less to produce than ethanol. Although currently the subject of several state bans, many major oil companies can produce MTBE and because it is petroleum-based, its use is strongly supported by major oil companies.

     Alternative fuels, gasoline oxygenates and alternative ethanol production methods are also continually under development by ethanol and oil companies with far greater resources. The major oil companies have significantly greater resources than we have to develop alternative products and to influence legislation and public perception of MTBE and ethanol. New ethanol products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages and harm our business.

     A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological option to address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets in order to decrease fuel costs, lessen dependence on crude oil and reduce harmful emissions. If the fuel cell and hydrogen industries continue to expand and gain broad acceptance and hydrogen becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would negatively impact our profitability.

     Distillers Grains Competition

     Ethanol plants in the Midwest produce the majority of distillers grains and primarily compete with other ethanol producers in the production and sales of distillers grains. According to the Renewable Fuels Association, approximately 12 million metric tons of distillers grains were produced by ethanol plants in 2006. The amount of distillers grains produced is expected to increase significantly as the number of ethanol plants increase which will increase competition in the distillers grains market in our area. In addition, our distillers grains compete with other livestock feed products such as soybean meal, corn gluten feed, dry brewers grain and mill feeds.

Research and Development

     We do not conduct any research and development activities associated with the development of new technologies for use in producing ethanol or distillers grains.

Costs and Effects of Compliance with Environmental Laws

     We are subject to extensive air, water and other environmental regulations and we have been required to obtain a number of environmental permits to construct and operate the Plant. We have obtained all of the necessary permits to operate the Plant including air pollution permits, construction permits, a pollutant discharge elimination system general permit, storm water discharge permits, a water withdrawal permit and an alcohol fuel producer’s permit. In addition, we have completed a spill prevention control and countermeasures plan. As of December 31, 2006, we did not have our Title V permit, but expect to be applying for our Title V permit within the next twelve (12) months. On August 4, 2004, we received our Air Permit to construct and we commenced construction of the Plant on July 7, 2005. Although we have been successful in obtaining all of the permits currently required, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources on complying with such regulations.

14

     We expect to be subject to ongoing environmental regulations and testing. As of December 31, 2006, the Plant had not undergone emissions testing. We expect emissions compliance testing to take place within the next six (6) months.

     We are subject to oversight activities by the EPA. There is always a risk that the EPA may enforce certain rules and regulations differently than North Dakota’s environmental administrators. North Dakota or EPA rules are subject to change, and any such changes could result in greater regulatory burdens on our Plant operations. We could also be subject to environmental or nuisance claims from adjacent property owners or residents in the area arising from possible foul smells or other air or water discharges from the Plant. Such claims may result in an adverse result in court if we are deemed to engage in a nuisance that substantially impairs the fair use and enjoyment of real estate.

     The government’s regulation of the environment changes constantly. It is possible that more stringent federal or state environmental rules or regulations could be adopted, which could increase our operating costs and expenses. It also is possible that federal or state environmental rules or regulations could be adopted that could have an adverse effect on the use of ethanol. For example, changes in the environmental regulations regarding the required oxygen content of automobile emissions could have an adverse effect on the ethanol industry. Furthermore, Plant operations likely will be governed by the Occupational Safety and Health Administration (“OSHA”). OSHA regulations may change such that the costs of the operation of the Plant may increase. Any of these regulatory factors may result in higher costs or other materially adverse conditions affecting our operations, cash flows and financial performance.

Employees

     We presently have 38 full-time employees and two contract employees. The two contract employees are for the positions of President and General Manager, Mick Miller, and Plant Manager, Edward Thomas, who are contracted to work with us by GreenWay Consulting, LLC, a Minnesota limited liability company (“GreenWay”), our management consultants. Currently, eight of our employees are primarily involved in management and administration and the remainder are primarily involved in Plant operations. We expect that our costs for the first year of operations for employees will be approximately $1,800,000 plus $85,000 for a Plant Manager and $130,000 for a General Manager. Employee costs for the fiscal year ended December 31, 2006, for salaries and benefits, were approximately $650,000 plus an additional approximate $165,000 for contract employees.

     The following table represents the our current positions.

	# Full-Time
Position	Personnel
General Manager (Contract Personnel)		1
Plant Manager (Contract Personnel)		1
Chief Financial Officer		1
Commodities Manager		1
Accounting/Marketing		1
Lab Manager		1
Lab Technician		1
Administrative Assistant		1
Shift Supervisors		4
Material Handlers		3
Maintenance Manager		1
Maintenance Supervisor		1
Maintenance Craftsmen		5
Plant Operators		16
Operations Supervisor		1
Scale Operator		1
TOTAL		40

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          We enter into written confidentiality and assignment agreements with our executive officers and employees. Among other things, these agreements require such executive officers and employees to keep all proprietary information developed or used by us in the course of our business strictly confidential.

          Our success depends in part on our ability to attract and retain qualified personnel at a competitive wage and benefit level. We must hire qualified managers, accounting and other personnel. We operate in a rural area with low unemployment. There is no assurance that we will be successful in attracting and retaining qualified personnel at a wage and benefit structure at or below those we have assumed in our project. If we are unsuccessful in this regard, we may not be competitive with other ethanol plants, which could increase our operating costs and decrease our revenues and profits.

ITEM 1A. RISK FACTORS.

          You should carefully read and consider the risks and uncertainties below and the other information contained in this Report. 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 currently deem immaterial could impair our financial condition and results of operation.

Risks Relating to Our Business

          We have a limited operating history and our business may not be as successful as we anticipate.We began our business in 2003 and commenced full production of ethanol at our Plant in January 2007. Accordingly, we have a limited operating history from which you can evaluate our business and prospects. Our operating results could fluctuate significantly in the future as a result of a variety of factors, including those discussed throughout these risk factors. Many of these factors are outside our control. As a result of these factors, our operating results may not be indicative of future operating results and you should not rely on them as indications of our future performance. In addition, our prospects must be considered in light of the risks and uncertainties encountered by an early-stage company and in rapidly evolving markets, such as the ethanol market, where supply and demand may change significantly in a short amount of time. Some of these risks relate to our potential inability to:

• effectively manage our business and operations;

• recruit and retain key personnel;

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

• manage rapid growth in personnel and operations;

• develop new products that complement our existing business; and

• successfully address the other risks described throughout this Report.

          If we cannot successfully address these risks, our business, future results of operations and financial condition may be materially adversely affected, and we may continue to incur operating losses in the future.

          Our business is not diversified.Our success depends largely upon our ability to profitably operate our ethanol Plant. We do not have any other lines of business or other sources of revenue if we are unable to operate our ethanol Plant and manufacture ethanol and distillers grains. If economic or political factors adversely affect the market for ethanol, we have no other line of business to fall back on if the ethanol business declines. Our business would also be significantly harmed if the Plant could not operate at full capacity for any extended period of time.

          Our financial performance is significantly dependent on corn and coal prices and generally we cannot pass on increases in input prices to our customers.Our results of operations and financial condition are significantly affected by the cost and supply of corn and coal. Changes in the price and supply of corn and coal are subject to and determined by market forces over which we have no control

          Ethanol production requires substantial amounts of corn. Corn, as with most other crops, is affected by weather, disease and other environmental conditions. The price of corn is also influenced by general economic, market and government factors. These factors include weather conditions, farmer planting decisions, domestic and foreign government farm programs and policies, global demand and supply and quality. Changes in the price of

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corn can significantly affect our business. Generally, higher corn prices will produce lower profit margins and, therefore, represent unfavorable market conditions. This is especially true if market conditions do not allow us to pass along increased corn costs to our customers. The price of corn has fluctuated significantly in the past and may fluctuate significantly in the future. Corn prices recently have been significantly higher than the 10-year average. If a period of high corn prices were to be sustained for some time, such pricing may reduce our ability to generate revenues because of the higher cost of operating and may make ethanol uneconomical to use in fuel markets. We cannot offer any assurance that we will be able to offset any increase in the price of corn by increasing the price of our products. If we cannot offset increases in the price of corn, our financial performance may be materially and adversely affected.

     We seek to minimize the risks from fluctuations in the prices of corn through the use of hedging instruments. However, these hedging transactions also involve risks to our business. See “Item 1A. Risks Relating to Our Business —We engage in hedging transaction which involve risks that can harm our business.”

     The prices for and availability of coal may be subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices as a result of colder than average weather conditions, overall economic conditions and foreign and domestic governmental regulations and relations. Significant disruptions in the supply of coal could impair our ability to manufacture ethanol for our customers. Furthermore, long-term increases in coal prices or changes in our costs relative to energy costs paid by competitors may adversely affect our results of operations and financial condition.

     Recently, the price of coal has risen along with other energy sources. Coal prices are considerably higher than the 10-year average, due to increased economic and industrial activity in the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. Any ongoing increases in the price of coal will increase our cost of production and may negatively impact our future profit margins.

     The spread between ethanol and corn prices can vary significantly and we do not expect the spread to remain at recent high levels.Corn costs significantly impact our cost of goods sold. Our gross margins are principally dependent upon the spread between ethanol and corn prices. Recently, the spread between ethanol and corn prices has been at historically high level, due in large part to high oil prices. However, this spread has reduced as corn prices have increased dramatically since August 2006. Any further reduction in the spread between ethanol and corn prices, whether as a result of higher corn prices or lower ethanol prices, would adversely affect our results of operations and financial condition.

     Our revenues will be greatly affected by the price at which we can sell our ethanol and distillers grains.These prices can be volatile as a result of a number of factors. These factors include the overall supply and demand, the price of gasoline, level of government support, and the availability and price of competing products. For instance, the price of ethanol tends to increase as the price of gasoline increases, and the price of ethanol tends to decrease as the price of gasoline decreases. Any lowering of gasoline prices will likely also lead to lower prices for ethanol, which may decrease our ethanol sales and reduce revenues.

     The price of ethanol has recently been much higher than its 10-year average. We do not expect these prices to be sustainable as supply from new and existing ethanol plants increases to meet increased demand. Increased production of ethanol may lead to lower prices. The increased production of ethanol could have other adverse effects. For example, the increased production could lead to increased supplies of co-products from the production of ethanol, such as distillers grains. Those increased supplies could outpace demand, which would lead to lower prices for those co-products. Also, the increased production of ethanol could result in increased demand for corn. This could result in higher prices for corn and corn production creating lower profits. There can be no assurance as to the price of ethanol or distillers grains in the future. Any downward changes in the price of ethanol and/or distillers grains may result in less income, which would decrease our revenues and profitability.

     We sell all of the ethanol we produce to Renewable Products Marketing Group (“RPMG”) in accordance with an ethanol marketing agreement.RPMG is the sole buyer of all of our ethanol and we rely heavily on its marketing efforts to successfully sell our product. Because RPMG sells ethanol for a number of other producers, we have limited control over its sales efforts. Our financial performance is dependent upon the financial health of RPMG, as a significant portion of our accounts receivable are attributable to RPMG. If RPMG breaches

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the ethanol marketing agreement or is not in the financial position to purchase all of the ethanol we produce, we could experience a material loss and we may not have any readily available means to sell our ethanol and our financial performance will be adversely and materially affected. If our agreement with RPMG terminates, we may seek other arrangements to sell our ethanol, including selling our own product, but we give no assurance that our sales efforts would achieve results comparable to those achieved by RPMG.

     We currently buy all of our coal from General Industries, Inc., d/b/a Center Coal Company (“Center Coal”).Center Coal is currently the sole provider of all of our lignite coal and we rely on them for the lignite to run our Plant. If Center Coal cannot or will not deliver the lignite coal pursuant to the contract terms, our business will be materially and adversely affected. If our contract with Center Coal terminates, we would seek alternative supplies of coal, either lignite or other coal types, but we may not be able to obtain the coal we need on favorable terms, if at all. If we cannot obtain an adequate supply of coal at reasonable prices, or enough coal at all, our financial condition would suffer and we could be forced to reduce or shut down operations.

     We engage in hedging transactions, which involve risks that can harm our business.We are exposed to market risk from changes in commodity prices. Exposure to commodity price risk results from our dependence on corn and coal in the ethanol production process. We may seek to minimize the risks from fluctuations in the prices of corn through the use of hedging instruments. The effectiveness of any future hedging strategies is dependent upon the cost of corn our ability to sell sufficient products to use all of the corn for which we have futures contracts. There is no assurance that our hedging activities will successfully reduce the risk caused by price fluctuation, which may leave us vulnerable to high corn prices. Alternatively, we may choose not to engage in corn hedging transactions in the future. As a result, our results of operations and financial conditions may also be adversely affected during periods in which corn prices increase.

     We are also exposed to market risk from changes in the price of ethanol. To manage our ethanol price risk, RPMG will have a percentage of our future production gallons contracted through fixed price contracts, ethanol rack hedges and gas plus hedges. There is no assurance that our hedging activities will successfully reduce the risk caused by price fluctuation, which may leave us vulnerable to fixed contracts below the current market value for ethanol. Alternatively, we may choose not to engage in ethanol hedging transactions in the future. As a result, our results of operations and financial conditions may also be adversely affected during periods in which ethanol prices decrease.

     Hedging activities themselves can result in costs because price movements in corn and ethanol contracts are highly volatile and are influenced by many factors that are beyond our control. There are several variables that could affect the extent to which our derivative instruments are impacted by price fluctuations in the cost of corn and ethanol. However, it is likely that commodity cash prices will have the greatest impact on the derivatives instruments with delivery dates nearest the current cash price. We may incur such costs and they may be significant.

     We have derivative instruments in the form of interest rate swaps in an agreement with bank financing. Market value adjustments and net settlements related to these agreements are recorded as a gain or loss from non-designated hedging activities. Significant increases in the variable rate could greatly affect the operations of the Company.

     Operational difficulties at our Plant could negatively impact our sales volumes and could cause us to incur substantial losses.Our operations are subject to labor disruptions, unscheduled downtime and other operational hazards inherent in our industry, such as equipment failures, fires, explosions, abnormal pressures, blowouts, pipeline ruptures, transportation accidents and natural disasters. Some of these operational hazards may cause personal injury or loss of life, severe damage to or destruction of property and equipment or environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. Our insurance may not be adequate to fully cover the potential operational hazards described above or we may not be able to renew this insurance on commercially reasonable terms or at all.

     Moreover, our Plant may not operate as planned or expected. Our Plant has a specified nameplate capacity, which represents the production capacity specified in the applicable design-build agreement. In the event our Plant does not run at its name-plate levels, our business, results of operations and financial condition may be materially adversely affected.

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

     Our business also depends on the continuing availability of raw materials, including corn and coal. The production of ethanol, from the planting of corn to the distribution of ethanol to refiners, is highly energy-intensive. Significant amounts of fuel are required for the growing, fertilizing and harvesting of corn, as well as for the fermentation, distillation and transportation of ethanol and coal for the drying of distillers grains. A serious disruption in supplies of fuel or coal, or significant increases in the prices of fuel or coal, could significantly reduce the availability of raw materials at our Plant, increase our production costs and could have a material adverse effect on our business, results of operations and financial condition.

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

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

     Technological advances could significantly decrease the cost of producing ethanol or result in the production of higher-quality ethanol, and if we are unable to adopt or incorporate technological advances into our operations, our Plant could become uncompetitive or obsolete.We expect that technological advances in the processes and procedures for processing ethanol will continue to occur. It is possible that those advances could make the processes and procedures that we utilize at our Plant less efficient or obsolete, or cause the ethanol we produce to be of a lesser quality. Advances and changes in the technology of ethanol production are expected to occur. Such advances and changes may make the ethanol production technology installed in our Plant less desirable or obsolete. These advances could also allow our competitors to produce ethanol at a lower cost than us. If we are unable to adopt or incorporate technological advances, our ethanol production methods and processes could be less efficient than our competitors, which could cause our Plant to become uncompetitive or completely obsolete. If our competitors develop, obtain or license technology that is superior to ours or that makes our technology obsolete, we may be required to incur significant costs to enhance or acquire new technology so that our ethanol production remains competitive. Alternatively, we may be required to seek third-party licenses, which could also result in significant expenditures. We cannot guarantee or assure you that third-party licenses will be available or, once obtained, will continue to be available on commercially reasonable terms, if at all. These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income.

     Ethanol production methods are also constantly advancing. Most ethanol is currently produced from corn and other raw grains, such as milo or sorghum — especially in the Midwest. However, the current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass such as agricultural waste, forest residue and municipal solid waste. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas that are unable to grow corn. Another trend in ethanol production research is to produce ethanol through a chemical process rather than a fermentation process, thereby significantly increasing the ethanol yield per pound of feedstock. Although current technology does not allow these production methods to be competitive, new technologies may develop that would allow these methods to become viable means of ethanol

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production in the future. If we are unable to adopt or incorporate these advances into our operations, our cost of producing ethanol could be significantly higher than those of our competitors, which could make our Plant obsolete.

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

Risks Related to Conflicts of Interest

     Our governors have other business and management responsibilities, which may cause conflicts of interest, including working with other ethanol plants and in the allocation of their time and services to our project.Some of our governors are involved in third party ethanol-related projects that might compete against the ethanol and co-products produced by our Plant. Our governors may also provide goods or services to us or our contractors or buy our ethanol co-products. We have not adopted a board policy restricting such potential conflicts of interests at this time. Our governors have adopted procedures for reviewing potential conflicts of interests; however, we cannot be assured that these procedures will ensure that conflicts of interest are avoided.

     In addition, our governors have other management responsibilities and business interests apart from us. These responsibilities include, but may not be limited to, being the owner and operator of non-affiliated business that our governors and executive officers derive the majority of their income from and to which they devote most of their time. We generally expect that each governor attend our monthly board meetings, either in person or by telephone, and attend any special board meetings in the same manner. Historically, our board meetings have lasted between three and six hours each, not including any preparation time before the meeting. Therefore, our governors may experience conflicts of interest in allocating their time and services between us and their other business responsibilities. In addition, conflicts of interest may arise because of their position to substantially influence our business and management because the governors, either individually or collectively, hold a substantial percentage of the units of our company.

     We may have conflicting interests with GreenWay Consulting, LLC (“GreenWay”) that could cause GreenWay to put its interests ahead of ours.GreenWay has and continues to advise our governors and has been, and is expected to be, involved in substantially all material aspects of operations. In addition, Mick Miller, our President and General Manager and Edward Thomas, our Plant Manager, are employees of GreenWay. Consequently, the terms and conditions of any future agreements and understandings with GreenWay may not be as favorable to us as they could be if they were to be obtained from other third parties. In addition, because of the extensive role that GreenWay had in the construction of the Plant and has in its operations, it may be difficult or impossible for us to enforce claims that we may have against GreenWay. Such conflicts of interest may reduce our profitability.

Risks Related to Taxes

     Income Taxes.We are a limited liability company and, subject to complying with certain safe harbor provisions to avoid being classified as a publicly traded partnership, we expect to be taxed as a partnership for federal income tax purposes. Our Member Control Agreement provides that no member shall transfer any unit if, in the determination of the board, such transfer would cause us to be treated as a publicly traded partnership, and any transfer of unit(s) not approved by the Board of Governors or that would result in a violation of the restrictions in the agreement would be null and void. In addition, as a condition precedent to any transfer of units, we have the right under the Member Control Agreement to seek an opinion of counsel that such transfer will not cause us to be treated as a publicly traded partnership. As a non-publicly traded partnership we are a pass-through entity and not subject to income tax at the company level. Our income is passed through to our members. If we become a publicly traded partnership we will be taxed as a C Corporation. We believe this would be harmful to us and to our members because we would cease to be a pass-through entity. We would be subject to income tax at the company level and members would also be subject to income tax on distributions they receive from us. This would have the affect of lowering our after-tax income and amount available for distributions to members and cash available to pay debt obligations and for operations.

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     We expect to be treated as a partnership for income tax purposes. As such, we will pay no tax at the company level and members will pay tax on their proportionate share of our net income. The income tax liability associated with a member’s share of net income could exceed any cash distribution the member receives from us. If a member does not receive cash distributions sufficient to pay his or her tax liability associated with his or her respective share of our income, he or she will be forced to pay his or her income tax liability associated with his or her respective units out of other personal funds.

     North Dakota Fuel Tax Incentive Program.We have received written assurance from the North Dakota Department of Commerce that our Plant will qualify for North Dakota’s fuel tax fund incentive program once ethanol production begins. Ethanol plants constructed after July 31, 2003 are eligible for incentives. Under the program, each fiscal quarter eligible ethanol plants may receive a production incentive based on the average North Dakota price per bushel of corn received by farmers during the quarter, as established by the North Dakota agricultural statistics service, and the average North Dakota rack price per gallon of ethanol during the quarter, as compiled by AXXIS Petroleum. Because we cannot predict the future prices of corn and ethanol, we cannot predict whether we will receive any funds in the future.

     Under the program, no facility may receive payments in excess of $10 million. If corn prices are low compared to historical averages and ethanol prices are high compared to historical averages, we will receive little or no funds from this program.

     The maximum annual credit a taxpayer may receive is $50,000 and no taxpayer may obtain more than $250,000 in credits over any combination of taxable years. In addition, a taxpayer may claim no more than 50% of the credit in a single year and the amount of the credit allowed for any taxable year may not exceed 50% of the tax liability, as otherwise determined. Credits may carry forward for up to five years after the taxable year in which the investment was made. If we don’t meet the requirements of a “qualified business,” unit holders will not be eligible for a tax credit.

Risks Related to the Units

     No public trading market exists for our units and we do not anticipate the creation of such a market, which means that it will be difficult for unit holders to liquidate their investment. There is currently no established public trading market for our units and an active trading market will not develop. To maintain partnership tax status, unit holders may not trade the units on an established securities market or readily trade the units on a secondary market (or the substantial equivalent thereof). We, therefore, will not apply for listing on any securities exchange or on the NASDAQ Stock Market. As a result, unit holders will not be able to readily sell their units.

     We have placed significant restrictions on transferability of the units, limiting a unit holder’s ability to withdraw from Red Trail.The units are subject to substantial transfer restrictions pursuant to our Member Control Agreement and tax and securities laws. This means that unit holders will not be able to easily liquidate their units and may have to assume the risks of investments in us for an indefinite period of time. Transfers will only be permitted in the following circumstances:

• Transfers by gift to the member’s descendants;

• Transfers upon the death of a member;

• Certain other transfers provided that for the applicable tax year, the transfers in the aggregate do not exceed 2% of the total outstanding units; and

• Transfers that comply with the “qualified matching service” requirements, if any is established.

     There is no assurance that a unit holder will receive cash distributions, which could result in a unit holder receiving little or no return on his or her investment.Distributions are payable at the sole discretion of our Board of Governors, subject to the provisions of the North Dakota Limited Liability Company Act, our Member Control Agreement and the requirements of our creditors. We do not know the amount of cash that we will generate

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in any given year. Cash distributions are not assured, and we may never be in a position to make distributions. Our Board may elect to retain future profits to provide operational financing for the Plant, debt retirement and possible Plant expansion or the construction of additional plants. This means that unit holders may receive little or no return on their investment and be unable to liquidate their investment due to transfer restrictions and lack of a public trading market.

     Our units were not valued based on any independent objective criteria, but rather by the amount of funding required to build our Plant.For our North Dakota intrastate offering and our initial seed capital round, we determined the offering price per unit to be $1.00. This determination was based solely on the capitalization requirements necessary to fund our construction and start-up activities. We did not rely upon any independent valuation, book value or other valuation criteria. Therefore, our outstanding units may be worth less than what they were sold for.

     Our governors and managers will not be liable for any breach of their fiduciary duty, except as provided under North Dakota law.Under North Dakota law, no governor or manager will be liable for any of Red Trail’s debts, obligations or liabilities merely because he or she is a governor or manager. In addition, our Operating Agreement contains an indemnification provision which requires us to indemnify any governor or manager to the extent required or permitted by North Dakota Century Code, Section 10-32-99, as amended from time to time, or as required or permitted by other provisions of law.

Risks Related to Ethanol Industry

     Overcapacity within the ethanol industry could cause an oversupply of ethanol and a decline in ethanol prices.Excess capacity in the ethanol industry would have an adverse impact on our results of operations, cash flows and general financial condition. Excess capacity may also result or intensify from increases in production capacity coupled with insufficient demand. If the demand for ethanol does not grow at the same pace as increases in supply, we would expect the price for ethanol to decline. If excess capacity in the ethanol industry occurs, the market price of ethanol may decline to a level that is inadequate to generate sufficient cash flow to cover our costs.

     We expect to operate in a competitive industry and compete with larger, better-financed entities, which could impact our ability to operate profitably.There is significant competition among ethanol producers with numerous producer and privately owned ethanol plants planned and operating throughout the United States. The number of ethanol plants being developed and constructed in the United States continues to increase at a rapid pace. The passage of the Energy Policy Act of 2005 included a renewable fuels mandate that we expect will further increase the number of domestic ethanol production facilities. The largest ethanol producers include Abengoa Bioenergy Corp., Archer Daniels Midland, Aventine Renewable Energy, Inc., Cargill, Inc., The Andersons, US Bio Energy and VeraSun Energy Corporation, all of which are each capable of producing more ethanol than we expect to produce. In 2005, Archer Daniels Midland announced its plan to add approximately 500 million gallons per year of additional ethanol production capacity in the United States. Archer Daniels Midland is currently the largest ethanol producer in the U.S. and controls a significant portion of the ethanol market. Archer Daniels Midland’s plan to produce an additional 500 million gallons of ethanol per year will strengthen its position in the ethanol industry and cause a significant increase in domestic ethanol supply. If the demand for ethanol does not grow at the same pace as increases in supply, we expect that lower prices for ethanol will result which may adversely affect our ability to generate profits and our financial condition.

     Competition from the advancement of alternative fuels may lessen the demand for ethanol. Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological option to address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets in order to decrease fuel costs, lessen dependence on crude oil and reduce harmful emissions. If the fuel cell and hydrogen industries continue to expand and gain broad acceptance, and hydrogen becomes readily available to consumers for motor vehicle use, we may not be able to

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compete effectively. This additional competition could reduce the demand for ethanol, resulting in lower ethanol prices that might adversely affect our results of operations and financial condition.

     Certain countries can export ethanol to the United States duty-free, which may undermine the ethanol production industry in the United States.Imported ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.51 per gallon ethanol subsidy available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. There is a special exemption from the tariff for ethanol imported from 24 countries in Central America and the Caribbean islands, which is limited to a total of 7.0% of United States production per year. In December 2006, legislation was passed by the U.S. House of Representatives and U.S. Senate to extend the $0.54 per gallon tariff beyond its current expiration in December 2007 through 2008. We do not know the extent to which the volume of imports would increase if the tariff is not renewed.

     In addition, the North America Free Trade Agreement countries, Canada and Mexico, are exempt from duty. Imports from the exempted countries have increased in recent years and are expected to increase further as a result of new plants under development. In particular, the ethanol industry has expressed concern with respect to a new plant under development by Cargill, Inc., the fifth largest ethanol producer in the United States, in El Salvador, that would take the water out of Brazilian ethanol and then ship the dehydrated ethanol from El Salvador to the United States duty-free. Brazil is currently the world’s second largest producer and largest exporter of ethanol. In Brazil, ethanol is produced primarily from sugarcane, which is also used to produce food-grade sugar. Since production costs for ethanol in Brazil are estimated to be significantly less than what they are in the United States, the import of the Brazilian ethanol duty-free through El Salvador or another country exempted from the tariff may negatively impact the demand for domestic ethanol and the price at which we sell our ethanol.

     Consumer resistance to the use of ethanol based on the belief that ethanol is expensive, adds to air pollution, harms engines and takes more energy to produce that it contributes may affect the demand for ethanol.Certain individuals believe that use of ethanol will have a negative impact on gasoline prices at the pump. Many also believe that ethanol adds to air pollution and harms car and truck engines. Still other consumers believe that the process of producing ethanol actually uses more fossil energy, such as oil and coal, than the amount of ethanol that is produced. These consumer beliefs could potentially be wide-spread. If consumers choose not to buy ethanol, it would affect the demand for the ethanol we produce which could lower demand for our product and negatively affect our profitability and financial condition.

     The expansion of domestic ethanol production in combination with state bans on MTBE and/or state renewable fuels standards may place strains on related infrastructure such that our ethanol cannot be marketed and shipped to blending terminals that would otherwise provide us the best cost advantages.If the volume of ethanol shipments continues to increase and blenders switch from MTBE to ethanol, there may be weaknesses in infrastructure such that our ethanol cannot reach its target markets. Substantial development of infrastructure by persons and entities outside our control will be required for our operations, and the ethanol industry generally, to grow. Areas requiring expansion include, but are not limited to:

• additional rail capacity to meet the expanding volume of ethanol shipments;

• additional storage facilities for ethanol;

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

• expansion of and/or improvements to refining and blending facilities to handle ethanol instead of MTBE; and

• growth in the fleet of flexible fuel vehicles capable of using E85 fuel.

     The expansion of the above infrastructure may not occur on a timely basis, if at all. Our operations could be adversely affected by infrastructure disruptions. In addition, lack of or delay in infrastructure expansion may result in an oversupply of ethanol on the market, which could depress ethanol prices and negatively impact our financial performance.

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Risks Related to Regulation and Governmental Action

     A change in government policies favorable to ethanol may cause demand for ethanol to decline. Growth and demand for ethanol may be driven primarily by federal and state government policies, such as state laws banning MTBE and the national renewable fuels standard. The continuation of these policies is uncertain, which means that demand for ethanol may decline if these policies change or are discontinued. A decline in the demand for ethanol is likely to cause lower ethanol prices, which in turn will negatively affect our results of operations, financial condition and cash flows.

     Loss of or ineligibility for favorable tax benefits for ethanol production could hinder our ability to operate at a profit and reduce the value of your investment in us.The ethanol industry and our business are assisted by various federal ethanol tax incentives, including those included in the Energy Policy Act of 2005. The provision of the Energy Policy Act of 2005 most likely to have the greatest impact on the ethanol industry is the creation of a 7.5 billion gallon Renewable Fuels Standard (“RFS”). The RFS began at 4 billion gallons in 2006, goes to 4.7 billion gallons in 2007 and increases to 7.5 billion gallons by 2012. The RFS helps support a market for ethanol that might disappear without this incentive. The elimination or reduction of tax incentives to the ethanol industry could reduce the market for ethanol, which could reduce prices and our revenues by making it more costly or difficult for us to produce and sell ethanol. If the federal tax incentives are eliminated or sharply curtailed, we believe that a decreased demand for ethanol will result, which could depress ethanol prices and negatively impact our financial performance.

     Another important provision involves an expansion in the definition of who qualifies as a small ethanol producer. Historically, small ethanol producers were allowed a 10-cents per gallon production income tax credit on up to 15 million gallons of production annually. The size of the plant eligible for the tax credit was limited to 30 million gallons. Under the Energy Policy Act of 2005 the size limitation on the production capacity for small ethanol producers increased from 30 million to 60 million gallons.

     Changes in environmental regulations or violations of the regulations could be expensive and reduce our profitability.We are subject to extensive air, water and other environmental laws and regulations. In addition some of these laws require our Plant to operate under a number of environmental permits. These laws, regulations and permits can often require expensive pollution control equipment or operation 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, damages, criminal sanctions, permit revocations and/or plant 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 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. Additionally, any changes in environmental laws and regulations, both at the federal and state level, could require us to invest or spend considerable resources in order to comply with future environmental regulations. The expense of compliance could be significant enough to reduce our profitability and negatively affect our financial condition.

ITEM 2. PROPERTIES.

     The Plant is located just east of the city limits of Richardton, North Dakota, and just north and east of the entrance/exit ramps to Highway I-94. The Plant complex is situated inside a footprint of approximately 25 acres of land which is part of an approximately 135 acre parcel which we acquired ownership of in 2004 and 2005. Included in the immediate campus area of the Plant are perimeter roads, buildings, tanks and equipment. An administrative building and parking area are located approximately 400 feet from the Plant complex and we utilize an additional acre of land within the approximately 135 acre parcel. We believe that our Plant complex and property will be sufficient for our operations in the foreseeable future.

ITEM 3. LEGAL PROCEEDINGS.

     From time to time in the ordinary course of business, we may be named as a defendant in legal proceedings related to various issues, including without limitation, workers’ compensation claims, tort claims, or contractual disputes. We are not currently involved in any material legal proceedings, directly or indirectly, and we are not

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aware of any claims pending or threatened against us or any of our governors that could result in the commencement of legal proceedings.

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

     We did not submit any matter to a vote of our unit holders through the solicitation of proxies or otherwise during the fourth quarter of 2006.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES.

Market Information

     There is no established trading market for our membership units.

     We may establish a Unit Trading Bulletin Board, a private online matching service, in order to facilitate trading among our members. The Unit Trading Bulletin Board would be designed to comply with federal tax laws and IRS regulations establishing a “qualified matching service,” as well as state and federal securities laws. Typically, a Unit Trading Bulletin Board consists of an electronic bulletin board that provides a list of interested buyers with a list of interested sellers, along with their non-firm price quotes. The Unit Trading Bulletin Board would not automatically affect matches between potential sellers and buyers and it would be the sole responsibility of sellers and buyers to contact each other to make a determination as to whether an agreement to transfer units may be reached. If we establish a Unit Trading Bulletin Board, we do not expect to become involved in any purchase or sale negotiations arising from our Unit Trading Bulletin Board or have any role in effecting the transactions beyond approval, as required under our Member Control Agreement, and the issuance of new certificates. We also do not expect to give advice regarding the merits or shortcomings of any particular transaction. We do not expect to receive, transfer or hold funds or securities as an incident of operating the Unit Trading Bulletin Board. We would not receive any compensation for creating or maintaining the Unit Trading Bulletin Board. If a qualified matching service were established, we would not characterize Red Trail as being a broker or dealer or an exchange. We would not use the Unit Trading Bulletin Board to offer to buy or sell securities other than in compliance with the securities laws, including any applicable registration requirements.

     In the event a Unit Trading Bulletin Board were established, significant rules and procedures may apply with respect to offers and sales of membership units. All transactions would be required to comply with any Unit Trading Bulletin Board Rules that may or may not be established and our Member Control Agreement, and would be subject to approval by our Board of Governors.

Unit Holders

     As of year ended December 31, 2006, Red Trail had 40,373,973 Class A Membership Units issued and outstanding and a total of 800 membership unit holders. There is no other class of membership unit issued or outstanding.

Distributions

     Red Trail did not make any distributions to its members for fiscal years ended December 31, 2006, 2005 or 2004. Distributions are payable at the discretion of our Board of Governors, subject to the provisions of the North Dakota Limited Liability Company Act and our Member Control Agreement. Distributions to our unit holders are also subject to certain loan covenants and restrictions that require us to make additional loan payments based on excess cash flow. These loan covenants and restrictions are described in greater detail under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness.” Red Trail may distribute a portion of the net profits generated from Plant operations to it owners. A unit holder’s distribution is determined by dividing the number of units owned by such unit holder by the total number of units outstanding. Our

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unit holders are entitled to receive distributions of cash or property if and when a distribution is declared by our Board of Governors. Subject to the North Dakota Limited Liability Company Act, our Member Control Agreement and the requirements of our creditors, our Board of Governors has complete discretion over the timing and amount of distributions, if any, to our unit holders. There can be no assurance as to the ability of Red Trail to declare or pay distributions in the future.

ITEM 6. SELECTED FINANCIAL DATA.

     The following tables set forth selected consolidated financial data of Red Trail Energy, LLC for the periods indicated. The audited financial statements included in Item 8 of this Annual Report have been audited by our independent auditors, Boulay, Heutmaker, Zibel & Co., P.L.L.P.

										From Inception
										July 16, 2003 to
Statement of										December 31,
Operations Data	2006			2005			2004			2006 (Unaudited)
Revenues	$	—		$	—		$	—		$	—
Operating Expenses		3,747,730			2,087,808			433,345			6,689,020
Operating Loss		(3,747,730	)		(2,087,808	)		(433,345	)		(6,689,020	)
Operating Income		1,243,667			360,204			147,004			1,750,875
Net Income (Loss )	$	(2,504,063	)	$	(1,727,604	)	$	(286,341	)	$	(4,938,145	)
Weighted Average Units Outstanding		39,625,843			24,393,980			3,591,180			13,920,740
Net Income (Loss) Per Unit	$	(0.06	)	$	(0.07	)	$	(0.08	)	$	(0.35	)

Balance Sheet Data	2006		2005
Cash & Equivalents	$	421,722	$	19,043,811
Total Current Assets		4,761,974		19,069,156
Total Property & Equipment		84,039,740		16,948,185
Total Assets	$	89,864,288	$	36,972,579
Total Current Liabilities		9,781,240		8,258,885
Other Liabilities		275,000		—
Long Term Debt		46,878,960		—
Members’ Equity		32,929,088		28,713,694
Book Value Per Weighted Average Unit	$	.83	$	1.18

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

     Except for the historical information, the following discussion contains forward-looking statements that are subject to risks and uncertainties. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the risks described in “Item 1A — Risk Factors” and elsewhere in this Annual Report. Our discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and related notes and with the understanding that our actual future results may be materially different from what we currently expect.

Overview

     We were organized to build a 50 million gallon annual production ethanol plant near Richardton, North Dakota. Construction began in 2005 and was completed in December 2006.

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     Since January 2007, our revenues have been derived from the sale and distribution of our ethanol and distillers grains throughout the continental United States. Corn is supplied to us from shuttle loaders, elevators and farmers, as negotiated by our Commodities Manager, although we have a contract with New Vision Coop in case we need them to provide corn if we cannot obtain it ourselves. After processing the corn, our ethanol is sold through RPMG, which subsequently markets and sells the ethanol to gasoline blenders and refiners located throughout the continental United States. The price that we receive from the sale of ethanol to RPMG is based upon the price that RPMG receives from the sale to its customers, minus a marketing fee. Except for Distillers Modified Wet Grains that we sell ourselves, our Distillers Dried Grains with Solubles (“DDGS”) that we produce are sold through Commodity Specialist Company (“CSC”), which markets and sells the product to livestock feeders. For our DDGS, we receive a percentage of the selling price actually received by CSC in marketing the DDGS to its customers.

     We are subject to industry-wide factors that affect our operating income and cost of production. Our operating results are largely driven by the prices at which we sell ethanol and distillers grains and the costs related to their production. Historically, the price of ethanol tends to fluctuate in the same direction as the price of unleaded gasoline and other petroleum products. Surplus ethanol supplies also tend to put downward price pressure on ethanol. In addition, factors such as general economic conditions, the weather, and government policies and programs generally influence the price of ethanol. The price of distillers grains is generally influenced by supply and demand, the price of substitute livestock feed, such as corn and soybean meal, and other animal feed proteins. Surplus grains also tend to put downward price pressure on distillers grains. In addition, our revenues are also impacted by such factors as our dependence on one or a few major customers who market and distribute our products, the intensely competitive nature of our industry, possible legislation at the federal, state, and/or local level, and changes in federal ethanol tax incentives.

     Our two largest costs of production are corn and coal. The cost of corn is primarily by supply and demand factors such as crop production, carryout, exports, government policies and programs, risk management and weather, much of which we have no control over. Coal prices fluctuate with the energy complex in general. Recently, the price of coal has risen along with other energy sources. Coal prices are considerably higher than the 10-year average, due to increased economic and industrial activity in the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. We have a ten (10) year contract with General Industries, Inc., d/b/a Center Coal Company to circumvent this volatility. Any ongoing increases in the price of coal will increase our cost of production and may negatively impact our future profit margins. Our costs of production are affected by the cost of complying with the extensive environmental laws that regulate our industry.

Results of Operations

     From January 1, 2006 to December 31, 2006, we were a development stage company with no revenues or costs of sales. We commenced operations in January 2007 and are engaged in the production and sale of fuel grade ethanol. We expect to be able to process approximately eighteen million bushels of corn into approximately fifty million gallons of ethanol. In addition, we intend to sell distillers grains, a principal co-product of the ethanol production process, which we will sell as distillers modified wet grains and distillers dried grains with solubles.

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     Comparison of Fiscal Years Ended December 31, 2006, 2005 and 2004

     The following table shows the results of our operations and the percentages of sales and revenues, cost of sales, operating expenses and other items to total sales and revenues in our statements of operations for the years ended December 31, 2006, 2005 and 2004:

	Fiscal Year Ended				Fiscal Year Ended				Fiscal Year Ended
	December 31, 2006				December 31, 2005				December 31, 2004
	Amount			%	Amount			%	Amount			%
Revenues	$	—			$	—			$	—
Costs of Sales		—				—				—
Gross Margin		—				—				—
Operating Expenses		3,747,730				2,087,808				433,345
Operating Loss		(3,747,730	)			(2,087,808	)			(433,345	)
Grant Income		—				50,000				100,000
Unrealized loss on corn derivatives		851,290				(277,592	)			—
Gain from non-designated hedging derivatives		210,100				—				—
Interest Income		182,277				588,156				47,004
Net Loss	$	(2,504,063	)		$	(1,727,604	)		$	(286,341	)

     Revenues

     We had no sales or revenues for the fiscal years ended December 31, 2006, 2005 or 2004.

     Due to a number of factors, including the higher price of petroleum gasoline and seasonal demand, ethanol prices remained high during fiscal year 2006. We believe the favorable prices are primarily due to high demand for ethanol, created by a number of factors, including the declining use of MTBE as an oxygenate, the high price of gasoline, which encourages voluntary blending, and the growing recognition of ethanol as an alternative energy source. However, ethanol prices began to trend lower during September 2006 and the fourth calendar quarter of 2006 due to a number of factors, including the lower price of petroleum gasoline and a drop in seasonal demand. We believe this trend will continue into 2007 until peak driving season begins in the summer. While ethanol prices were lower late in the fourth quarter of 2006, they are still higher than the historical average. However, we cannot guarantee that the price of ethanol will not significantly decrease due to factors beyond our control.

     With respect to distillers grains, we believe that prices will remain at or near their currently low and stable levels due to the increasing number of ethanol production facilities commencing operations. In 2007, we expect revenues from the sale of distiller grains should increase relative to 2006 due to our commencing operations.

     Cost of Goods Sold

     We had no costs of sales for the fiscal years ending December 31, 2006, 2005 and 2004.

     Corn costs will significantly impact our cost of goods sold. As of March 31, 2007, Untied States Department of Agriculture’s National Agricultural Statistics Service projected the 2007 national corn acreage at approximately 90.5 million acres, which would be the second largest corn acreage on record. North Dakota 2006 production was 155,400,000 bushels. However, despite the projected 2007 corn crop, corn prices have increased sharply since August 2006. Additionally, due to increased exposure of ethanol, corn is now viewed as an “energy commodity” as opposed to strictly a “grain commodity,” contributing to the upward pressure on corn prices. A recent USDA report entitled “World Agricultural Supply and Demand Estimates” (February 9, 2007) states that U.S. corn prices could increase in year 2007 to as much as $3.40 per bushel or more. Our average cost per bushel of corn

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for the year ended December 31, 2006 was $3.23. We expect corn prices to remain at historically high price levels well into 2007, which could significantly impact our cost of goods sold.

     Recently, the price of coal has risen along with other energy sources. Coal prices are considerably higher than the 10-year average, due to increased economic and industrial activity in the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. We have a ten (10) year contract with General Industries, Inc., d/b/a Center Coal Company to deliver lignite coal designed to circumvent this large volatility. However, since operations began on January 1, 2007, we have had issues with the use of lignite in our coal combustor. We are exploring other options, including using powder river basin (“PRB”) coal as an alternative. If we are unable to continue using lignite and have to use PRB coal instead, we would expect our coal cost to increase significantly and we may be subject to market volatility if we cannot obtain a long-term coal contract, if needed. Any ongoing increases in the price of coal will increase our cost of goods sold and may cause our net income to decrease.

     We recognize that any gains or losses that result from the changes in value of our derivative instruments in cost of goods sold as the changes occur. As corn fluctuates, the value of our derivative instruments are impacted, which affects our financial performance. We anticipate continued volatility in our cost of goods sold due to the timing of the changes in value of the derivative instruments relative to the cost and use of the commodity being hedged.

     Operating Expenses

     Our operating expenses were approximately $3,748,000, $2,088,000 and $433,000 for the fiscal years ended December 31, 2006, 2005 and 2004, respectively. For the year ending 2006, our operating expenses increased by approximately $1,660,000 or 79.51%. These increases are primarily due to costs associated with management and administrative expenses during the construction of our Plant, professional and consulting fees and commencement of Plant Operations. For the year ended 2006, our material operating expenses were: 1) approximately $249,000 related to legal fees; 2) approximately $165,000 related to management fees; 3) approximately $649,000 related to salaries and payroll expenses; 4) approximately $1,555,000 related to professional services; 5) approximately $239,000 for start up Plant supplies; and 6) approximately $891,000 related to other start up costs.

     Our operating expenses increased by approximately $1,655,000 or 382% for 2005 over 2004 and increased by approximately $13,000 or 3% for 2004 over 2003. These increases for both 2005 versus 2004 and 2004 versus 2003 were due primarily to costs associated with starting construction on our Plant, professional and consulting fees, including the 2005 payment due to GreenWay in excess of $1,500,000 under our consulting agreement related to their work through Phase I, and other general operating expenses. In 2005, our material operating expenses were: 1) approximately $1,500,000 related to consulting fees paid to GreenWay; 2) approximately $177,000 related to salaries; 3) approximately $84,000 related to marketing expenses; and 4) approximately $77,000 related to office and insurance expenses. In 2004, our material operating expenses were: 1) approximately $105,000 in payments to our coordinator; 2) approximately $90,000 related to accounting expenses; 3) approximately $182,000 related to professional services; 4) approximately $46,000 related to marketing expenses; and 5) approximately $33,000 in consulting fees.

     We believe that our operating expenses will increase significantly in 2007 as a result of the commencement of operation in January 2007, resulting primarily in higher salaries and payroll expenses.

     Operating Income

     Because we had no revenues prior to 2007, our operating loss in fiscal years 2006, 2005 and 2004 is the same as our operating expenses..

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     Other Income and Expense

     Our interest costs for the fiscal years ended December 31, 2006, 2005 and 2004 were approximately $1,527,000, $0 and $0, respectively. However, the interest cost in fiscal year 2006 was capitalized and included in construction in progress. There were no interest expenses for fiscal years ending December 31, 2005 and 2004.

     Interest income, resulting primarily from the investment of cash received from our member unit sales since inception prior to its use in the construction of our Plant was approximately $182,000, $588,000 and $47,000 for the fiscal years ended December 31, 2006, 2005 and 2004, respectively. Interest income increased in 2005 due to interest earned on the equity raised from member investments and then decreased in 2006 as those funds were disbursed for Plant construction and pre-production operating costs. We do not expect to receive any significant interest income in 2007.

     Gains (losses) from non-designated hedging derivatives are derived from investments in corn call options and an interest rate swap contract in an agreement associated with bank financing to effectively fix the interest rate on approximately $27,600,000 of our future debt at an interest rate of 8.08%. For the fiscal years ending December 31, 2006, 2005 and 2004, there were no settlements, and market value adjustments resulted in gains (losses) from non-designated hedging derivatives on the interest rate swap contract of approximately $167,000, $(278,000) and $0, respectively. For the fiscal years ending December 31, 2006, 2005 and 2004, there were no net settlements, and market value adjustments resulted in a gain from non-designated hedging derivatives of corn call options of approximately $894,000, $0 and $0. We may recognize significant gains or losses in the near future in connection with our interest rate swap contract and corn call options, as well as with any ethanol contracts into which we may enter.

     Grant income was approximately $0, $50,000 and $100,000 for the fiscal years ended December 31, 2006, 2005 and 2004, respectively. Grant income relates to the grant we were awarded from Ag Products Utilization Council in the amount of $150,000.

Plant Operations

     Operations of Ethanol Plant

     Construction of the Plant was substantially completed and preliminary production operations commenced in December 2006. Production activities were minimal during 2006, and the Company exited its development stage in January 2007 when it began generating substantial revenues from ethanol production. While early production in 2007 has been at less than capacity levels as we work out early production difficulties, management anticipates that the Plant will be operating at or above name-plate capacity of 50 MMGY for the majority of the next twelve (12) months.

     We expect to have sufficient cash from cash flow generated by continuing operations, current lines of credit through our revolving promissory note, and cash reserves to cover our usual operating costs over the next twelve (12) months, which consist primarily of corn supply, coal supply, water supply, staffing, office, audit, legal, compliance, working capital costs and debt service obligations.

Critical Accounting Estimates

     Management uses estimates and assumptions in preparing our consolidated financial statements in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Of the significant accounting policies described in the notes to our consolidated financial statements, we believe that the following are the most critical:

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     Derivative Instruments

     We account for derivative instruments and hedging activities in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires a company to evaluate its contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from accounting and reporting requirements of SFAS No. 133.

     In order to reduce the risk caused by market fluctuations of corn, ethanol and interest rates, we enter into option, futures and swap contracts. These contracts are used to fix the purchase price of our anticipated requirements of corn in production activities and the selling price of our ethanol product and limit the effect of increases in interest rates. The fair value of these contracts is based on quoted prices in active exchange-traded or over-the-counter markets. The fair value of the derivatives is continually subject to change due to the changing market conditions. We do not typically enter into derivative instruments other than for hedging purposes. On the date the derivative instrument is entered into, we will designate the derivative as a hedge. Changes in the fair value of a derivative instrument that is designated and meets all of the required criteria for, a cash flow or fair value hedge, is recorded in accumulated other comprehensive income and reclassified into earnings as the hedged items affect earnings. Changes in fair value of a derivative instrument that is not designated and accounted for, as a cash flow or fair value hedge, is recorded in current period earnings. Although certain derivative instruments may not be designated and accounted for, as a cash flow or fair value hedge, they are effective economic hedges of specific risks.

     Inventory

     Inventory consists of raw materials, work in process, and finished goods. The work in process inventory is based on certain assumptions. The assumptions used in calculating work in process are the quantities in the fermenter and beer well tanks, the spot price of corn at the end of the month, the effective yield, and the amount of dried distillers grains assumed to be in the tanks. These assumptions could change in the near term.

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Liquidity and Capital Resources

     Comparison of Fiscal Years ended December 31, 2006 and 2005

     As of December 31, 2006, we had total assets of approximately $89,864,000 consisting primarily of derivative instruments, financing costs and construction in progress. As of December 31, 2006, we had current liabilities of approximately $9,781,000 consisting primarily of accounts payable related to the construction of the Plant. For the fiscal year ended December 31, 2006, cash used in operating activities was approximately $7,662,300, cash used in investing activities, primarily for Plant construction, was approximately $66,904,000 and cash provided by financing activities, primarily bank debt, was approximately $55,945,000. Likewise for 2005 and 2004, our cash outflows for operating purposes, $58,000 and $289,000, respectively, were to fund our preproduction operating costs, our outflows for investing purposes, $10,599,000 and $314,000, respectively, were primarily to construct our Plant and administrative office facilities, and our cash in(out)flows from financing activities, $13,812,000 and $15,642,000, respectively, were primarily the result of member equity contribution and bank financing activities. Since our inception, we have generated no revenue from operations. From our inception to December 31, 2006, we have accumulated a net loss of approximately $4,938,000 consisting primarily of start-up business costs.

     As of December 31, 2006, we had material commitments related to our construction agreement with Fagen, Inc. (“Fagen”), the designer and builder of our Plant, in the amount of approximately $77,000,000 and remaining material commitments related to our consulting agreement with GreenWay in the amount of approximately $1,525,000, which is included in our accrued liabilities at the end of 2006. As of December 31, 2006, we paid approximately $70,030,000 to Fagen from the proceeds from our equity financings and have remaining commitments to Fagen of approximately $6,970,000. Based on the revenues we are currently receiving from sales of our ethanol and co-products, as well as our cash on hand as of the date hereof, including the loan proceeds available to us as described above, we believe that we will have adequate cash reserves and available lines of credit after payment of the remaining amounts to GreenWay and Fagen so that we can fund our operations and service our debt obligations and operating costs.

     As of December 31, 2006, we have used all funds remaining from our equity financings. Current and remaining operating expenses, including all remaining construction costs will be paid for with the proceeds from our loan agreements. We anticipate that we have sufficient funds available, at December 31, 2006, from our loan agreements to meet our working capital requirements for the next twelve (12) months.

										From
										Inception July
	Year Ended			Year Ended			Year Ended			16, 2003 to
	December 31,			December 31,			December 31,			December 31,
	2006			2005			2004			2006
Statement of Cash Flow	(Audited)			(Audited)			(Audited)			(Audited)
Cash Flows from Operating Activities		(7,662,308	)		(57,980	)		(288,913	)		(8,215,209	)
Cash Flows from Investing Activities		(66,903,860	)		(10,558,969	)		(313,821	)		(77,979,890	)
Cash Flows from Financing Activities		55,944,079			13,811,977			15,642,024			86,616,821

     Cash Flow From Operations

     The net cash flow expended for operating activities in 2006 increased $7,604,000 over that for 2005,and in 2005 decreased $231,000 from that in 2004. The increased expenditures during 2006 were primarily due to the start up expenses in 2006. The decrease of cash expenditures during 2005 from those in 2004 was due to the timing of payments related to preproduction expenditures during both years. While our 2005 net loss of $1,728,000 was significantly higher than the $286,000 loss in 2004, a significant amount of the 2005 operating expenses were paid in 2006.

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     Cash Flow From Investing Activities

     We used cash provided by the debt financing and member contribution activities for capital expenditures, primarily Plant and administrative facilities and equipment, which totaled $66,904,000 for fiscal year 2006 compared to $10,559,000 for fiscal year 2005 and $313,000 for fiscal year 2004.

     Management estimates that approximately $3,600,000 in capital expenditures will be made in the next twelve (12) months for general improvements to the Plant, all of which are expected to be financed from a portion of cash flows from operations and additional debt financing.

     Cash Flow From Financing Activities

     Since our inception, we have generated significant cash inflows from bank financing arrangements and member equity contributions. Proceeds from our bank financing arrangements totaling $49,800,000 substantially all of which was generated in 2006, were received once the cash from our member equity contributions was completely expended. Cash in(out)flows from our member equity contribution activities were approximately $6,719,000, $14,285,830, and $15,745,986 during 2006, 2005 and 2004, respectively. The 2004 outflows were costs paid in advance of receiving the contribution proceeds.

Indebtedness

     Short-Term Debt Sources

     We have a revolving promissory note of up to $3,500,000 with First National Bank of Omaha, subject to certain borrowing base limitations, through July 2007. Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over LIBOR, which totaled 8.71% at December 31, 2006. We have no outstanding borrowings on the revolving promissory note as of December 31, 2006 and 2005.

     Long-Term Debt Sources

     In December 2005, we entered into a construction loan agreement with our bank providing for a total credit facility of approximately $59,712,000 for the purpose of funding the construction of the Plant. The construction loan agreement requires us to maintain certain financial ratios and meet certain non-financial covenants. The loan agreement is secured by substantially all of our assets and includes the terms as described below.

     The construction loan agreement provides for a construction loan for up to an amount of approximately $55,212,000 with a loan termination date of April 16, 2007. Interest is to be charged at a rate of 3.4% over LIBOR, which totaled 8.71% at December 31, 2006. The agreement calls for interest only payments to be made every three (3) months beginning March 2006 through the loan termination date.

     At the loan termination date, all principal and unpaid interest will be paid out through three term notes, each with specific interest rates and payments terms as described in the construction loan agreement.

     The first of the three notes is a Fixed Rate Note in the amount of approximately $27,606,000 with interest payments made on a quarterly basis and charged at fixed rate of 3.0% over LIBOR on the date of the construction loan termination date. Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $470,000 and increasing to $653,000 per quarter, from April 2007 to October 2011, with a final principal payment of approximately $17,000,000 at January 2012.

     The second term note is referred to as the Variable Rate Note and is in the amount of approximately $17,606,000. Interest will be charged at a variable rate of 3.4% over the three-month LIBOR rate.

     The third term note, the Long-Term Revolving Note, in the amount of approximately $10,000,000, will be charged interest at a variable rate of 3.4% over the one-month LIBOR rate. The agreement calls for payments of approximately $1,005,000 to be made each quarter with amounts allocated to the term notes in the following

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manner: 1) to accrued interest on the Long-Term Revolving Note, 2) to accrued interest on the Variable Rate Note, and 3) to the principal balance on the Variable Rate Note.

     All unpaid amounts on the three term notes are due and payable in April 2012. The outstanding borrowings on the construction loan at December 31, 2006 is $44,060,352.

     We are subject to a number of covenants and restrictions in connection with this loan, including:

• Providing the bank with current and accurate financial statements;

• Maintaining certain financial ratios, minimum net worth, and working capital;

• Maintaining adequate insurance;

• Make, or allow to be made, any significant change in our business or tax structure; and

• Limiting our ability to make distributions to members.

     The construction loan agreement also contains a number of events of default which, if any of them were to occur, would give the bank certain rights, including but not limited to:

• declaring all the debt owed to the bank immediately due and payable; and

• taking possession of all of our assets, including any contract rights.

     The bank could then sell all of our assets or business and apply any proceeds to repay their loans. We would continue to be liable to repay any loan amounts still outstanding.

     Interest Rate Swap Agreement

     The construction loan agreement provides for us to enter into interest rate swap contracts for up to approximately $2,800,000. In December 2005, we entered into an interest rate swap transaction that effectively fixes the interest rate at 8.08% on approximately $27.6 million of the outstanding principal of the construction loan. The interest rate swap was not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements are recorded as a gain or loss from non-designated hedging activities. For the fiscal years ending December 31, 2006, 2005, and 2004, there were no net settlements, and market value adjustments resulting in a gain of approximately of $851,300 in 2006, a loss of approximately $278,000 in 2005 and no gain or loss in 2004.

     Letters of Credit

     The construction loan agreement provides for up to $1,000,000 in letters of credit with the bank to be used for any future line of credit requested by a supplier to the Plant. All letters of credit are due and payable at the loan termination date in April 2007. The construction loan agreement provides for us to pay a quarterly commitment fee of 2.25% of all outstanding letters of credit. In addition, as of December 31, 2006, we have one outstanding letter of credit for $137,000 for capital expenditures for gas services with Montana-Dakota Utilities Co.

     Subordinated Debt

     As part of the construction loan agreement, we entered into three separate subordinated debt agreements totaling approximately $5,525,000 and received funds from these debt agreements during 2006. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate (a total of 10.75% at December 31, 2006) and is due and payable subject to approval by the Senior Lender, the bank. Interest is compounding with any unpaid interest converted to principal. Amounts will be due and payable in full in April 2012. As of December 31, 2006, the outstanding amounts on these loans was $5,525,000.

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     Contractual Obligations and Commercial Commitments

     We have the following contractual obligations as of December 31, 2006:

Contractual			Less than						More than
Obligations	Total		1 Year		1-3 Years		3-5 Years		5 Years
Long Term Debt Obligations	$	89,980,759	$	6,360,699	$	23,858,980	$	59,761,080		—
Capital Leases	$	236,667	$	61,701	$	173,050	$	1,916		—
Operating Lease Obligations	$	148,500	$	27,000	$	81,000	$	40,500		—
Purchase Obligations – Fagen(1)	$	77,000,000	$	70,029,516		—		—		—
Coal	$	28,728,000	$	2,394,000	$	7,182,000	$	7,182,000	$	11,970,000
Water	$	6,625,100	$	662,600	$	1,987,500	$	1,987,500	$	1,987,500

(1) Related to our contracts with Fagen, capital leases, operating leases, purchase commitments for coal and water and our debt obligations. As of December 31, 2006, we have already paid approximately $70,029,516 to Fagen.

Grants

     We have been awarded a grant from Ag Products Utilization Council in the amount of $150,000, which was used in 2005 and 2004 for general business expenses, including legal and accounting. We also received a grant from the North Dakota Lignite Council in the amount of $350,000. This grant requires a portion of the proceeds to be repaid over a period of 10 years at $22,000 per year and the remainder to be forgiven upon the fulfillment of certain conditions.

     We have entered into an agreement with Job Service North Dakota for a new jobs training program. This program provides incentives to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training. Red Trail will receive up to approximately $170,000 over ten years. We did not receive any funds in the fiscal year ended December 31, 2006.

     In additional to the Job Services North Dakota training program, the Company entered into a contract on October 2, 2006 with Job Service North Dakota for the Workforce 20/20 program. The program assists North Dakota employers in training and upgrading workers’ skills. Under this program, the Company could be eligible to receive up to approximately $28,000 in the fiscal year 2007.

Fuel Tax Incentive Program

     We have received written assurance from the North Dakota Department of Commerce that our Plant will qualify for North Dakota’s fuel tax fund incentive program. Ethanol plants constructed after July 31, 2003 are eligible for incentives. Under the program, each fiscal quarter eligible ethanol plants may receive a production incentive based on the average North Dakota price per bushel of corn received by farmers during the quarter, as established by the North Dakota agricultural statistics service, and the average North Dakota rack price per gallon of ethanol during the quarter, as compiled by AXXIS Petroleum. Because we cannot predict the future prices of corn and ethanol, we cannot predict whether we will receive any funds in the future. The incentive received is calculated by using the sum arrived at for the corn price average and for the ethanol price average as calculated in number 1 and number 2 below:

35

1.	Corn Price:
a.	For every cent that the average quarterly price per bushel of corn exceeds $1.80, the state shall add to the amounts payable under the program $.001 multiplied by the number of gallons of ethanol produced by the facility during the quarter.
b.	If the average quarterly price per bushel of corn is exactly $1.80, the state shall not add anything to the amount payable under the program.
c.	For every cent that the average quarterly price per bushel of corn is below $1.80, the state shall subtract from the amounts payable under the program $.001 multiplied by the number of gallons of ethanol produced by the facility during the quarter.
2.	Ethanol Price:
a.	For every cent that the average quarterly rack price per gallon of ethanol is above $1.30, the state shall subtract from the amounts payable under the program $.002 multiplied by the number of gallons of ethanol produced by the facility during the quarter.
b.	If the average quarterly price per gallon of ethanol is exactly $1.30, the state shall not add anything to the amount payable under the program.
c.	For every cent that the average quarterly rack price per gallon of ethanol is below $1.30, the state shall add to the amounts payable under the program $.002 multiplied by the number of gallons of ethanol produced by the facility during the quarter.

          Under the program, no facility may receive payments in excess of $10 million. If corn prices are low compared to historical averages and ethanol prices are high compared to historical averages, we will receive little or no funds from this program.

Tax Credit for Investors

          In addition, we believe our investors are eligible for a tax credit against North Dakota state income tax liability. On May 3, 2004, we were approved for the North Dakota Seed Capital Investment Tax Credit. In 2005, North Dakota revised its tax incentive programs and adopted the Agricultural Commodity Processing Facility Investment Tax Credit. We were grandfathered into the new program and do not need to meet the new conditions to qualify for the tax credit. The amount of credit for which a taxpayer may be eligible is 30% of the amount invested by the taxpayer in a qualified business during the taxable year.

          The maximum annual credit a taxpayer may receive is $50,000 and no taxpayer may obtain more than $250,000 in credits over any combination of taxable years. In addition, a taxpayer may claim no more than 50% of the credit in a single year and the amount of the credit allowed for any taxable year may not exceed 50% of the tax liability, as otherwise determined. Credits may carry forward for up to five years after the taxable year in which the investment was made.

Off-Balance Sheet Arrangements

          We do not have any off-balance sheet arrangements.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

          We are exposed to the impact of market fluctuations associated with interest rates and commodity prices as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in U.S. Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. We use cash, futures and option contracts to hedge changes to the commodity prices of corn We do not enter into these derivative

36

financial instruments for trading or speculative purposes, nor do we designate these contracts as hedges for accounting purposes pursuant to the requirements of SFAS 133,Accounting for Derivative Instruments and Hedging Activities.

Interest Rate Risk

     We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding a revolving promissory note and construction term notes which bear variable interest rates. Specifically, all outstanding long-term debt is at a variable rate as of December 31, 2006

     In order to achieve a fixed interest rate on the construction loan and reduce our risk to fluctuating interest rates, we entered into an interest rate swap contracts that effectively fix the interest rate at 8.08% on approximately $27.6 million of the outstanding principal of the construction loan. The interest rate swap was not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements are recorded as a gain or loss from non-designated hedging activities. For the fiscal years ending December 31, 2006 and 2005, there were no net settlements, and market value adjustments resulting in a loss of approximately of $167,000 and a loss of approximately $278,000, respectively.

Commodity Price Risk

     We also expect to be exposed to market risk from changes in commodity prices. Exposure to commodity price risk results from our dependence on corn in the ethanol production process and the sale of ethanol. We will seek to minimize the risks from fluctuations in the prices of corn through the use of hedging instruments. In practice, as markets move, we will actively manage our risk and adjust hedging strategies as appropriate. Although we believe our hedge positions will accomplish an economic hedge against our future purchases, they likely will not qualify for hedge accounting, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged. We intend to use fair value accounting for our hedge positions, which means as the current market price of our hedge positions changes, the gains and losses are immediately recognized in our cost of sales. For example, we would generally expect that a 10% increase in the cash price of corn would produce a $100,000 increase in the fair value of our derivative instruments. Whereas a 10% decrease in the cash price of corn would likely produce a $100,000 decrease in the fair value of our derivatives.

     The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged. As of December 31, 2006, we had a $320,341 investment in derivative instruments for corn and no derivative instruments for ethanol. There are several variables that could affect the extent to which our derivative instruments are impacted by price fluctuations in the cost of corn or ethanol. However, it is likely that commodity cash prices will have the greatest impact on the derivatives instruments with delivery dates nearest the current cash price.

     To manage our corn price risk, our hedging strategy will be designed to establish a price ceiling for our corn purchases. We intend to take a net long position on our exchange traded futures and options contracts, which should allow us to offset increases or decreases in the market price of corn. The upper limit of loss on our futures contracts will be the difference between the futures price and the cash market price of corn at the time of the execution of the contract. The upper limit of loss on our exchange traded and over-the-counter option contracts will be limited to the amount of the premium we paid for the option.

     We estimate that our expected corn usage will be approximately 18 million bushels per year for the production of 50 million gallons of ethanol. As of December 31, 2006, we have option contract price protection for our expected corn usage through the first forty days of operation. We intend to continue to contract for price protection for our corn usage. As corn prices move in reaction to market trends and information, our income statements will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects but are expected to produce long-term positive growth.

37

     We intend to manage our ethanol price risk by setting a hedging strategy designed to establish a price floor for our ethanol sales. At present, the price of ethanol has increased. In the future, we may not be able to sell ethanol at a favorable price relative to gasoline prices, we also may not be able to sell ethanol at prices equal to or more than our current price. This would limit our ability to offset our costs of production.

     To manage our ethanol price risk, RPMG will have a percentage of our future production gallons contracted through fixed price contracts, ethanol rack hedges and gas plus hedges. We communicate closely with RPMG to ensure that they are not over marketing our ethanol volume. As ethanol prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on energy market movements, crop prospects and weather, any price protection positions may cause short-term adverse effects but are expected to produce long-term positive growth.

     To manage our coal price risk, we entered into a coal purchase agreement with our supplier to supply us with coal, fixing the price at which we purchase coal. If we are unable to continue buying coal under this agreement, we may have to buy coal in the market. The price of coal has risen substantially over the last several months and our strategy is to purchase coal based on our operating assumptions of the Plant.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

     Our financial statements and supplementary data are included on pages F-1 to F-16 of this Report.

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

     Boulay, Heutmaker, Zibel & Co., P.L.L.P. has been our independent auditor since 2005 and is the Company’s independent auditor at the present time. The Company has had no disagreements with its auditors.

ITEM 9A. CONTROLS AND PROCEDURES.

     Our management, including our President and General Manager (the principal executive officer), Mick J. Miller, along with our Chief Financial Officer (the principal financial officer), Bonnie G. Eckelberg, have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchanges Act of 1934, as amended) as of December 31, 2006. Based upon this review and evaluation, these officers have concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed in the reports that we file or submit under the Exchanges Act is recorded, processed, summarized and reported within the time periods required by the forms and rules of the Securities and Exchanges Commission, and are also effective to ensure that the information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to our management including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

     Our management, including our principal executive officer and principal financial officer, have reviewed and evaluated any changes in our internal control over financial reporting that occurred as of December 31, 2006 and there has been no change that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

     We recently became aware that the forms of Operating Agreement and Member Control Agreement filed with our Form 10-12G (000-52033) were not the most current versions in effect. We are filing the current version with this Report as Exhibits 3.2 (Operating Agreement) and 4.2 (Member Control Agreement).

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PART III

     Pursuant to General Instruction G (3), we omit Part III, Items 10, 11, 12, 13, and 14 and incorporate such items by reference to an amendment to this Annual Report on Form 10-K or to a definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year covered by this Annual Report (December 31, 2006).

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

     The following exhibits and financial statements are file as part of, or are incorporated by reference into, this report:

     (1) Financial Statements

     An index to the financial statements included in this Report appears at page F-1. The financial statements appear beginning at page F-3 of this Report.

     (2) Financial Statement Schedules

     All supplemental schedules are omitted as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes.

     (3) Exhibits

3.1	Articles of Organization, as filed with the North Dakota Secretary of State on July 16, 2003. Filed as Exhibit 3.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
3.2	Operating Agreement of Red Trail Energy, LLC. Filed herewith.
4.1	Membership Unit Certificate Specimen. Filed as Exhibit 4.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
4.2	Member Control Agreement of Red Trail Energy, LLC. Filed herewith.
10.1	The Burlington Northern and Santa Fe Railway Company Lease of Land for Construction/ Rehabilitation of Track made as of May 12, 2003 by and between The Burlington Northern and Santa Fe Railway Company and Red Trail Energy, LLC. Filed as Exhibit 10.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.2	Management Agreement made and entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and GreenWay Consulting, LLC. Filed as Exhibit 10.2 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.3	Development Services Agreement entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and GreenWay Consulting, LLC. Filed as Exhibit 10.3 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.4	The Burlington Northern and Santa Fe Railway Company Real Estate Purchase and Sale Agreement with Red Trail Energy, LLC, dated January 14, 2004. Filed as Exhibit 10.4 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.5	Distiller’s Grain Marketing Agreement entered into effective as of March 1, 2004 by Red Trail Energy, LLC, and Commodity Specialist Company. Filed as Exhibit 10.5 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.6	Contract for Purchase of Coal made and entered into the 9th day of March, 2004 by and between Red Trail Energy, LLC, and General Industries, Inc., d/b/a Center Coal Company. Filed as Exhibit 10.6 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.7	Grain Origination Contract effective April 1, 2004 between Red Trail Energy, LLC, and New Vision Coop. Filed as Exhibit 10.7 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.8	Warranty Deed made as of January 13, 2005 between Victor Tormaschy and Lucille Tormaschy, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.8 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

40

10.9	Warranty Deed made as of July 11, 2005 between Neal C. Messer and Bonnie M. Messer, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.9 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.10	Agreement for Electric Service made the 18th day of August, 2005, by and between West Plains Electric Cooperative, Inc. and Red Trail Energy, LLC. Filed as Exhibit 10.10 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.11	Ethanol Fuel Marketing agreement entered into the 18th day of August, 2005, by and between Renewable Products Marketing Group, L.L.C. and Red Trail Energy, LLC. Filed as Exhibit 10.11 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.12+	Lump Sum Design-Build Agreement between Red Trail Energy, LLC, and Fagen, Inc. dated August 29, 2005. Filed as Exhibit 10.12 to the registrant’s registration statement on Form 10-12G/A-3 (000-52033) and incorporated by reference herein.
10.13	Railroad Construction, Design and Repair Contract made as of November 7, 2005, by and between R & R Contracting, Inc. and Red Trail Energy, LLC. Filed as Exhibit 10.13 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.14	Construction Loan Agreement dated as of the 16th day of December by and between Red Trail Energy, LLC, and First National Bank of Omaha. Filed as Exhibit 10.14 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.15	Construction Note for $55,211,740.00 dated December 16, 2005, between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.15 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.16	Revolving Promissory Note for $3,500,000.00, dated December 16, 2005, between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha as Bank. Filed as Exhibit 10.16 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.17	Promissory Note and Continuing Letter of Credit Agreement to First National Bank from Red Trail Energy, LLC, signed December 16, 2005. Filed as Exhibit 10.17 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.18	International Swap Dealers Association, Inc. Master Agreement dated as of December 16, 2005, signed by First National Bank of Omaha and Red Trial Energy, LLC. Filed as Exhibit 10.18 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.19	Security Agreement and Deposit Account Control Agreement made December 16, 2005, by and among First National Bank of Omaha, Red Trail Energy, LLC, and Bank of North Dakota. Filed as Exhibit 10.19 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.20	Security Agreement given as of December 16, 2005, by Red Trail Energy, LLC, to First National Bank of Omaha. Filed as Exhibit 10.20 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.21	Control Agreement Regarding Security Interest in Investment Property, made as of December 16, 2005, by and between First National Bank of Omaha, Red Trail Energy, LLC, and First National Capital Markets, Inc. Filed as Exhibit 10.21 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.22	Loan Agreement between GreenWay Consulting, LLC, and Red Trail Energy, LLC, dated February 26, 2006. Filed as Exhibit 10.22 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.23	Promissory Note for $1,525,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to GreenWay Consulting, LLC. Filed as Exhibit 10.23 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.24	Loan Agreement between ICM Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.24 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

41

10.25	Promissory Note for $3,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to ICM Inc. Filed as Exhibit 10.25 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.26	Loan Agreement between Fagen, Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.26 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.27	Promissory Note for $1,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to Fagen, Inc. Filed as Exhibit 10.27 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.28	Southwest Pipeline Project Raw Water Service Contract, executed by Red Trail Energy, LLC, on March 8, 2006, by the Secretary of the North Dakota State Water Commission on March 31, 2006, and by the Chairman of the Southwest Water Authority on April 2, 2006. Filed as Exhibit 10.28 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.29	Contract dated April 26, 2006, by and between the North Dakota Industrial Commission and Red Trail Energy, LLC. Filed as Exhibit 10.29 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.30	Subordination Agreement, dated May 16, 2006, among the State of North Dakota, by and through its Industrial Commission, First National Bank and Red Trail Energy, LLC. Filed as Exhibit 10.30 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.31	Firm Gas Service Extension Agreement, dated June 7, 2006, by and between Montana-Dakota Utilities Co. and Red Trail Energy, LLC. Filed as Exhibit 10.31 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.32	First Amendment to Construction Loan Agreement dated August 16, 2006 by and between Red Trail Energy, LLC and First National Bank of Omaha. Filed herewith.
10.33	Revolving Promissory Note for $3,500,000, dated August 16, 2006 given by First National Bank of Omaha to Red Trail Energy, LLC. Filed herewith.
10.34	Security Agreement and Deposit Account Control Agreement effective August 16, 2006 by and among First National Bank of Omaha and Red Trail Energy, LLC. Filed herewith.
10.35	Equity Grant Agreement dated September 8, 2006 by and between Red Trail Energy, LLC and Mickey Miller. Filed herewith.
10.36	Option to Purchase 200,000 Class A Membership Units of Red Trail Energy, LLC by Red Trail Energy, LLC from North Dakota Development Fund and Stark County dated December 11, 2006. Filed herewith.
10.37	Audit Committee Charter adopted April 9, 2007. Filed herewith.
10.38	Senior Financial Officer Code of Conduct adopted March 28, 2007. Filed herewith.
31.1	Certification by Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).
31.2	Certification by Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).
32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

b. Reports in Form 8-K.

June 14, 2006 regarding the Company’s receipt of a $350,000 grant agreement with the State of North Dakota and the entering into a Gas Service Agreement with Montana-Dakota Utilities Company. July 21, 2006 regarding the appointment of Ronald D. Aberle as Interim Chief Financial Officer August 29, 2006 regarding the resignation of Ronald D. Aberle as Interim Chief Financial Officer, the appointment of Bonnie G. Eckelberg as Chief Financial Officer and the appointment of Mick J. Miller as the Company’s President.

October 19, 2006 regarding amendment to Construction Loan Agreement with First National Bank of Omaha and entry into Security Agreement and Deposit Account Control Agreement with Bremer Bank December 19, 2006 regarding the entering into of an Option to Purchase up to 200,000 Membership Units of its Class A Membership Units currently owned by the North Dakota Development Funds for the purpose of establishing an employee bonus plan.

+ Confidential treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the    Securities and Exchange Commission.

42

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 17, 2007	/s/ Mick J. MillerMick J. Miller
	President and Chief Financial Officer
	(Principal Executive Officer)

Date: April 17, 2007	/s/ Bonnie EckelbergBonnie G. Eckelberg
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

Date: April 17, 2007
	Ambrose R. Hoff, Chairman of the Board

Date: April 17, 2007	/s/ William A. Price
	William A. Price, Vice President and Governor

Date: April 17, 2007 /s/ William N. DuToit   William N. DuToit, Treasurer and Governor

Date: April 17, 2007 /s/ Ron Aberle   Ron Aberle, Secretary and Governor

Date: April 17, 2007	/s/ Mike Appert
	Mike Appert, Governor

Date: April 17, 2007 /s/ Jody Hoff   Jody Hoff, Governor

Date: April 17, 2007 /s/ Grant Hoovestol   Grant Hoovestol, Governor

Date: April 17, 2007
	Troy Jangula, Governor
Date: April 17, 2007
	Tim Gross, Governor
Date: April 17, 2007	/s/ William Cornatzer, MDWilliam Cornatzer, Governor
Date: April 17, 2007	Kenny Meier, Governor
Date: April 17, 2007	/s/ Marlyn Richter
	Marlyn Richter, Governor
Date: April 17, 2007	/s/ Fred BraunFred Braun, Governor
Date: April 17, 2007	/s/ Don StreifelDon Streifel, Governor
Date: April 17, 2007	/s/ Duane ZentDuane Zent, Governor

43

Red Trail Energy, LLC
(A Development Stage Company)

Financial Statements

December 31, 2006 and 2005

Red Trail Energy, LLC
(A Development Stage Company)

C O N T E N T S

	Page
Report of Independent Registered Public Accounting Firm		F-2
Financial Statements
Balance Sheet		F-3
Statement of Operations		F-4
Statement of Changes in Members’ Equity		F-5
Statement in Cash Flows		F-6
Notes to Financial Statements		F-8 - 17

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Governors
Red Trail Energy, LLC
Richardton, North Dakota

We have audited the accompanying balance sheet of Red Trail Energy, LLC (a development stage company), as of December 31, 2006 and 2005, and the related statements of operations, changes in members’ equity, and cash flows for the years ended December 31, 2006, 2005 and 2004 and for the period from inception (July 16, 2003) to December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC, (a development stage company) as of December 31, 2006 and 2005, and the results of its operations, changes in members’ equity and its cash flows for the years ended December 31, 2006, 2005 and 2004 and for the period from inception (July 16, 2003) to December 31, 2006, in conformity with U.S. generally accepted accounting principles.

/s/ Boulay, Heutmaker, Zibell & Co. P.L.L.P.  

Certified Public Accountants 

Minneapolis, Minnesota
April 17, 2007

F-2

Red Trail Energy, LLC
(A Development Stage Company)

Balance Sheet

	December 31, 2006		December 31, 2005
ASSETS
Current Assets
Cash and equivalents	$	421,722	$	19,043,811
Derivative instruments		320,341		—
Prepaid expenses		63,782		25,345
Inventory		3,956,129		—
Total current assets		4,761,974		19,069,156
Property and Equipment
Land		300,602		300,602
Office equipment		151,851		—
Building		313,295		—
Construction in progress		83,290,008		16,647,583
		84,055,756		16,948,185
Less accumulated depreciation		16,016		—
Total property and equipment		84,039,740		16,948,185
Other Assets
Debt issuance costs, net of amortization		982,574		955,238
Deposits		80,000		—
Total other assets		1,062,574		955,238
Total Assets	$	89,864,288	$	36,972,579
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Current maturities of long term debt	$	2,909,228	$	—
Accounts payable		4,437,601		7,971,436
Accrued expenses		2,323,476		9,497
Market value – interest rate swap		110,935		277,952
Total current liabilities		9,781,240		8,258,885
Other Liabilities
Contracts payable		275,000		—
Long-term Debt		46,878,960		—
Members’ Equity		32,929,088		28,713,694
Total Liabilities and Members’ Equity	$	89,864,288	$	36,972,579

Notes to Financial Statements are an integral part of this Statement.

F-3

Red Trail Energy, LLC
(A Development Stage Company)

Statement of Operations

										From Inception
	Year ended			Year ended			Year ended			July 16, 2003 to
	December 31,			December 31,			December 31,			December 31,
	2006			2005			2004			2006
Revenues	$	—		$	—		$	—		$	—
Operating Expenses		3,747,730			2,087,808			433,345			6,689,020
Operating Loss		(3,747,730	)		(2,087,808	)		(433,345	)		(6,689,020	)
Other Income (Expense)
Grant income		—			50,000			100,000			150,000
Gain/(loss) from non-designated hedging		851,290			(277,952	)		—			573,338
Unrealized gain on hedging		210,100			—			—			210,100
Interest income		182,277			588,156			47,004			817,437
Total other income, net		1,243,667			360,204			147,004			1,750,875
Net Loss	$	(2,504,063	)	$	(1,727,604	)	$	(286,341	)	$	(4,938,145	)
Weighted Average Units Outstanding		39,625,843			24,393,980			3,591,180			13,920,740
Net Loss Per Unit, basic and fully diluted	$	(0.06	)	$	(0.07	)	$	(0.08	)		(0.35	)

Notes to Financial Statements are an integral part of this Statement.

F-4

Red Trail Energy, LLC
(A Development Stage Company)

Statement of Changes in Members’ Equity

						Additional											Total
	Member		Member			Paid in		Units			Unearned			Accumulated			Members’
	Units		Contributions			Capital		Subscribed			Compensation			Deficit			Equity
Balance — Inception, July 16, 2003			$	—		$	—	$	—		$	—		$	—		$	—
Capital contributions - 3,600,000 units, $0.33 per unit September 2003 - December 2003, adjusted for 3 for 1 split in January 2004		3,600,000		1,200,000					(33,550	)								1,166,450
Unit options issued - 62,500 units, $0.10 per unit, September 2003							56,825					(56,825	)
Amortization of unearned compensation												20,313						20,313
Net Loss															(420,137	)		(420,137	)
Balance — December 31, 2003		3,600,000		1,200,000			56,825		(33,550	)		(36,512	)		(420,137	)		766,626
Collection of subscribed units									33,550									33,550
Amortization of unearned compensation												36,512						36,512
Net Loss															(286,341	)		(286,341	)
Balance — December 31, 2004		3,600,000		1,200,000			56,825		—						(706,478	)		550,347
Capital contributions - 25,983,452 units, $1.00 per unit, April 6		25,983,452		25,983,452														25,983,452
Capital contributions - 1,389,303 units, $1.00 per unit, April 6 - June 30		1,389,303		1,389,303														1,389,303
Capital contributions 2,080,555 units, $1.00 per unit, July 1 - Sept 30		2,080,555		2,080,555														2,080,555
Capital contributions - 544,956 units, $1.00 per unit, Oct 1 - Dec 31		544,956		544,956														544,956
Costs related to capital contributions				(107,315	)													(107,315	)
Net Loss															(1,727,604	)		(1,727,604	)
Balance — December 31, 2005		33,598,266		31,090,951			56,825		—			—			(2,434,082	)		28,713,694
Capital contributions - 6,713,207 units, $1.00 per unit, Jan 1 - Mar 31		6,713,207		6,713,207														6,713,207
Units issued under option exercised - 62,500 units, $0.10 per unit		62,500		6,250														6,250
Net Loss															(2,504,063	)		(2,054,063	)
Balance — December 31, 2006		40,373,973		37,810,408		$	56,825	$	—		$	—		$	(4,938,145	)	$	32,929,088

Notes to Financial Statements are an integral part of this Statement.

F-5

RED TRAIL ENERGY, LLC
(A Development Stage Company)

Statements of Cash Flows

										From Inception
	Year Ended			Year Ended			Year Ended			July 16, 2003
	December 31,			December 31,			December 31,			to December 31
	2006			2005			2004			2006
Cash Flows from Operating Activities
Net income (loss)	$	(2,504,063	)	$	(1,727,604	)		(286,341	)	$	(4,938,145	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		16,016			—						16,016
Amortization of unearned compensation		—			—			36,512			56,825
Unrealized gain/loss on derivative instrument		(210,100	)		—						(210,100	)
Gain from non-designated hedging derivatives		(167,017	)		277,952			—			110,935
Changes in assets and liabilities
Inventory		(3,956,129	)								(3,956,129	)
Derivative instrument		(110,241	)		—						(110,241	)
Prepaid expenses		(38,437	)		(25,345	)		—			(63,782	)
Other assets — deposits		(80,000	)								(80,000	)
Accounts payable		(1,423,115	)		1,409,068			(37,715	)		139,137
Other liabilities		275,000									275,000
Accrued expenses		535,778			7,949			(1,369	)		545,275
Net cash used in operating activities		(7,662,308	)		(57,980	)		(288,913	)		(8,215,209	)
Cash Flows from Investing Activities
Capital expenditures		(66,903,860	)		(10,558,969	)		(313,821	)		(77,979,890	)
Net cash used in investing activities		(66,903,860	)		(10,558,969	)		(313,821	)		(77,979,890	)
Cash Flows from Financing Activities
Payments for deferred offering costs		—			(3,353	)		(103,962	)		(107,315	)
Payments for debt issuance costs		(563,566	)		(470,500	)					(981,775	)
Proceeds from long-term debt		49,788,188			—						49,788,188
Proceeds for stock subscriptions held in escrow		—			10,271,016			15,712,436			25,983,452
Member contributions		6,719,457			4,014,814			33,550			11,934,271
Net cash provided by financing activities		55,944,079			13,811,977			15,642,024			86,616,821
Net Increase (Decrease) in Cash and Equivalents		(18,622,089	)		3,195,028			15,039,290			421,722
Cash and Equivalents — Beginning of Period		19,043,811			15,848,783			809,493			—
Cash and Equivalents — End of Period	$	421,722		$	19,043,811		$	15,848,783		$	421,722
Supplemental Disclosure of Cash Flow Information
Interest paid and capitalized in construction in process	$	1,474,638		$	—		$	—		$	1,474,638
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Debt issuance costs included in accounts payable	$	799		$	484,738		$	—		$	799
Capital expenditures included in accounts payable	$	4,297,665		$	5,924,446		$	133,670		$	4,297,665
Capital expenditures included in accrued liabilities	$	1,778,201		$	—		$	—		$	1,778,201
Amortization of deferred offering costs capitalized in construction in process	$	52,291		$	—		$	—		$	52,291
Stock subscriptions held in escrow converted to member contributions	$	—		$	25,983,452		$	—		$	25,983,452
Member unit subscriptions	$	—		$	—		$	—		$	33,550
Issuance of restricted shares	$	—		$	—		$	—		$	56,825

Notes to Financial Statements are an integral part of this Statement.

F-6

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Red Trail Energy, LLC (a North Dakota Limited Liability Company), was organized to pool investors to build a 50 million gallon annual production ethanol plant near Richardton, North Dakota. Construction began in 2005 with an anticipated completion date of November 2006. Construction of the Plant was substantially completed as of December 31, 2006. As of December 31, 2006, the Company is in the development stage with its efforts being principally devoted to preliminary production. The Company exited its development stage in January 2007 when it began generating substantial revenues from ethanol production.

Fiscal Reporting Period

The Company adopted a fiscal year ending December 31 for reporting financial operations.

Accounting Estimates

Management uses estimates and assumptions in preparing these financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported revenues and expenses. Actual results could differ from those estimates.

Cash

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The carrying value of cash and equivalents approximates the fair value.

The Company maintains its accounts at various financial institutions. At times throughout the year, the Company’s cash and equivalents balances may exceed amounts insured by the Federal Deposit Insurance Corporation. At December 31, 2006 and December 31, 2005, the Company’s deposits exceeded insurance coverage by approximately $322,000 and $18.9 million, respectively.

Derivative Instruments

The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires the recognition of derivatives in the balance sheet and the measurement of these instruments at fair value.

In order for a derivative to qualify as a hedge, specific criteria must be met and appropriate documentation maintained. Gains and losses from derivatives that do not qualify as hedges, or are undesignated, must be recognized immediately in earnings. If the derivative does qualify as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be either offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of undesignated derivatives are recorded in costs of goods sold.

Additionally, SFAS No. 133 requires a company to evaluate its contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted as “normal purchases or normal sales.” Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. As of December 31, 2006 and 2005 the Company has no derivatives instruments that meet this criterion.

Inventory

Inventory consists of raw materials and work in process. Corn, the primary raw material, along with other chemicals and ingredients, is stated at the lower of average cost or market. Finished goods, when produced, will consist of ethanol and distillers grains produced, and will be stated at the lower of average cost or market.

Property and Equipment

Property and equipment is stated at the lower of cost or estimated fair value. Once assets are placed in service, which is expected to be in January 2007, depreciation will be provided over their estimated useful lives by use of the straight-line method. Maintenance and repairs are expensed as incurred; major improvements and betterments are capitalized.

The Company reviews its property and equipment impairment whenever events indicate that the carrying amount of the asset may not be recoverable. An impairment loss is recorded when the sum of the future cash flows is less than

F-7

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

the carrying amount of the asset. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds its fair value.

The Company had incurred substantial consulting, permitting and other pre-construction services related to building its Plant facilities. Prior to 2005, due to the substantial uncertainties regarding the Company’s ability to proceed with the ultimate facility construction until the Company had raised debt and equity financing, the Company expensed these pre-construction costs as incurred.

Debt Issuance Costs

Debt issuance costs will be amortized over the term of the related debt by use of the effective interest method. Amortization commenced June 2006 when the Company began drawing on the related bank loan. Amortization expense for December 31, 2006 was $52,291 which is included in construction in progress. There was no amortization expense for the years ended December 31, 2005 or 2004.

Deferred Offering Costs

The Company deferred the costs incurred to raise equity financing until that financing occurred. At such time that the issuance of new equity occurred, these costs were netted against the proceeds. As of April 6, 2005, the minimum equity had been raised and these costs were netted against the proceeds received.

Fair Value of Financial Instruments

The fair value of the Company’s cash and cash equivalents, accounts payable, and derivative instruments approximates their carrying value. It is not currently practicable to estimate the fair value of our long-term debt and contracts payable since these agreements contain unique terms, conditions, and restrictions, which were negotiated at arm’s length. As such, there are no readily determinable similar instruments on which to base an estimate of fair value of each item.

Grants

The Company recognizes grant proceeds as other income for reimbursement of expenses incurred upon complying with the conditions of the grant. For reimbursements of capital expenditures, the grants are recognized as a reduction of the basis of the asset upon complying with the conditions of the grant.

Grant income received for incremental expenses that otherwise would not have been incurred is netted against the related expenses.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes and generally does not incur income taxes. Instead, its earnings and losses are included in the income tax returns of the members. Therefore, no provision or liability for federal or state income taxes has been included in these financial statements.

Differences between financial statement basis of assets and tax basis of assets is related to capitalization and amortization of organization and start-up costs for tax purposes, whereas these costs are expensed for financial statement purposes.

Organizational and Start Up Costs

The Company expenses all organizational and start up costs as incurred.

Advertising

The Company expenses advertising costs as they are incurred. Advertising costs totaled approximately $18,900 as of December 31, 2006. There was no advertising expense for the years ended December 31, 2005 or 2004.

Equity-Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123R”), Share-Based Payment, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. In January 2005, the SEC issued SAB No. 107, which provides supplement implementation guidance for SFAS No. 123R. SFAS No. 123R eliminates the ability to account for stock-based compensation transaction using the intrinsic value method under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and instead generally requires that such transaction be accounted for using a fair-value-based method. The Company adopted the provisions of SFAS No. 123R using the straight-line attribution method. Under this

F-8

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

method, the Company recognizes compensation cost related to service-based awards ratably over a single requisite service period.

The Company recognizes the related costs under these agreements using the straight-line attribution method over the grant period and the current fair value unit price. Compensation expense for the year ended December 31, 2006 is approximately $25,000 and is included in operating expenses and accrued expenses as of December 31, 2006. There was no compensation expense for the years ended December 31, 2005 or 2004.

Prior to 2006, the Company utilized a standard option pricing model, such as Black-Scholes, to measure the fair value of stock options granted to an independent contractor. The following assumptions were used to estimate the fair value of the options outstanding: dividend yield and expected volatility of 0%, risk free rate of 2%, and expected lives of 3 years.

Earnings Per Share

Earnings per share are calculated on a basic and fully diluted basis using the weighted average units outstanding during the period. Equity-based compensation, representing 200,000 units, is not considered in the fully diluted calculation since they are anti-dilutive and contingent on future events.

Environmental Liabilities

The Company’s operations are subject to environmental laws and regulations adopted by various governmental entities in the jurisdiction in which it operates. These laws require the Company to investigate and remediate the effects of the release or disposal of materials at its location. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, occupational health and the production, handling, storage and use of hazardous materials to prevent material, environmental or other damage, and to limit the financial liability which could result from such events. Environmental liabilities, if any, are recorded when the liability is probable and the costs can reasonably be estimated. No such liabilities have been identified as of December 31, 2006 and 2005.

Recently Issued Accounting Pronouncements

Management has reviewed recently issued, but not yet effective, accounting pronouncements and does not expect the implementation of these pronouncements to have a significant effect on the Company’s financial statements.

2. DERIVATIVE INSTRUMENTS

At December 31, 2006, the Company has recorded an asset for derivative instruments related to a corn put options with a market value of approximately $320,341. The open position at December 31, 2006 is not designated as a cash flow or fair value hedge. The Company had no recorded derivative instruments related to corn for the year ended December 31, 2005.

The Company has derivative instruments in the form of interest rate swaps in an agreement associated with bank financing. Fair market value related to the interest rate swap liabilities totaled approximately $111,000 and $278,000 as of December 31, 2006 and 2005. Market value adjustments and net settlements related to these agreements are recorded as a gain or loss from non-designated hedging derivatives. See Note 5 for a description of these agreements.

3. PROPERTY, PLANT AND EQUIPMENT

Amounts included in construction in progress are as follows:

	December 31, 2006		December 31, 2005
Construction costs	$	73,715,280	$	15,516,973
Rain infrastructure and development		3,391,214		1,026,124
Water wells		558,327		4,678
Other costs		5,625,187		99,808
	$	83,290,008	$	16,647,583

Construction of the Plant was substantially completed and preliminary production operations commenced in December 2006. During fiscal 2006, the Company capitalized interest related to the expansion to a 50 million gallon plant of approximately $1,475,000. There was no interest capitalized during fiscal year 2005. The Company expects to begin depreciating the construction in process once the Plant commences operations in January 2007. After reclassification construction in progress to its permanent classification upon the completion of a definitive cost segregation study, property, plant and equipment are expected to be approximately as follows:

F-9

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

Category	Cost		Average Life
Land improvements	$	7,748,577	20 years
Buildings		4,846,085	40 years
Plant equipment		67,882,287	7 to 15 years
Railroad and rail equipment		3,391,214	20 years
Office equipment		187,293	5 to 7 years
	$	84,055,456

4. BANK FINANCING

Long-term debt consists of the following:

	December 31, 2006
Construction loan agreement payable to bank, see below	$	44,060,352
Subordinated notes payable, see below		5,525,000
Capital lease obligations (Note 6)		202,836
Total	$	49,788,188
Less amounts due within one year		2,909,228
Total	$	46,878,960

The estimated maturities of long-term liabilities at December 31, 2006 are as follows:

2007	$	2,909,228
2008		4,130,850
2009		4,460,213
2010		4,787,398
2011		5,134,932
Thereafter		28,365,567
Total Long-Term Liabilities	$	49,788,188

In December 2005, the Company entered into a Credit Agreement with a bank providing for a total credit facility of approximately $59,712,000 for the purpose of funding the construction of the Plant. The construction loan agreement provides for the Company to maintain certain financial ratios and meet certain non-financial covenants. The loan agreement is secured by substantially all of the assets of the Company and includes the terms as described below.

Construction Loan

The Credit Agreement provides for a construction loan for up to an amount of approximately $55,212,000 with a loan termination date of April 16, 2012. Interest is to be charged at a rate of 3.4% over LIBOR, which totaled 8.71% and 7.77% at December 31, 2006 and 2005, respectively. The agreement calls for interest only payments to be made every three (3) months beginning March 2006 through the loan termination date. As of December 31, 2006, the Company has advanced $44,060,352 on this loan. There were no amounts outstanding as of December 31, 2005.

At the loan termination date, all principal and unpaid interest will be converted to three term notes each with specific interest rates and payment terms as described in the construction loan agreement.

The first of the three notes is a Fixed Rate Note in the amount of approximately $27,606,000 with interest payments made on a quarterly basis and charged at fixed rate of 3.0% over LIBOR (8.31% as of December 31, 2006) on the date of the construction loan termination date. Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $470,000 and increasing to $653,000 per quarter, from April 2007 to October 2011, with a final principal payment of approximately $17,000,000 at January 2012. The note is secured by substantially all assets of the Company.

The second term note is referred to as the Variable Rate Note and is in the amount of approximately $17,606,000. Interest will be charged at a variable rate of 3.4% over the three-month LIBOR rate (8.71% as of December 31, 2006).

The third term note, the Long-Term Revolving Note, in the amount of approximately $10,000,000, will be charged interest at a variable rate of 3.4% over the one-month LIBOR rate (8.81% as of December 31, 2006.). The agreement calls for payments of approximately $1,005,000 to be made each quarter with amounts allocated to the

F-10

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

term notes in the following manner: 1) to accrued interest on the Long-Term Revolving Note, 2) to accrued interest on the Variable Rate Note, and 3) to the principal balance on the Variable Rate Note.

All unpaid amounts on the three term notes are due and payable in April 2012. The Company has outstanding borrowings on the construction loan of approximately $44,060,352 as of December 31, 2006. The Company has incurred interest expense on this loan of approximately $1,475,000 in 2006 which is included in construction in progress. There were no amounts outstanding nor any interest incurred as of December 31, 2005 or 2004.

Revolving Line of Credit

The Company entered into a $3,500,000 line of credit agreement with its bank, subject to certain borrowing base limitations, through July 5, 2007. Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over LIBOR, which totaled 8.75% at July 5, 2007. The Company has no outstanding borrowings at December 31, 2006 and 2005. The Company has incurred interest expense in fiscal year 2006 of approximately $5,000 which is included in construction in progress.

Interest Rate Swap Agreement

The Credit Agreement provides for the Company to enter into interest rate swap contracts for up to approximately $2.8 million. In December 2005, the Company entered into an interest rate swap transaction that effectively fixes the interest rate at 8.08% on approximately $27.6 million of any outstanding principal of the Fixed Rate Note.

The interest rate swap was not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements are charged to gain from non-designated hedging derivatives. For the years ended December 31, 2006 and 2005, there were no net settlements, and market value adjustments resulted in a gain of approximately $167,000 in 2006 and a loss of approximately $278,000 in 2005, from non-designated hedging derivative letters of credit.

Letters of Credit

The Credit Agreement provides for up to $1,000,000 in letters of credit with the bank. All letters of credit are due and payable at the loan termination date in April 2007. The agreement provides for the Company to pay a quarterly commitment fee of 2.25% of all outstanding letters of credit. As of December 31, 2006, the Company had one outstanding letter of credit of approximately $137,000 for capital expenditures for gas services with Montana-Dakota Utilities Co. There were no amounts outstanding as of December 31, 2005.

Subordinated Debt

As part of the Credit Agreement, the Company entered into three separate subordinated debt agreements totaling approximately $5,525,000. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate (a total of 10.75% at December 31, 2006) and is due and payable subject to approval by the Senior Lender, the bank. Interest is compounding quarterly with any unpaid interest converted to principal. Amounts will be due and payable in full in April 2012. The outstanding balance on these loans is $5,525,000 as of December 31, 2006. The Company has incurred interest expense of approximately $337,000 in 2006 which is included in construction in progress. There were no amounts outstanding as of December 31, 2005.

5. LEASES

The Company leases equipment under operating and capital leases through 2011. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under an operating lease includes rail cars. Rent expense for operating leases was approximately $11,250 for the year ending December 31, 2006. Equipment under capital leases consists of office equipment and equipment used for the construction of the Plant is included in construction in progress as December 31, 2006.

Equipment under capital leases is as follows at:

	December 31, 2006		December 31, 2005
Equipment	$	216,745	$	—
Accumulated amortization		598		—
Totals	$	216,147	$	—

F-11

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

At December 31, 2006, the Company had the following minimum commitments, which at inception had non-cancelable terms of more than one year:

	Operating Leases			Capital Leases
2007	$	27,000		$	61,701
2008		27,000			61,701
2009		27,000			61,701
2010		27,000			49,648
2011		13,500			1,916
Total minimum lease commitments	$	121,500		$	236,667
Less amount representing interest					33,831
			��
Present value of minimum lease commitments included in the preceding long-term liabilities				$	202,836

6. MEMBERS’ EQUITY

The Company was formed on July 16, 2003 to have an indefinite life. The Company was initially capitalized by conducting a private placement with its founding members who were also its first governors. The founding members contributed $1,200,000 ($1.00 per unit) of seed capital in exchange for 1,200,000 Class A Membership Units. During January 2004, the Company approved a 3 for 1 split on these founding Membership Units, effectively issuing 3,600,000 Class A Membership Units for approximately $0.33 per unit. All references in the financial statements and notes to the number of units outstanding and per unit amounts of the Company’s Class A Membership Units reflect the effect of the unit split for all periods presented. The proceeds from this offering were used to pay for organizational, permitting and other development costs.

Income and losses are allocated to all members based upon their respective percentage units held. Only one class of membership units is outstanding or authorized.

The Company prepared and filed a Registration Statement with the State of North Dakota during fiscal 2004. The Offering was for up to 40,000,000 Class A Membership Units available for sale at $1.00 per unit. The minimum purchase requirement was 10,000 units for a minimum investment of $10,000. Thereafter, additional units were available for purchase in 1 unit increments for sale at $1.00 per unit. The Company has one class of membership units with each unit representing a pro rata ownership interest in the Company’s capital, profits, losses and distributions.

Under the terms of its North Dakota Registration Statement, the Company had until May 30, 2005 to both a) sell at least the minimum number of units required to close the private offering of Class A Membership Units and b) enter into an executed debt financing commitment letter from a bank. Investments received were held in escrow through April 6, 2005, at which point the Company had raised the minimum required $25,000,000 in cash proceeds and obtained the required executed debt financing commitment letter from a bank. If the minimum offering and the debt financing commitment had not been obtained, the amount held in escrow would have been refunded to each subscriber with no interest earned.

The escrowed funds received by the Company were held in a segregated bank account, in the Company’s name, until the initial offering was closed on April 6, 2005. The Company reported the amounts in their financial statements as “restricted cash” until April 6, 2005, when the funds became available for general use. Because no membership units were issued or issuable until such a time as the Company met the minimum unit sales and bank financing commitment requirements, the Company recorded a corresponding liability for “unit subscriptions held in escrow.” This liability represented amounts that would have been returned to unit subscribers had the minimum offering and bank commitment requirements not been met. Cash received subsequent to the initial close on the minimum required unit sales was available for use as received and as the respective membership units were issued.

On March 1, 2006, the Company closed its offering with a total of 36,711,473 Class A Membership Units sold, and aggregate offering proceeds of $36,711,473. The Company paid approximately $107,000 in costs of offering its membership units, which was offset against the equity raised once the minimum required cash proceeds were received during 2005.

In August 2003, the Company granted an independent contractor an option to purchase up to 62,500 Class A Membership Units at $0.10 per unit. The options vested at the completion of the duties as specified by the project coordinator agreement. At September 30, 2006, these options have been exercised for a purchase of the full 62,500

F-12

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

units for aggregate proceeds of $6,250. Compensation related to those options was approximately $36,500 in 2004. No related expense was recorded in 2006 or 2005.

7. EQUITY-BASED COMPENSATION

2006 Equity-Based Incentive Plan

During 2006, the Company has an equity-based incentive plan (the “Plan”) which provides for the issuance of restricted Class A Membership Units to the Company’s key management personnel, for the purpose of compensating services rendered. These units have vesting terms established by the Company at the time of each grant. Vesting terms of outstanding awards begin after one to three years of service and are fully vested after ten years of service. A total of 200,000 units of the Company’s equity have been reserved for issuance under the Plan.

8. GRANTS

The Company has been awarded four grants. It has been awarded an Ag Products Utilization Council grant in the amount of $150,000 to be used for general business expenses, including legal and accounting. All proceeds from this grant were received in 2005 and 2004.

In 2006 the Company was entered into a contract with the State of North Dakota through its Industrial Commission for a Lignite Grant not to exceed $350,000. In order to receive the proceeds, the Company must construct a 50 million-gallon-per-year ethanol plant located in North Dakota that utilizes clean lignite technologies in the production of ethanol. The Company must also provide the Industrial Commission with specific reports in order to receive the funds. After the first year of operation, the Company will be required to repay a portion of the proceeds in annual payments of $22,000 over ten years. These payments could increase based on the amount of lignite the Company is using as a percentage of primary fuel. The Company has received $275,000 from this grant in 2006.

In September 2006, the Company finalized a training program agreement with Job Service North Dakota. This program provides an incentive to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training new employees. The Company may receive up to $169,813 over ten years

The Company entered into a Workforce 20/20 contract with the state in October 2006. This program is designed to assist North Dakota business and industry in retraining and upgrading the skills of current employee brought about through the introduction of new technologies or work methods to the workplace. The purpose is to foster the growth and competition of North Dakota’s work force and industry by ensuring that the current work force has the skills and expertise to compete in a global economy. The Company has received the approximately $27,550 from this grant during 2006.

9. COMMITMENTS AND CONTINGENCIES

Design Build Contract

The total cost of the project, including the construction of the ethanol plant and start-up expenses, is expected to approximate $99,000,000. The Company signed a Design-Build Agreement with Fagen, Inc. (a related party) in September 2005 to design and build the ethanol plant at a total contract price of approximately $77,000,000.

Consulting Contracts

In August 2003, the Company entered into a contract with an individual to provide project coordination services for approximately $70,000 per year in connection with the construction of the Company’s plant. Either party could terminate this agreement upon default or thirty days written notice. In 2005, this individual became a member of the Company through the purchase of units and as a result of exercising options received under this consulting agreement in January 2006. Total costs paid to this member totaled $182,000 and $169,000 as of December 31, 2006 and 2005, respectively. This agreement was terminated in September 2006.

In December 2003, the Company entered into a contract with a consulting firm to provide project coordination and development services in connection with the design, construction and initial operation of the Company’s plant for $3,050,000. Either party upon a default of the other may terminate this agreement.

In December 2003, the Company entered into a contract with a consulting firm to provide management services related to the Company’s plant. For these services, the Company will pay the consultant $200,000 per year, reimburse the consultant for the salary and benefits of a General Manager and Plant Manager, as well as pay 4% of the Company’s pre-tax net income once the plant is in compliance with the engineer’s performance standard, except for the reimbursement of the salary and benefits of the General Manager and Plant Manager, which began in June 2006. Either party may terminate this agreement upon a default of the other after thirty days written notice.

F-13

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

In February 2006, the Company entered into a Risk Management Agreement for Grain Procurement and Byproduct Marketing with John Stewart & Associates (JSA). JSA will provide services in connection with grain hedging, pricing and purchasing. The Company will pay $2,500 per month for these services beginning no sooner than ninety days preceding plant startup. In addition, JSA will serve as clearing broker for the Company and charge a fee of $15.00 per contract plus clearing and exchange fees.

Utility Agreements

The Company entered into a contract with West Plains Electric Cooperative, Inc. dated August 2005, for the provision of electric power and energy to the Company’s plant site. The agreement is effective for five years from August 2005, and thereafter for additional three year terms until terminated by either party giving to the other six months’ notice in writing. The agreement calls for a facility charge of $400 per month and an energy charge of $0.038 per kWh for the first 400,000 kWh and $0.028 per kWh thereafter. In addition, there is an $8.00 per kW monthly demand charge based on the highest recorded fifteen minute demand.

In March 2006, the Company entered into a ten year contract with Southwest Water Authority to purchase raw water. The contract includes a renewal option for successive periods not to exceed ten years. Additionally, the contract requires the Company to make an $80,000 prepayment to be held in escrow for a minimum of three years after which $40,000 may be applied toward its water bill. The base rate for raw water shall be $0.72 per each one thousand gallons of water. The base rate may be adjusted annually by the State Water Commission. Subsequent to quarter end, the Company made the $80,000 prepayment.

In June 2006, the Company entered into an agreement with Montana-Dakota Utilities Co. (MDU) for the construction and installation of a natural gas line. The agreement requires the Company to pay $3,500 prior to the commencement of the installation and to maintain an irrevocable letter of credit in the amount of $137,385 for a period of five years as a preliminary cost participation requirement. If the volume of natural gas used by the Company exceeds volume projections, the Company will earn a refund of the preliminary cost participation requirement and interest at 12% annually.

Marketing Agreements

The Company entered into a Distillers Grain Marketing Agreement with Commodity Specialist Company (CSC) in March 2004, for the sale and purchase of distillers grains. The contract is an all output contract with a term of one year from start-up of production of the Plant and continuing thereafter until terminated by either party after ninety days notice. CSC receives a 2% fee based on the sales price per ton sold with a minimum fee of $1.35 per ton and a maximum fee of $2.15 per ton. At December 31, 2006, the Company is in a start up stage and no payments have been paid as a result of this agreement.

The Company entered into an Ethanol Fuel Marketing Agreement in August 2005 with Renewable Products Marketing Group, LLC (RPMG), which makes RPMG the Company’s sole marketing representative for the Company’s entire ethanol product. The Agreement is a best good faith efforts agreement. The term of the Agreement is twelve months from the first day of the month that the Company initially ships ethanol to RPMG. At the termination of the initial twelve month term, the Agreement provides that the parties “shall be at liberty to negotiate an extension of the contract.” The Company will pay RPMG $0.01 per gallon for each gallon of ethanol sold by RPMG. At December 31, 2006, the Company is in a start up stage and no payments have been paid as a result of this agreement.

Coal Purchase Contract

The Company entered into a contract in March 2004 with General Industries, Inc. d/b/a Center Coal Company (CCC) for the purchase of lignite coal. The term of the contract is for ten years from the commencement date agreed upon by the parties. The Company will pay CCC $17.35 per ton of coal delivered beginning in 2005 plus/minus a fuel adjustment amount for delivery costs. The price per ton of coal delivered increases each year by approximately $0.05 per ton. The fuel adjustment is based on the market price of fuel.

Chemical Consignment Purchase Contracts

During November 2006, the Company entered into two consignment purchases for bulk chemicals purchased through Genecor International Inc. Genecor will provide the following enzymes: Alpha-Amylase at $3.42 per KG, Glucoamylease at $2.35 per KG and Protease at $9.95 per KG. The Univar agreement states that it will provide the following bulk chemicals: Caustic Soda, Sulfuric Acid, Anyhydous Ammonia and Sodium Bicarbonate. All Univar chemicals are purchased at market price.

Chemical Purchase Contract

The Company entered into a contract in October 2005 with Quadra Energy Trading Inc. for the purchase of Natural Gasoline. The term of the contract is November 2006 through April 2007. The price is the weekly average front month NYMEX Crude Oil plus $11.00 bbl.

F-14

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

Grain Origination Contract

The Company entered into a grain origination contract with New Vision Coop (NVC) in April 2004 for grain origination and related services. The term of the contract is three years from its start date, unless extended through an amendment. However, either party may cancel the contract by providing sixty days’ written notice to the other party. The Company shall pay NVC a development fee of $25,000 upon completion of construction. Thereafter, the fee will be $0.005 per bushel for all grain delivered by rail, with no fee for grain transported by truck. The Company will also pay NVC an incentive fee of 10% for profits earned through the use of corn futures, call options and put options.

Rail Track Design

The Company entered into a railroad construction agreement with R & R Contracting, Inc. in November 2005. The agreement includes the engineering, site excavation, materials and track construction. The track was completed in the fourth quarter of 2006. The total costs of the rail track was approximately $3,400,000, which is included in property, plant and equipment at December 31, 2006.

Leases

The Company entered into an operating lease in July 2006 for the lease of a locomotive. The term of the contract is for a period of five years commencing upon delivery. The Company will pay $75 per day or $2,250 per month.

In September 2006, the Company entered into an agreement for office equipment under a long-term capital lease agreement valued at $10,245. The contract requires monthly payments of approximately $200 over a period of five years.

The Company entered into an agreement for a 2004 CAT Loader with Merchants Capital under a long-term capital lease agreement valued at $112,500. The contract requires monthly payments of approximately $2,730 over a period of four years.

The Company entered into an agreement for a telescopic handler with Butler Machinery under a long-term capital lease agreement valued at $94,000. The contract requires monthly payments of approximately $2,195 over a period of four years starting on October 15, 2006.

10. RELATED PARTY TRANSACTIONS

The Company has balances and transaction in the normal course of business with various related parties for the purchases of corn to begin the pre-production phase and costs associated with the construction of the Plant. Significant related party activity affecting consolidated financial statements are as follows:

	December 31, 2006		December 31, 2005
Accounts payable	$	46,281	$	—
Accrued liabilities		1,525,000		—
Corn Purchases during 2006		172,176		—

11. INCOME TAXES

The difference between financial statement basis and tax basis of assets are as follows:

	2006		2005
Financial statement basis of assets	$	89,864,288	$	36,972,579
Plus: organization and start-up costs		6,195,047		2,941,290
Plus: book to tax depreciation		1,191		—
Income tax basis of assets	$	96,060,526	$	39,913,869
Financial statement basis of liabilities		47,153,960		8,258,952
Less: interest rate swap		110,935		277,952
Income tax basis of liabilities	$	47,043,025	$	7,980,933

F-15

Red Trail Energy, LLC
(A Development Stage Company)

Notes to Financial Statements

December 31, 2006 and 2005

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarter results are as follows

Statement of Operations

	March 2006			June 2006			September 2006			December 2006
Revenues	$	0		$	0		$	—		$	—
Operating expenses		156,235			246,524			406,079			2,938,892
Operating loss		(156,235	)		(246,524	)		(406,079	)		(2,938,892	)
Other income, net		544,731			340,744			(622,571	)		980,763
Net income (loss)		388,496			94,220			(1,028,650	)		(1,958,129	)
Weighted average units		37,340,846			40,375,973			40,375,973			40,375,973
Net income (loss) per unit		0.01			0.00			(0.03	)		(0.05	)

	March 2005			June 2005			September 2005			December 2005
Revenues	$	—		$	—		$	—		$	—
Operating expenses		109,545			97,260			115,016			1,765,987
Operating loss		(109,545	)		(97,260	)		(115,016	)		(1,765,987	)
Other income, net		113,563			94,094			181,921			(29,374	)
Net income (loss)		4,018			(3,166	)		66,905			(1,795,361	)
Weighted average units outstanding		3,600,000			290,126,070			31,497,630			33,246,647
Net income (loss) per unit		0.00			0.00			0.00			(0.05	)

The above quarterly financial data is Unaudited, but in the opinion of management, all adjustments necessary for a fair presentation of the selected data for these periods presented .have been included.

13. SUBSEQUENT EVENTS

Since the start up of operations in January 2007, the Plant has experienced a number of shut-downs as a result of issues related to the use of lignite coal in operations. During March 2004, the Company entered into a contractual agreement with General Industries, Inc. d/b/a Center Coal Company (CCC) for the purchase and use of lignite coal for a term of ten years from the commencement date agreed upon by the parties. Due to the issues related to the use of lignite coal, the Compnay is considering using Powder River Basin (PRB) coal as an alternative to lignite. The Company is working with the parties involved on both short-term and long-term solutions. the Plant contractor and designer has approved the use of PRB coal in the Plant and Plant facilities. While the Company does expect the costs of PRB to exceed that of lignite, the Company does not expect a significant impact on income from operations

F-16