UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10

GENERAL FORM FOR REGISTRATION OF
SECURITIES
Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934

RED TRAIL ENERGY, LLC

(Name of Registrant as specified in its charter)

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

P.O. Box 11
3682 Hwy. 8 South
Richardton, ND 58652
(Address of principal executive offices)

701-974-3308
(Registrant’s Telephone Number)
With a copy to:

Todd A. Taylor and Michael R. O’Brien
Leonard, O’Brien, Spencer, Gale & Sayre, Ltd.
100 South Fifth Street, Suite 2500
Minneapolis, MN 55402
612-332-1030

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

Title of each class		Name of each exchange on which registered
None		None

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

LIMITED LIABILITY COMPANY
CLASS A MEMBERSHIP UNITS
(Title of Class)

 

 

RED TRAIL ENERGY, LLC
FORM 10

		Page
ITEM 1. BUSINESS			1
ITEM 2. FINANCIAL INFORMATION			33
ITEM 3. PROPERTIES			44
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			45
ITEM 5. GOVERNORS AND EXECUTIVE OFFICERS			46
ITEM 6. EXECUTIVE COMPENSATION			49
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			49
ITEM 8. LEGAL PROCEEDINGS			50
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED MEMBER MATTERS			50
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES			51
ITEM 11. DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED			51
ITEM 12. INDEMNIFICATION OF GOVERNORS AND EXECUTIVE OFFICERS			55
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			55
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			55
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS			55
SIGNATURES
Articles of Organization
Operating Agreement
Membership Unit Certificate Specimen
Member Control Agreement
Lease of Land for Construction/Rehabilitation of Track
Management Agreement
Development Services Agreement
Real Estate Purchase and Sale Agreement
Distiller's Grain Marketing Agreement
Contract for Purchase of Coal
Grain Origination Contract
Warranty Deed - January 13, 2005
Warranty Deed - July 11, 2005
Agreement for Electric Service
Ethanol Fuel Marketing Agreement
Lump Sum Design-Build Agreement
Railroad Construction, Design & Repair Contract
Construction Loan Agreement
Construction Note for $55,211,740
Revolving Promissory Notes for $3,500,000
Promissory Note and Continuing Letter of Credit Agreement
International Swap Dealers Association, Inc. Master Agreement
Security Agreement and Deposit Account Control Agreement
Security Agreement
Control Agreement
Loan Agreement - GreenWay Consulting, LLC & Red Trail Energy, LLC
Promissory Note for $1,525,000
Loan Agreement - ICM Inc. & Red Trail Energy, LLC
Promissory Note for $3,000,000
Loan Agreement - Fagen, Inc & Red Trail Energy, LLC
Promissory Note for $1,000,000
Southwest Pipeline Project Raw Water Service Contract

ITEM 1. BUSINESS

Overview

     Red Trail Energy, LLC was organized as a North Dakota limited liability company on July 16, 2003 (the “Company.”) We were originally formed for the purpose of raising capital to develop, construct, own and operate a 50 million gallon per year corn-based ethanol plant in Richardton, North Dakota. Based on estimates from our design engineer, ICM Inc., we expect our ethanol plant to annually process approximately 18 million bushels of corn into 50 million gallons of denatured fuel grade ethanol, 170,000 tons of dried distillers grains with solubles, or 430,000 tons of distillers wet grains. In this process we will consume approximately 133,000 tons of lignite coal per year. Unless otherwise indicated, whenever we use the terms we, us, our or ours, we mean the Company. Our website is located at www.redtrailenergyllc.com .

General Developments

     Land Acquisition

     On March 22, 2004, January 13, 2005 and July 11, 2005, we acquired 134.7 acres of land just east of Richardton, North Dakota as the site for our plant. On October 18, 2005, we started construction at this site.

     Construction Contract

     We have executed a Lump-Sum Design Build Contract dated August 29, 2005, with Fagen, Inc. for the design and construction of our plant. Plant construction began October 18, 2005 and we expect construction to be completed in approximately November 2006. We have utilized funds from our sales of securities, grants and interest income to pay for construction costs to date.

     Loan Agreements

     On December 16, 2005, we closed on a construction loan agreement with First National Bank of Omaha for total loan proceeds of $59,712,000. We are utilizing the proceeds from this construction loan agreement to pay Fagen, Inc. for the design and construction of our plant. We had not used any of the proceeds from this loan yet.

     On December 16, 2005, we closed on a Subordinated Debt Agreement with Fagen, Inc. in the amount of $1,000,000. We have not utilized the proceeds from this agreement yet.

     On December 16, 2005, we closed on a Subordinated Debt Agreement with ICM Inc. in the amount of $3,000,000. We have not utilized the proceeds from this agreement yet.

     On December 16, 2005, we closed on a Subordinated Debt Agreement with GreenWay Consulting, LLC. in the amount of $1,525,000. We have not utilized the proceeds from this agreement yet.

     Consulting Agreements

     We have entered into two contracts with GreenWay Consulting, LLC. The first is a Development Services Agreement whereby GreenWay will manage project development, plant construction and initial plant operations through plant start-up. The second is a Management Agreement for management of operations after plant start-up.

     Marketing Agreements

     We have entered into marketing agreements to market all of our ethanol and distillers dried grains with solubles. Because we have not commenced operations yet, we have not sold any ethanol or distillers dried grains with solubles and we do not expect to do so until at least November 2006.

Primary Product — Ethanol

     Ethanol is a chemical produced by the fermentation of sugars found in grains and other biomass. Ethanol can be produced from a number of different types of grains, such as wheat and milo, as well as from agricultural waste products such as rice hulls, cheese whey, potato waste, brewery and beverage wastes and forestry and paper wastes. 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 a mix of corn and other input. Corn produces large quantities of carbohydrates, which convert into glucose more easily than most other kinds of biomass.

     We anticipate that our business will be that of the production and marketing of ethanol and distillers dried and wet grains. We have entered into an agreement with Commodity Specialist Company, Inc. located in Minneapolis, Minnesota to market our dried grains with solubles. We intend to be our own marketer of wet grains, and we have entered into an agreement with Renewable Products Marketing Group, LLC located in Minneapolis, Minnesota to market our entire ethanol output.

Description of Dry Mill Process

     Our plant will produce ethanol by processing corn. The corn will be received by rail and by truck, then weighed and unloaded in a receiving building. It will then be transported to storage bins. Thereafter, it will be converted to a scalper to remove rocks and debris before it is transported to a hammermill, or grinder, where it is ground into a flour and conveyed into a slurry tank for enzymatic processing. Then, water, heat and enzymes are added to break the ground grain into a fine slurry. The slurry will be heated for sterilization and pumped to a liquefaction tank where additional enzymes are added. Next, the grain slurry is pumped into fermenters, where yeast is added, to begin a batch fermentation process. A vacuum distillation system will divide the alcohol from the grain mash. Alcohol is then transported through a rectifier column, a side stripper and a molecular sieve system where it is dehydrated. The 200 proof alcohol is then pumped to tank farm shift tanks and blended with approximately five percent denaturant, usually gasoline, as it is pumped into storage tanks. The 200 proof alcohol and approximately five percent denaturant constitute ethanol.

     Corn mash from the distillation stripper is pumped into one of several decanter-type centrifuges for dewatering. The water (“thin stillage”) is then pumped from the centrifuges to an evaporator where it is evaporated into thick syrup. The solids that exit the centrifuge or evaporators (the “wet cake”) are conveyed to the distillers dried grains dryer system or to flat storage to be sold as wet distillers grains with solubles. Syrup is added to the wet cake as it enters the dryer, where moisture is removed. The process will produce distillers grains, which is processed corn mash that can be used as animal feed.

     The following chart illustrates the dry mill process:

The Ethanol Production Process (Dry-Mill)

Source: Renewable Fuels Association (RFA)

     1. In the dry-mill ethanol process, the corn kernels are first ground into a flour, or “meal,” and mixed with water in cookers to form a slurry, called “mash.”

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

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

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

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

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

Thermal Oxidation

     Ethanol plants such as ours may produce odors in the production of ethanol and its primary co-product, distillers dried grains with solubles and distillers wet grains, which some people may find unpleasant. We intend to eliminate odors by routing dryer emissions through a thermal oxidizer. Based upon materials and information from ICM Inc., we expect thermal oxidation to significantly reduce any unpleasant odors caused by the ethanol and distillers grains manufacturing process. We expect thermal oxidation, which burns emissions, will eliminate a significant amount of the volatile organic carbon compounds in emissions that cause odor in the drying process and

allow us to meet the applicable permitting requirements. We also expect this addition to the ethanol plant to reduce the risk of possible nuisance claims and any related negative public reaction against us.

Ethanol Markets

     Ethanol has important applications. Primarily, ethanol can be used as 1) a high quality octane enhancer and an oxygenate capable of reducing air pollution and improving automobile performance and 2) an alternative to gasoline. We have entered into a marketing contract with Renewable Products Marketing Group, LLC to market all of our ethanol.

Local Ethanol Markets

     Local markets are the easiest to service because of their close proximity. The local market where we intend to build our plant, however, may be oversold with regional marketers leading to depressed ethanol prices and is likely unable to purchase and utilize our production capacity. Therefore, it is likely that the majority of our ethanol will be marketed to regional and national markets.

Regional Ethanol Markets

     Typically, a regional market is one that is outside of the local market, yet within the neighboring states. Because ethanol use results in less air pollution than regular gasoline, regional markets typically include large cities that are subject to anti-smog measures in either carbon monoxide or ozone non-attainment areas, such as Minneapolis/St. Paul. In addition, the state of Minnesota has required that all gasoline sold in the state be reformulated to include 10% ethanol, with an increase to 20% by 2013. We expect to reach these regional markets by delivering ethanol by truck and by rail. Regional pricing tends to follow national pricing less the freight difference.

     Occasionally, we may have opportunities to obtain backhaul rates from local trucking companies. These are rates that are reduced since the truck is loaded both ways. Normally, the trucks drive to the refined fuels terminals empty and load gasoline product for delivery. A backhaul is the opportunity to load the truck with ethanol to return to the terminal.

National Ethanol Markets

     According to the Renewable Fuels Association, demand for fuel ethanol in the United States reached a new high in 2005 of 4.26 billion gallons per year. In its report titled, “Ethanol Industry Outlook 2006,” the Renewable Fuels Association stated that they anticipate the demand for ethanol to remain strong. The passage of the Volumetric Ethanol Excise Tax Credit (“VEETC”) is expected to provide the flexibility necessary to expand ethanol blending into higher blends of ethanol such as E85, E diesel and fuel cell markets. In addition, the recent implementation of a Renewable Fuels Standard contained in the Energy Policy Act of 2005, which was signed into law on August 8, 2005 is expected to favorably impact the ethanol industry by enhancing both the production and use of ethanol.

     Historically, ethanol sales have also been favorably affected by the Clean Air Act amendments of 1990, particularly the Federal Oxygen Program which became effective November 1, 1992. The Federal Oxygen Program required the sale of oxygenated motor fuels during the winter months in certain major metropolitan areas to reduce carbon monoxide pollution. Ethanol use increased due to a second Clean Air Act program, the Reformulated Gasoline Program. This program became effective January 1, 1995, and required 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 MTBE and ethanol, however, MTBE has contributed to groundwater contamination and has been banned from use by many states.

     Although the Energy Policy Act of 2005 did not impose a national ban of MTBE, its failure to include liability protection for manufacturers of MTBE is expected to result 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

such Act also repeals the Clean Air Act’s 2% oxygenate requirement for reformulated gasoline immediately in California and 270 days after enactment elsewhere.

Ethanol Pricing

     The following chart provides a comparison of ethanol and gasoline price per gallon in the Minneapolis/St. Paul area from 1994 to 2005:

     The following table provides monthly prices per gallon of ethanol in the Minneapolis/St. Paul area.

     Historic prices may not be indicative of future prices. On March 23, 2005, the Chicago Board of Trade (“CBOT”) launched the CBOT Denatured Fuel Ethanol futures contract. The new contract is designed to address the growing demand for an effective hedging instrument for domestically produced ethanol. We expect that our ethanol marketing firm will use the new ethanol futures contracts to manage ethanol price volatility.

Co-Products

     The 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 bypass protein that is superior to other protein supplements such as cottonseed meal and soybean meal. According to a 1986 study by the University of Nebraska reported in “Nebraska Company Extension Study MP51 — Distillers Grains,” bypass proteins are more digestible to the animal, thus generating greater lactation in dairy cows and greater weight gain in beef cattle. Dry mill ethanol processing creates three forms of distillers grains: distillers wet grains with solubles (“distillers wet grains”), distillers modified wet grains with solubles (“distillers modified wet grains”) and distillers dry grains. Distillers wet grains are processed corn mash that contains approximately 70% moisture and have a shelf life of approximately seven days. Therefore, they can be sold only to farms within the immediate vicinity of an ethanol plant. Distillers modified wet grains are distillers wet grains that have been dried to approximately 50% moisture. They have a slightly longer shelf life of approximately three weeks and are often sold to nearby markets. Distillers dried grains are distillers wet grains that have been dried to 10% moisture. Distillers dried grains have an almost indefinite shelf life and may be sold and shipped to any market regardless of its proximity to an ethanol plant. Our plant will be producing distillers wet grains and distillers dried grains but not modified wet grains.

     Based on the ICM plans, our plant is expected to produce approximately 166,500 tons annually of raw carbon dioxide as another co-product of the ethanol production process. At this time, we do not intend to capture and market our carbon dioxide gas. We believe the market for carbon dioxide gas is currently oversupplied and therefore prices are too low to make capturing and marketing carbon dioxide profitable. If prices increase to a level where we believe it would be profitable to capture the carbon dioxide, we will consider adding the necessary equipment to do so, however, we expect that adding this equipment will be expensive and could potentially require us to curtail or cease operations while it is installed. We do not foresee the carbon dioxide market improving at any time soon.

Distillers Grains Markets

     According to the University of Minnesota’s DDGS—General Information website (October 12, 2005) approximately 3,200,000 to 3,500,000 tons of distillers grains are produced annually in North America, approximately 98% of which are produced by ethanol plants. Ethanol plants in South Dakota and Minnesota produce about 25% of this amount. The amount of distillers grains produced is expected to increase significantly as the number of ethanol plants increase.

     The primary consumers of distillers grains are dairy and beef cattle. In recent years, an increasing amount of distillers grains have been used in the swine and poultry markets. With the advancement of research into the feeding rations of poultry and swine, these markets are expected to continue to grow. The market for distillers grains is generally confined to locations where freight costs allow it to be competitively priced against other feed ingredients. Distillers grains competes with three other feed formulations: corn gluten feed, dry brewers grain and mill feeds. The primary value of these products as animal feed is their protein content. Dry brewers grain and distillers grains have about the same protein content, and corn gluten feed and mill feeds have slightly lower protein contents.

     As with ethanol, the distillers grains markets are local, regional and national. These national markets are just emerging, primarily in the southeast and southwest United States where significant dairy and poultry operations are located. In addition, there is the possibility of some local marketing. Local markets are very limited and highly competitive for the use of distillers grains.

     Although local markets will be the easiest to service, they may be oversold, which would depress distillers grains prices. We plan to market 25% of our distillers grains as wet distillers grains to the local livestock markets surrounding the plant. The distillers dried grains will be marketed through our marketing contract with Commodity Specialist Company to the regional and national markets.

Dried Distillers Grains Pricing

     Historically, the price of dried distillers grains has been relatively steady. Various factors affect the price of dried distillers grains, including, among others, the price of corn, soybean meal and other alternative feed products, and the general supply and demand of domestic and international markets for distillers grains. We believe that unless demand increases, the price of distillers grains may be subject to future downward pressure as the supply of distillers grains increases because of increased ethanol production. As demonstrated in the table below, the price of distillers grains may be subject to downward pressure.

Wet Distillers Grains

     Wet distillers grains consist of approximately 70% moisture and 30% dry matter. Because of the short shelf life, we will have to sell wet distillers grains locally. We hope to develop a local market once the plant is operating. Because wet distillers grains do not have to be dried, there will be a significant energy savings to the extent that we can sell wet distillers grains.

Corn Feedstock Supply

     Based upon ICM data, we anticipate that our plant will need approximately 18 million bushels of corn per year for our processing. We have entered into a Grain Origination Agreement with New Vision Coop to supply all of our corn. The corn supply for our plant will be obtained from regional markets, including North Dakota, South Dakota and Minnesota. Traditionally, corn grown in these areas has been fed locally to livestock or exported for feeding or processing, but more recently, the construction of numerous ethanol plants has increased competition for the corn supply. We expect to purchase corn from North Dakota, South Dakota and Minnesota, which had the following amount of grain corn production according to the U.S. Department of Agriculture:

     We will be dependent on the availability and price of corn. The price at which we will purchase corn will depend on prevailing market prices. Although we do not anticipate problems sourcing corn, there is no assurance that a shortage will not develop, particularly if there are other ethanol plants competing for corn, an extended drought in the area, or other production problems. In addition, our financial projections assume that we can purchase corn for prices near the ten-year average for corn at our plant. We believe that the ten-year average price for corn in the three states we are planning on purchasing our corn from for our plant is $2.08 per bushel.

     Corn prices are primarily dependent on world feedstuffs supply and demand and on United States and global corn crop production, which can be volatile as a result of a number of factors, the most important of which are weather, current and anticipated stocks and prices, export prices and supports and the government’s current and anticipated agricultural policy. We note that historical corn pricing information from the U.S. Department of Agriculture indicates that the price of corn has fluctuated significantly in the past and may fluctuate significantly in the future. Because the market price of ethanol is not related to corn prices, ethanol producers are generally not able to compensate for increases in the cost of grain feedstock through adjustments in prices charged for their ethanol. We, therefore, anticipate that our plant’s profitability will be negatively impacted during periods of high corn prices.

Grain Origination and Risk Management

     As part of our Grain Origination Agreement, New Vision Coop will assist us in arranging the consistent scheduling of corn deliveries and to establish and fill forward contracts through grain elevators and producers. In addition, we have engaged John Stewart and Associates to provide Risk Managed Services for us. Together they will utilize forward contracting and hedging strategies, including certain derivative instruments such as futures and option contracts, to manage our commodity risk exposure and optimize finished product pricing on our behalf. We anticipate that most of our grain will be acquired in this manner. Forward contracts allow us to purchase corn for future delivery at fixed prices without using the futures market. The corn futures market allows us to trade in standard units of corn for delivery at specific times in the future. Option contracts consist of call options (options to purchase a fixed amount of a commodity) and put options (options to sell a fixed amount of a commodity). We expect to use a combination of these derivative instruments in our hedging strategies to help guard against corn price volatility. Hedging means protecting the price at which we buy corn and the price at which we will sell our products in the future. It is a way to attempt to reduce the risk caused by price fluctuation. The effectiveness of such hedging activities will depend on, among other things, the cost of corn and our ability to sell enough ethanol and distillers grains to use all of the corn subject to futures and option contracts we have purchased as part of our hedging strategy. Although we will attempt to link hedging activities to sales plans and pricing activities, such hedging activities themselves can result in costs because price movements in corn contracts are highly volatile and are influenced by many factors that are beyond our control. We may incur such costs and they may be significant.

Project Location and Proximity to Markets

     We started construction on our plant on October 18, 2005 and anticipate it will be completed by November 2006. Our plant will be owned by us and located in Richardton, North Dakota.

     While we have obtained all required permits for construction of the plant, there can be no assurance that we will not encounter environmental hazardous conditions such as groundwater or other subsurface contamination as we continue construction at the plant site. The presence of an environmental hazardous condition will likely delay construction of the ethanol plant and may require significant expenditure of our resources to correct the condition. In addition, our contractor may be entitled to an adjustment in price if it has been adversely affected by the environmental hazardous condition. If we encounter any environmental hazardous conditions during construction

that require time or money to correct, such event may have a material adverse effect on our operations, cash flows and financial performance.

Transportation and Delivery

     Our plant will have the facilities to receive grain by truck and rail and to load ethanol and distillers grains onto trucks and rail cars. We purchased land from the Burlington Northern and Santa Fe Railway Company for $15,650 for construction, location and maintenance of trackage and have a contract with R&R Contracting, Inc. for construction of track.

Utilities

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.

Coal

     Based on ICM data, we expect that our plant will consume approximately 133,000 tons of lignite coal per year (375 tons of lignite coal per operating day) for which we have a ten-year contract with General Industries, Inc. d/b/a Center Coal Company. This contract provides that we can purchase and have delivered to our plant approximately 133,000 tons of lignite coal annually, or 375 tons per operating day. The price for the lignite coal is established by the contract and escalates annually through 2014 from $17.45 per ton in 2007 to $18.00 per ton in 2014, subject to adjustment based on delivery costs incurred by Center Coal Company to deliver the coal to our plant.

     Despite this contract, there can be no assurance that the coal we need will always be delivered as we need it. 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 and 29,943,000 tons in 2004, 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. If there is an interruption in the supply of coal for any reason, such as supply or delivery, 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 and profits.

     If there is an interruption in the supply of coal for any reason, such as supply or delivery 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.

     In addition to lignite coal, we could use natural gas as a fuel source if our coal supply is significantly interrupted. There is a natural gas line within 3 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 have already obtained our coal-related permits, we do not expect to need natural gas.

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 to purchase raw water. Under the contract we are required to purchase a minimum of 200 million gallons per year. Prior to connection, we are required to

deposit with the Authority a prepayment of $80,000. After 3 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. If there is an interruption in the supply of water 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.

     If there is an interruption in the supply of water for any reason, such as supply or delivery 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.

     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.

Employees

     We presently have 2 full-time employees, both of whom are administrative assistants working with our General Manager, Mick Miller, who is contracted to work with us by GreenWay Consulting, LLC (“Greenway”). After completion of the plant construction and commencement of operations, we intend to hire approximately 40 full-time employees plus a Plant Manager under contract from GreenWay. Our current plan is that 8 of our employees will be involved primarily in management and administration and the remainder will be involved primarily in plant operations. We expect that our costs for the first year of operations for employees will be approximately $1,500,000 plus $80,000 for a plant manager and $125,000 for a general manager.

     The following table represents some of the anticipated positions within the plant and the minimum number of individuals we expect will be full-time personnel:

     The positions, titles, job responsibilities and number allocated to each position may differ when we begin to employ individuals for each position. We may be required to hire additional personnel in one, if not more, positions. These additional personnel may be required to possess more education or skills that we currently estimate we need.

     We intend to enter into written confidentiality and assignment agreements with our executive officers and employees. Among other things, these agreements will 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 will depend 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.

Sales and Marketing

     We have entered into marketing contracts to market all of our ethanol and distillers dry grains with solubles. We intend to sell and market the wet distillers grains produced at the plant ourselves to local feed lots. We expect that most, if not all, of our ethanol and distillers dry grains with solubles will be sold through normal and established regional and national markets. We do not plan to hire or establish a sales organization to market these products. Consequently, we will be extremely dependent on the entities we have engaged to market each of our products.

Strategic Partners

Contract with Fagen, Inc.

     We have executed a Lump-Sum Design-Build Contract with Fagen, Inc. for design and construction services. We are also relying upon ICM Inc., for our process engineering services. ICM Inc., is being paid as apart of the Fagen Lump-Sum Design-Build Contract. We expect to pay Fagen approximately $76,000,000 in exchange for the following services:

	•		Providing a preliminary design and construction schedule and a guaranteed maximum price for the design and construction of the plant; and
	•		Designing and building the plant.

GreenWay Consulting, LLC

     We have entered into two contracts with GreenWay, LLC. The first is a Development Services Agreement whereby GreenWay will manage project development, plant construction and initial plant operations through plant start-up. The second is a Management Agreement for management of operations after plant start-up. The Management Agreement is for 5 successive years after successful commissioning of the plant. We are extremely dependent for our success on GreenWay’s performance. If GreenWay fails or refuses to perform under either of its agreements, we would have to identify and engage a replacement manager or management consultant. This could take considerable time, effort and expense, during which time we may not be able to operate the plant efficiently or at all. If we operate the plant at a reduced efficiency, or not at all, our business and financial condition would be materially adversely affected.

Construction and Timetable for Completion of the Project

     We estimate that the plant will be completed and ready for operations in November 2006. We are extremely dependent on Fagen, Inc., our design-build contractor for the successful and timely completion of our plant. If Fagen fails or refuses to perform under its contract with us, our plant may not be completed when projected and the commencement of our operations could be substantially delayed. Prior to November 2006, we expect preliminary testing, training of personnel and start-up of operations at our plant to occur. This schedule also assumes that bad weather, and other factors beyond our control, do not upset our timetable as there is no additional

time built into our construction schedule for unplanned contingencies. There can be no assurance that the timetable that we have set will be followed and factors or events beyond our control could hamper our efforts to complete the project in a timely fashion.

Regulatory Permits

     We will be subject to extensive air, water and other environmental regulations and have obtained a number of environmental permits to construct and operate the plant. We have engaged Natural Resource Group, Inc., to coordinate and assist us with obtaining certain environmental permits and to advise us on general environmental compliance. There is no written agreement in place with Natural Resource Group, Inc. Thus far we have incurred costs of $239,000 for regulatory permits preparation, site investigations and applications and expect to incur additional costs of at least $50,000 through the completion of the plant start-up.

     We obtained a Building and Use Permit, North Dakota Drive Permit, Electrical Wiring Certificate, North Dakota Air Pollution Control Permit and Authorization to Discharge Under the North Dakota Pollutant Discharge Elimination System prior to starting construction. Additional permits will be required shortly before or shortly after we can begin to operate the plant. If for any reason any of these additional permits are not granted, construction costs for the plant may increase, the construction might be delayed or forced to cease all together or we may be unable to commence operations at the plant as expected without significant design changes. In addition to the state requirements, the Environmental Protection Agency (“EPA”) could impose conditions or other restrictions in the permits that are detrimental to us or which increase permit requirements or the testing protocols and methods necessary to obtain a permit either before, during or after the permitting process. North Dakota and the EPA could also modify the requirements for obtaining a permit. Any such event would likely delay our operations and reduce our revenues.

     Even if we receive all required permits from North Dakota, we may also be subject to regulatory oversight from the EPA. Currently, the EPA’s statutes and rules do not require us to obtain separate EPA approval in connection with the construction and operation of the plant. North Dakota is authorized to enforce the EPA’s federal emissions program. However, the EPA does retain authority to take action if it decides that the state is not correctly enforcing its emissions program. Additionally, environmental laws and regulations, both at the federal and state level, are subject to change, and changes can be made retroactively. Consequently, even if we have the proper permits at the present time, we may be required to invest or spend considerable resources to comply with future environmental regulations or new or modified interpretations of those regulations to the detriment of our financial performance and cash flows.

     The following is a list of the material permits we may be required to obtain:

Federal Permits

Clean Air Act

* Prevention of Significant Deterioration (PSD) and Construction Permits
* Applicable Federal New Source Performance Standards (NSPS)
* Applicable National Emission Standards for Hazardous Air Pollutants (NESHAPS)
* Title V Operating Permit of the Clean Air Act Amendments of 1990
* Risk Management Plan

Clean Water Act

* National Pollutant Discharge Elimination System (NPDES)
* Oil Pollution Prevention and Spill Control Countermeasures

Comprehensive Environmental Response Compensation and Liability Act & Community Right to Know Act (CERCLA/EPCRA)

* Tier II Forms * listing of potentially hazardous chemicals stored on-site
* EPCRA Sections 313 and 304 and CERCLA Section 103. These reports track use and release of
regulated substances above threshold and/or designated quantities annually

Alcohol and Tobacco Tax and Trade Bureau (ATF)

* Alcohol Fuel Permit (AFP)

State Permits

* Air Quality Permits
* Storage Tank Permits
* Water Quality Permits
* State Liquor License
* State Department of Motor Fuels
* State Department of Transportation

Highway Access Permit
Possible Easement Rights

* State Department of Health
* State Department of Public Service

Boiler License

* State Department of Natural Resources

Water appropriation permits
Other waters and wetland considerations

Major PSD Permit for Air Emissions

     Our estimates indicate that our facility will be considered a major source of regulated air pollutants. The Environmental Protection Agency has proposed new regulations that would lower the emissions standards for fuel ethanol plants. These new regulations, if enacted, may permit our facility to be classified as a minor source of regulated air pollutants. There are a number of emission sources that require permitting. These sources include the coal furnace, boiler, ethanol process equipment, storage tanks, scrubbers and baghouses. The types of regulated pollutants that are expected to be emitted from our plant include SO2, PM10, CO, NOx and VOCs. The activities and emissions mean that we are expected to obtain a major construction permit for the facility emissions. Because of regulatory requirements, we anticipate that we will agree to limit production levels to a certain amount to fix potential emissions, which may be higher than the production levels described in this document (currently projected at 50 million gallons per year at the nominal rate with the permit at a higher rate of 68.5 MMgal/year) in order to project compliance with air dispersion modeling and Best Available Control Technology (“BACT”) limits for a major source air permit facility. These production limitations will be a part of the major construction permit. If we exceed these production limitations, we could be subjected to very expensive fines, penalties, injunctive relief and civil or criminal law enforcement actions. Exceeding these production limitations could also require us to pursue modification to a major source air permit. There is also a risk that pursuant to further analysis prior to commencement of operations, a change in design assumptions or a change in the interpretation of regulations may require us to file for a modified air permit. If we must obtain a modified air permit, then we will experience significantly increased expenses and a significant delay in obtaining a subsequently sought Title V air permit. There is also a risk that North Dakota might reject a Title V air permit application and request additional information, further delaying startup and increasing expenses. There is also a risk that the area in which the plant is situated may later be determined to be a nonattainment area for a particular pollutant. In this event, the threshold standards that require a Title V permit may be changed, thus requiring us to file for and obtain a modified Title V air permit. The cost of complying and documenting compliance should a modified Title V air permit be required is also higher. It is also possible that in order to comply with applicable air regulations or to avoid having to obtain a Title V permit, we would have to install additional air pollution control equipment such as additional or different scrubbers.

Air Pollution Standard

     There are a number of standards which may affect the construction and operation of the plant going forward. The Prevention of Significant Deterioration (“PSD”) regulation creates more stringent and complicated permit review procedures for construction permits. It is possible, but not expected, that the plant may exceed applicable PSD levels for NOx, CO, and VOCs. If the plant exceeds applicable PSD levels for NOx, CO and VOCs, then the plant would be required to install more expensive pollution control equipment in order to reach the

mandatory maximum levels for NOx, CO and VOCs. The purchase and installation of such equipment would increase costs.

Waste Water Discharge Permit

     This plant will be a zero-discharge facility. We expect that we will use water to cool our closed circuit systems in the plant. In order to maintain a high quality of water for the cooling system, the water will be continuously replaced with make-up water. As a result, this plant will discharge clean, non-contact cooling water from boilers and the cooling towers. We intend to use a receiving stream to discharge the cooling water from our plant. A North Dakota Pollution Discharge Elimination System Permit (NDPES) was obtained prior to commencement of construction of the plant. We have also entered into an agreement with Assumption Abbey which is located to the north of the plant regarding the discharge of our cooling water into a receiving stream that feeds into a lake on the Monastery’s property.

New Source Performance Standards

     The plant will be subject to new source performance standards for both the plant’s distillation processes and the storage of volatile organic compounds used in the denaturing process. These duties include initial notification, emissions limits, compliance, monitoring requirements and record keeping requirements.

Spill Prevention, Control and Countermeasures Plan

     Before we can begin operations, we must prepare and implement a Spill Prevention Control and Countermeasure (“SPCC”) plan in accordance with the guidelines contained in 40 CFR § 112. This plan will address oil pollution prevention regulations and must be reviewed and certified by a professional engineer. The SPCC must be reviewed and updated every three years.

Alcohol and Tobacco Tax and Trade Bureau Requirements

     Before we can begin operations, we must comply with applicable Alcohol and Tobacco Tax and Trade Bureau (formerly the Bureau of Alcohol, Tobacco and Firearms) regulations. These regulations require that we first make application for and obtain an alcohol fuel producer’s permit. The application must include information identifying the principal persons involved in our venture and a statement as to whether any of them have ever been convicted of a felony or misdemeanor under federal or state law. The term of the permit is indefinite until terminated, revoked or suspended. The permit also requires that we maintain certain security measures. We must also secure an operations bond pursuant to 27 CFR § 19.957. There are other taxation requirements related to special occupational tax and a special stamp tax.

Risk Management Plan

     Once the plant is in production, we may use anhydrous ammonia. Pursuant to § 112I(7) of the Clean Air Act, stationary sources with processes that contain more than a threshold quantity of a regulated substance are required to prepare and implement a Risk Management Plan. If we use anhydrous ammonia, we must establish a plan to prevent spills or leaks of the ammonia and an emergency response program in the event of spills, leaks, explosions or other events that may lead to the release of the ammonia into the surrounding area. The same requirement may also be true for denaturant. This determination will be made as soon as the exact chemical makeup of the denaturant is obtained. We will need to conduct a hazardous assessment and prepare models to assess the impact of an ammonia and/or denaturant release into the surrounding area. The program will be presented at one or more public meetings. However, if we use a different ammonia, such as aqueous ammonia, the risk management program will only be needed for the denaturant. In addition, it is likely that we will have to comply with the prevention requirements under OSHA’s Process Safety Management Standard. These requirements are similar to the Risk Management Plan requirements. The Risk Management Plan will be filed before our plant is operational.

Environmental Protection Agency

     Even if we receive all state required environmental permits for construction and operation of the plant, we will also be subject to oversight activities by the EPA. There is always a risk that the EPA may enforce certain rules

and regulations differently than the state’s environmental administrators. State or EPA rules and regulations are subject to change, and any such changes may result in greater regulatory burdens.

Nuisance

     Ethanol production has been known to produce an odor to which surrounding residents could object. Ethanol production may also increase dust in the area due to operations and the transportation of coal and grain to the plant and ethanol and distillers dried and wet grains from the plant. Such activities may subject us to nuisance, trespass or similar claims by employees or property owners or residents in the vicinity of the plant. To help minimize the risk of nuisance claims based on odors related to the production of ethanol and its co-products, we intend to install a thermal oxidizer in the plant.

     We are not currently involved in any litigation involving nuisance or any other claims, nor are we aware of any such claims that have not yet reached litigation or have been threatened against us.

General Ethanol Demand and Supply

     Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains, and 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 nonpetroleum-based gasoline substitute. Approximately 95% of all ethanol is used in its primary form for blending with unleaded gasoline and other fuel products. The implementation of the Federal Clean Air Act has made ethanol fuels an important domestic renewable fuel additive. Used as a fuel oxygenate, ethanol provides a means to control carbon monoxide emissions in large metropolitan areas. The principal purchasers of ethanol are generally the wholesale gasoline marketer or blender. Oxygenated gasoline is commonly referred to as reformulated gasoline.

     According to the Renewable Fuels Association, the annual demand for fuel ethanol in the United States reached a new high in 2005 of 4.26 billion gallons per year. In its report titled, “Ethanol Industry Outlook 2006,” the Renewable Fuels Association stated that they anticipate the demand for ethanol to remain strong. The passage of the Volumetric Ethanol Excise Tax Credit (“VEETC”) is expected to provide the flexibility necessary to expand ethanol blending into higher blends of ethanol such as E85, E diesel and fuel cell markets. In addition, the recent implementation of a Renewable Fuels Standard contained in the Energy Policy Act of 2005, which was signed into law on August 8, 2005, is expected to favorably impact the ethanol industry by enhancing both the production and use of ethanol.

     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 will begin at 4 billion gallons in 2006, increasing to 7.5 billion gallons by 2012. 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 Fuels Association, RFS is expected to lead to about $6 billion in new investments 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 RFS may cause ethanol prices to increase in the short term due to additional demand, future supply could exceed the demand for ethanol. This would have a negative impact on our earnings. Alternatively, since the RFS begins at 4 billion gallons in 2006 and national production is expected to exceed this amount, there could be an oversupply until the RFS requirements exceed national production. This would have an immediate adverse affect on our earnings.

     On December 28, 2005, the Environmental Protection Agency (“EPA”) released interim rules governing the implementation of the 2006 RFS requirement. The EPA’s interim rule imposes a collective compliance approach, which means the requirement for 2006 fuel use is determined in the aggregate rather than on a refiner-by-refiner basis. The EPA adopted this approach for 2006 because current uncertainties regarding the RFS might result in unnecessarily high costs of compliance if each party was required to independently comply. 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. However, in the unlikely event that the RFS is not met in 2006, the EPA expects to adjust the volume requirement in 2007 to cover the deficit. There are no other consequences for failure to collectively meet the 2006 standard. The EPA expects to promulgate more comprehensive regulations by August 8, 2006, but the interim rules and collective compliance approach are expected to apply for the entire 2006 calendar year. In 2007 and subsequent years, the EPA expects to

specifically identify liable parties, determine the applicable RFS, and develop a credit trading program. Further, the standards for compliance, record-keeping and reporting are expected to be clarified.

     The following shows the RFS created by the Energy Policy Act of 2005:

Source: American Coalition for Ethanol (ACE)

     According to the Renewable Fuels Association, the supply of domestically produced ethanol is at an all-time high. The RFA stated that in 2005, 95 ethanol plants located in 19 states annually produce a record 4.26 billion gallons, a 20% increase from 2004 and 62% increase from 2000. As of May 2006, there were 97 ethanol plants with an initial capacity of nearly 4.5 billion gallons and 35 new plants and 9 major expansions were under construction, representing an additional 2.2 billion gallons of production capacity within the next 18 months.

     Ethanol supply is also affected by ethanol produced or processed in certain countries in South and Central America and the Caribbean region United States’ demand for imported ethanol has risen recently due to supply issues in certain parts of the United States as MTBE usage is being reduced and replaced with ethanol. A portion of the ethanol produced in these countries is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative (“CBI”). Large ethanol producers, such as Cargill, have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as Costa Rica, Jamaica and El Salvador, which would convert ethanol into fuel-grade ethanol for shipment to the United States. Ethanol imported from Caribbean Basin countries may be a less expensive alternative to domestically produced ethanol. According to the United States International Trade Commission, the 2005 CBI import quota was 240.4 million gallons of ethanol and the 2006 CBI import quota is 268.1 million gallons of ethanol. Legislation has been introduced in the Senate that would limit the transshipment of ethanol through the CBI. However, there is no assurance or guarantee that such legislation will be introduced or that it will be successfully passed.

Federal Ethanol Supports

     Historically, ethanol sales have also been favorably affected by the 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 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 contributed to groundwater contamination and has been banned from use by many states. Although the Energy Policy Act of 2005 did not impose a national ban of MTBE, its failure to include liability protection for manufacturers of MTBE is expected to result 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 such Act repeals the Clean Air Act’s 2% oxygenate requirement for reformulated gasoline immediately in California and 270 days after enactment elsewhere.

     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 is also possible that federal or state environmental rules or regulations could be adopted that could have an adverse affect on the use of ethanol. For example, changes in the environmental regulations regarding ethanol’s use due to currently unknown effects on the environment could have an adverse affect 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.

     The use of ethanol as an alternative fuel source has been aided by federal tax policy. 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 to be collected on all reformulated gasoline and allocated to the highway trust fund. This is expected 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 gasoline blended with 10% ethanol. 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 E-85 and the E-20 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. Because we expect our production to be less than the production limits of 60 million gallons a year, we expect to be eligible for the credit.

     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 January 1, 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.

     The ethanol industry and our business depend upon continuation of the federal ethanol supports discussed above. These incentives have supported a market for ethanol that might disappear without the incentives. Alternatively, the incentives may be continued at lower levels than currently exist. The elimination or reduction of such federal ethanol supports would make it more costly for us to sell our ethanol and would likely reduce our net income.

North Dakota Ethanol Supports

Fuel Tax Incentive Program

     We expect to 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 averages as calculated in number 1 and number 2 below:

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, our investors may be eligible for a tax credit against North Dakota state income tax liability. 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. Under the code section, a “qualified business” is a business that:

	a.		Is incorporated or organized in North Dakota after December 31, 2000, for the primary purpose of processing and marketing agricultural commodities capable of being raised in North Dakota;
	b.		Has been certified by the North Dakota Securities Commissioner to be in compliance under the securities laws of North Dakota;
	c.		Has an agricultural commodity processing facility, or intends to locate one, in North Dakota; and
	d.		Is among the first 10 businesses that meet these requirements.

     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. We may not be able to meet the requirements of a through d above and as of the date hereof, we are unaware if this tax credit is still available. If we do not meet the requirements of a “qualified business,” our members will not be eligible for a tax credit.

Our Primary 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 enter the market if the demand for

ethanol continues to increase. Our plant will compete with other ethanol producers on the basis of cost and price. 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 will be able to compete favorably with other ethanol producers due to the cost of coal relative to natural gas. In addition, we expect that the site selected for our plant will be accessible to multiple modes of transportation, such as railroad and highways, which may reduce our cost of sales.

     According to the Renewable Fuels Association (“RFA”), during the last 20 years, ethanol production capacity in the United States has grown from almost nothing to an estimated 4.2 billion gallons per year. Plans to construct new plants or to expand existing plants have been announced which would increase capacity by approximately 2.2 billion gallons per year. This increase in capacity is likely to continue in the future. We cannot determine the affect of this type of an increase upon the demand or price of ethanol.

     The ethanol industry has grown to approximately 97 production facilities in the United States according to the RFA. The largest ethanol producers include Abengoa Bioenergy Corp., Archer Daniels Midland (“ADM”), Aventine Renewable Energy, Inc., Cargill, Inc., New Energy Corp. and VeraSun Energy Corporation, all of which are capable of producing more ethanol than we expect to produce. ADM recently announced its plan to add approximately 500 million gallons per year of additional ethanol production capacity in the United States. ADM is currently the largest ethanol producer in the United States and controls a significant portion of the ethanol market. ADM’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. In addition, there are several regional entities recently formed, or in the process of formation, of similar size and with similar resources to ours. North Dakota currently has two ethanol plants producing an aggregate of 35 million gallons of ethanol per year. In addition, there are several ethanol plants in or near to North Dakota under construction or in the planning stage.

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

*		farmer owned
		Source: Renewable Fuels Association, April 12, 2006.

     In addition to our domestic competition, we will face competition in the ethanol industry from international suppliers of ethanol, including, but necessary limited to, Brazil and Caribbean Basin countries that produce ethanol

from sugarcane and import it into the United States. Recently, ethanol imports have increased as MTBE has been phased out in parts of the United States, most notably the eastern United States. While we do not believe that this recent trend will continue as domestic ethanol is supplied to these states, imported ethanol may continue to be a viable competitor for our, and all domestic ethanol producers.

Competition from Alternative Fuel Additives

     Alternative fuels, gasoline oxygenates and ethanol production methods are 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 ethanol. New ethanol products or methods of ethanol production developed by larger and better-financed competitors could provide them with competitive advantages and harm our business.

RISK FACTORS

Risks Related to Our Financing Plan

Present and future loan agreements with lenders may hinder our ability to operate the business by imposing restrictive loan covenants which could delay or prohibit us from making cash distributions to our unit holders.

     Our debt load and the service requirements necessary to implement our business plan will result in substantial debt service requirements. Our debt load and service requirements could have important consequences which could hinder our ability to operate, including our ability to:

	•		Incur additional indebtedness;
	•		Make capital expenditures or enter into lease arrangements in excess of prescribed thresholds;
	•		Make distributions to unit holders, or redeem or repurchase units;
	•		Meet operating expenses;
	•		Make certain types of investments;
	•		Create liens on our assets;
	•		Utilize the proceeds of assets sales; and
	•		Merge or consolidate or dispose of all, or substantially all, of our assets.

     In the event that we are unable to pay our debt service obligations, our creditors could force us to reduce or eliminate distributions to unit holders (even for tax purposes), or reduce or eliminate needed capital expenditures. It is possible that we could be forced to sell assets, seek to obtain additional equity or refinance or restructure all or a portion of our debt. In the event that we would be unable to refinance our indebtedness or raise funds through asset sales, sales of equity or otherwise, our ability to operate our plant would be greatly affected and we may be forced to liquidate.

Risks Related to Red Trail Energy, LLC as a Development-Stage Company

      Red Trail Energy, LLC has no operating history, which could result in errors in management and operations causing a reduction in the value of your investment.

     We were formed in July 2003 and have no history of operations. We cannot provide assurance that we can manage our plant construction effectively and properly staff operations when construction is completed, and any failure to manage these tasks effectively could delay the commencement of plant operations. A construction delay or delay in commencing operations will further delay our ability to generate revenue and satisfy our debt obligations. We anticipate a period of significant growth, involving the continuing construction and start-up of

operations of the plant. This period of growth and the start-up of the plant are likely to be a substantial challenge to us. If we fail to manage the start-up of the plant effectively, this could also delay our ability to generate revenue and satisfy our debt obligations.

We have little to no experience in the ethanol industry, which may affect our ability to build and operate the ethanol plant.

     We are presently, and are likely for some time to continue to be, dependent upon our founding members, some of whom also serve as our governors and executive officers. Most of these individuals are experienced in business generally but the majority have very little or no experience in organizing, building and operating an ethanol plant and governing and operating a public company. Many of our governors have no expertise in the ethanol industry. In addition, certain governors on our board are presently engaged in business and other activities which impose substantial demand on the time and attention of such governors.

We will depend on Fagen, Inc. for expertise in plant construction and any loss of this relationship could cause us delay and added expense, placing us at a competitive disadvantage.

     We will be dependent on our relationship with Fagen, Inc. and its employees. Any loss of this relationship with Fagen, Inc., particularly during the construction and start-up period for the plant, may prevent us from commencing operations and result in the failure of our business. The time and expense of locating new contractors would result in unforeseen expenses and delays. Unforeseen expenses and delays may reduce our ability to generate revenue and profitability and significantly damage our competitive position in the ethanol industry.

We will depend on GreenWay Consulting, LLC for expertise in the ethanol industry and operation of our plant and any loss of this relationship could cause us delay and added expense, placing us at a competitive disadvantage.

     We will be dependent on our relationship with GreenWay Consulting, LLC and its employees, one of whom serves as our General Manager. Any loss of this relationship with GreenWay Consulting, LLC, particularly during the construction and start-up period for the plant, may prevent us from commencing operations and may result in the failure of our business. The time and expense of locating new consultants would result in unforeseen expenses and delays. Unforeseen expenses and delays may reduce our ability to generate revenue and profitability and significantly damage our competitive position in the ethanol industry.

Our lack of business diversification could result in the devaluation of our units if our revenues from our primary products decrease.

     We expect our business to solely consist of ethanol and distillers grains production and sales. We will not have any other lines of business or other sources of revenue if we are unable to complete the construction and operation of the plant. Our lack of business diversification could cause you to lose all or some of your investment if we are unable to generate revenues through the production and sales of ethanol and distillers grains since we do not expect to have any other lines of business or alternative revenue sources.

We have a history of losses and may not ever operate profitably.

     For the period of July 16, 2003 (inception) through December 31, 2005, we incurred an accumulated net loss of approximately $2,434,000. We will continue to incur significant losses until we successfully complete construction and commence operations of the plant. There is no assurance that we will be successful in our efforts to build and operate an ethanol plant. Even if we successfully meet all of these objectives and begin operations at the ethanol plant, there is no assurance that we will be able to operate profitably.

Our business may suffer due to decisions made by our Board of Governors and, until the plant is built, your only recourse to replace these governors will be through amendment to our Member Control Agreement.

     Our Member Control Agreement provides that the initial Board of Governors will serve until the first annual or special meeting of the members following commencement of substantial operations of the ethanol plant. If our project suffers delays due to financing or construction, our initial Board of Governors could serve for an extended period of time. In that event, your only recourse to replace these governors would be through an amendment to our Member Control Agreement which could be difficult to accomplish.

Risks Related to Construction of the Ethanol Plant

We depend on Fagen, Inc. and ICM Inc. to continue building our ethanol plant and their failure to perform could force us to abandon business, hinder our ability to operate profitably or decrease the value of your investment.

     We are highly dependent upon Fagen, Inc. and ICM Inc. for their work related to the ongoing construction of our plant. Fagen, Inc. and ICM Inc. and their affiliates, may have a conflict of interest with us because Fagen, Inc., ICM Inc. and their employees or agents are involved as owners, creditors and in other capacities with other ethanol plants in the United States. We cannot require Fagen, Inc. or ICM Inc. to devote their full time attention to our activities. As a result, Fagen, Inc. and ICM Inc. may have, or come to have, a conflict of interest in allocating personnel, materials and other resources to our plant.

We may need to increase cost estimates for construction of the ethanol plant, and such increase could result in devaluation of our units if plant construction requires additional capital.

     We anticipate that Fagen, Inc. will construct the plant for a contract price, based on the plans and specifications in the lump sum design-build agreement. We have based our capital needs on a design for the plant that will cost approximately $76,000,000 with additional start-up and development costs of approximately $23,000,000 for a total project completion cost of approximately $99,000,000. This price includes construction period interest. There is no assurance that the final cost of the plant will not be higher. There is no assurance that there will not be design changes or cost overruns associated with the construction of the plant. The price of steel could affect the final cost of construction of the ethanol plant. Shortages of steel could affect the final completion date of the project. Rebuilding from the various hurricanes that have struck the gulf coast last fall has caused a shortage of cement and labor. A shortage in the supply of cement may increase the cost of cement or delay the construction of our plant. A shortage in labor can result in increased costs for the labor available or in an inability to find sufficient labor to complete our project, thereby delaying the construction of our plant. Advances and changes in technology may require changes to our current plans in order to remain competitive. Any significant increase in the estimated construction cost of the plant could delay our ability to generate revenues and reduce the value of your units because our revenue stream may not be able to adequately support the increased costs and expense attributable to increased construction costs and additional capital may be required in order to meet such costs.

Construction delays could result in devaluation of our units if our production and sale of ethanol and its co-products are similarly delayed.

     We currently expect our plant to be operating by November 2006, however, construction projects often involve delays in obtaining permits, construction delays due to weather conditions, or other events that delay the construction schedule. In addition, changes in political administrations at the federal, state or local level may result in policy changes towards ethanol or this project, which could cause construction and operation delays. If it takes longer to construct the plant than we anticipate, it would delay our ability to generate revenue and make it difficult for us to meet our debt service obligations. This could reduce the value of our business.

Defects in plant construction could hurt our business if our plant does not produce ethanol and its co-products as anticipated.

     There is no assurance that defects in materials and/or workmanship in the plant will not occur. Under the terms of the design-build agreement with Fagen, Inc., they have warranted that the material and equipment furnished to build the plant will be new, of good quality, and free from material defects in material or workmanship at the time of delivery. Though the design-build agreement requires Fagen, Inc. to correct all defects in material or workmanship for a period of one year after substantial completion of the plant, material defects in material or workmanship may still occur. Such defects could delay the commencement of operations of the plant or, if such defects are discovered after operations have commenced, this could cause us to halt or discontinue the plant’s operation. Halting or discontinuing plant operations could delay our ability to generate revenues and reduce the value of our units.

The plant site may have unknown environmental problems that could be expensive and time consuming to correct, which may delay or halt plant construction and delay our ability to generate revenue.

     Although a Phase I Environmental Review Assessment identified no issues, there can be no assurance that we will not encounter hazardous environmental conditions that may delay the construction of the plant. We do not believe that Fagen, Inc. would be responsible for any hazardous environmental conditions encountered at the plant site. Upon encountering a hazardous environmental condition, Fagen, Inc. may suspend work in the affected area. If we receive notice of a hazardous environmental condition, we may be required to correct the condition prior to continuing construction. The presence of a hazardous environmental condition will likely delay construction of the plant and may require significant expenditure of our resources to correct the condition. In addition, Fagen, Inc. is entitled to an adjustment in price and time of performance if it has been adversely affected by the hazardous environmental condition. If we encounter any hazardous environmental conditions during construction that require time or money to correct, such event could delay our ability to generate revenues.

Risks Related to our Business

Changes in the prices of corn, ethanol and distillers grains can be volatile and these changes will significantly impact our financial performance and the value of your investment.

     Our results of operations and financial condition will be significantly affected by the cost and supply of corn and by the selling price for ethanol and distillers grains. Changes in the price and supply of these commodities are subject to and determined by market forces over which we have no control. Higher corn prices will produce lower profit margins. If we experience a sustained price increase in the cost of corn, our profit margins may significantly decrease or be eliminated. In addition, the price of ethanol may decline in the future. If we experience a sustained price decreases in ethanol sales, our profit margins may decrease or be eliminated.

     Generally, higher corn prices will produce lower profit margins. This is especially true if market conditions do not allow us to pass through increased corn costs to our customers. There is no assurance that we will be able to pass through higher corn prices. 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.

     Our revenues will be exclusively dependent on the market prices for 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, the 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 reduce revenues.

     We believe that ethanol production is expanding rapidly at this time. 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.

We engage in hedging transactions and other price mitigation strategies that could harm our results.

     In an attempt to partially offset the effects of volatility of ethanol prices and corn costs, we may enter into contracts to supply a portion of our ethanol production or purchase a portion of our corn requirements on a forward basis and also engage in other hedging transactions involving exchange-traded futures and options contracts for corn from time to time. The price of unleaded gasoline also affects the price we may receive for our ethanol under indexed contracts. The financial statement impact of these activities will be dependent upon, among other things, the prices involved and our ability to sell sufficient products to use all of the corn for which we may have futures contracts. Hedging arrangements also will expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or

received by us. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. A hedge position is often settled in the same time frame as the physical commodity is either purchased (corn) or sold (ethanol). Hedging losses may be offset by a decreased cash price for corn and an increased cash price for ethanol. We can not assure you that we will not experience hedging losses in the future. We also intend to vary the amount of hedging or other price mitigation strategies we undertake, and we may choose not to engage in hedging transactions at all. As a result, our results of operations and financial position may be adversely affected by increases in the price of corn or decreases in the price of ethanol or unleaded gasoline.

Our ability to successfully operate is dependent on the availability of electricity at anticipated prices.

     Adequate electricity is critical to plant operations. Our existing agreement to obtain electricity is subject to price fluctuations based on market conditions over which we have no control. As a result, our ability to make a profit may decline.

Our ability to successfully operate is dependent on the availability of lignite coal as the primary fuel to operate our plant.

     We anticipate that the entire plant will consume approximately 133,000 tons of lignite coal per year or 375 tons per day. We have entered into a contract with General Industries, Inc. d/b/a Center Coal Company for the purchase and delivery of coal and ash removal. Despite that agreement, there is no assurance that General Industries will be able to deliver all of the coal we will need for our operations on a timely basis without disruptions. Any failures or disruptions in the delivery of coal will force us to either reduce or stop operations completely until we have obtained either a new supply of coal or an alternative energy supply, such as natural gas. Any disruption in our operations may result in a loss of revenue. In addition, we may be unable to find an alternative energy source sufficient to supply our operations or at prices that are acceptable.

We are subject to environmental regulations related to disposal of coal fly ash that may add additional costs to our operations.

     According to ICM, Inc., our plant is expected to produce approximately 37.5 tons of coal fly ash per day as a result of the burning process of the coal used to provide the power to our plant. We are required to dispose of this coal fly ash in a licensed disposal facility. Our coal delivery provider is required under the terms of the coal delivery contract to remove and dispose of all of our coal fly ash. In the event our coal provider is unable or unwilling to continue with this contract, we will have to seek alternative methods of disposing of the coal fly ash that our plant will produce, which we may be unable to find or find at an economically feasible cost.

     In addition, we believe that federal and state environmental regulations related to operating a coal fired plant may be increasing and that any increased regulatory compliance requirements may negatively impact our operations and profitability.

We will depend on others for sales of our products, which may place us at a competitive disadvantage and reduce profitability.

     We have contracted with Renewable Products Marketing Group, LLC to market all of the ethanol we plan to produce. We currently expect to do our own wet distillers grains marketing by selling locally to livestock markets in approximately the 50 miles surrounding our plant. We have contracted with Commodity Specialist Company to market all of the dry distillers grains we produce. As a result, we are dependent on our ethanol broker and our dry distillers grains broker. If either of the ethanol or distillers grains broker breaches their contract or does not have the ability, for financial or other reasons, to market all of the ethanol or distillers grains we produce, we will not have any readily available means to sell our products. Our lack of a sales force and reliance on third parties to sell and market our products may place us at a competitive disadvantage. Our failure to sell all of our ethanol and dry distillers grains may result in less income from sales, reducing our revenue stream.

Changes and advances in ethanol production technology could require us to incur costs to update our ethanol plant or could otherwise hinder our ability to compete in the ethanol industry or operate profitably.

     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.

We currently have a limited number of full-time employees and will face challenges to hiring qualified employees capable of implementing our plan of operations, which may hinder our ability to conduct our operations and reduce our ability to operate profitably.

     We currently employ only two full-time employees, both of whom are engaged in administrative functions. In order to implement our plan of operations and operate the plant, we will need to hire up to an additional 40 qualified employees. Some of these additional employees will need to be skilled in ethanol and distillers grains production technologies and we may have difficulty in identifying, hiring and retaining such employees. In addition, we need to identify, hire and retain supervisory, marketing and other management-level employees. We may have difficulty in doing so and this also may hinder our ability to operate.

Our executive officers and governors lack significant experience in financial accounting and preparation of reports under the Securities and Exchange Act of 1934, as amended (the “Exchange Act.”).

     None of our executive officers or governors has ever served as such with a company that is required to file reports under the Exchange Act as we will be required to do. As a result, we may not be able or qualified to efficiently and correctly deal with our financial accounting issues and preparation of the Exchange Act reports.

Risks Related to Ethanol Industry

Our business is not diversified.

     Our success depends largely upon our ability to operate our ethanol plant profitably. 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. Our business would also be significantly harmed if our ethanol plant could not operate at full capacity for any extended period of time.

Competition from the advancement of alternative fuels may lessen the demand for ethanol and negatively impact our profitability, which could reduce the value of your investment.

     Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing more efficient engines, hybrid engines and alternative clean power systems using fuel cells or clean burning gaseous fuels. Vehicle manufacturers are working to develop vehicles that are more fuel efficient and have reduced emissions using conventional gasoline. Vehicle manufacturers have developed and continue to work to improve hybrid technology, which powers vehicles by engines that utilize both electric and conventional gasoline fuel sources. In the future, the emerging fuel cell industry may offer 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.

Corn-based ethanol may compete with cellulose-based ethanol in the future, which could make it more difficult for us to produce ethanol on a cost-effective basis, which could reduce the value of your investment.

     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. Although current technology is not sufficiently efficient to be competitive, we believe that new conversion technologies are being developed that might be competitive with current production technologies sometime in the future. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. It may not be cost-effective to convert the ethanol plant we are proposing into a plant which will use cellulose-based biomass to produce ethanol. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue will be negatively impacted.

As domestic ethanol production continues to grow, ethanol supply may exceed demand causing ethanol prices to decline and the value of your investment to be reduced.

     The number of ethanol plants being developed and constructed in the United States continues to increase at a rapid pace. As these plants begin operations, we expect domestic ethanol production to significantly increase. 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. Declining ethanol prices will result in lower revenues and may reduce or eliminate profits.

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 than it contributes may affect the demand for ethanol, which could affect our ability to market our product.

     According to popular media, certain individuals believe that the use of ethanol will have a negative impact on 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 natural gas, 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.

Competition from ethanol imported from Caribbean basin countries may be a less expensive alternative to our ethanol, which would cause us to lose market share.

     A portion of the ethanol produced or processed in certain countries in Central America and the Caribbean region is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative. Large ethanol producers, such as Cargill, Inc. have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would convert ethanol into fuel-grade ethanol for shipment to the United States. Ethanol imported from Caribbean Basin countries may be a less expensive alternative to domestically produced ethanol. Competition from ethanol imported from Caribbean Basin countries may affect our ability to sell our ethanol profitably.

Competition from ethanol imported from Brazil may be a less expensive alternative to our ethanol, which would cause us to lose market share.

     Brazil is currently the world’s second largest producer and the largest exporter of ethanol. In Brazil, ethanol is produced primarily from sugarcane, which is also used to produce food-grade sugar. Brazil experienced a dramatic increase in ethanol production and trade in 2004 and 2005, exporting approximately 90 million gallons to the United States in 2004 and 65 million gallons to the United States in 2005 according to the U.S. International Trade Commission. Ethanol imported from Brazil may be a less expensive alternative to domestically produced ethanol, which is primarily made from corn, even though United States tariffs increase the price. United States oil refineries may increase imports of Brazilian ethanol in 2006 as MTBE use decreases in the United States and supply chain problems with domestic ethanol delivery are resolved. Tariffs presently protecting United States ethanol producers may be reduced or eliminated. Competition from ethanol imported from Brazil may affect our ability to sell our ethanol profitably.

Risks Related to Federal Regulation and Governmental Action

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.

     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 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 will begin at 4 billion gallons in 2006, increasing 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 result in the failure of our business.

     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 increases from 30 million to 60 million gallons. Because our plant will have a capacity to annually produce 50 million gallons of ethanol, we expect to qualify for this tax credit, but if this provision is changed in the future or if we exceed our expected production capacity by over 10 million gallons per year, the loss of this tax credit could harm the value of your investment. .

A change in environmental regulations or violations thereof could result in the devaluation of our units and a reduction in the value of your investment.

     We will be subject to extensive air, water and other environmental regulations and we will need to obtain a number of environmental permits to construct and operate the plant. We have received a number of North Dakota and federal environmental permits and we do not anticipate a problem receiving any additional required environmental permits for which we have filed applications. However, if for any reason any of these permits are not granted, construction costs for the plant may increase, or construction may be delayed.

     Because our plant will utilize lignite coal as its primary energy source, we are subject to a number of environmental regulations that require us to add scrubbers and other methods to reduce emissions from the burning of coal. If our safeguards fail or are ineffective, we might be subject to significant fines and penalties, including a shut-down of the plant to remedy these failures. Remedying any coal-based environmental problems may cost significant money and halt or reduce plant operations. Any significant fine or reduction in plant operations would harm our business.

     Additionally, environmental laws and regulations, both at the federal and state level, are subject to change and changes can be made retroactively. Consequently, even if we have the proper permits at the present time, we may be required to invest or spend considerable resources to comply with future environmental regulations or new or modified interpretations of those regulations, which may reduce our profitability.

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 the Company.

     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 “qualifying 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, if any, once we begin operations. 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 the Company’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 Statutes, Section 10-32-99, as amended from time to time, or as required or permitted by other provisions of law.

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.

     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 expect to qualify for North Dakota’s fuel tax incentive program. See Item 1. “Business” and Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operation.” Ethanol plants constructed after July 31, 2003 are eligible for these incentives. However, because the incentives are dependent upon future prices for ethanol and corn, we may not qualify for the incentives and such failure to qualify could reduce our net income.

North Dakota Income Tax Credit

     Our members may be eligible for a tax credit against North Dakota state income tax liability equal to 30% of the amount invested by the member in us. In order for our members to obtain this credit, we have to be a “qualified business” as defined in the North Dakota code section. See Item 1. “Business” and Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operation.” It is possible that we will not meet the requirements for being a “qualified business,” in which case members will not be eligible for the credit.

Risks Related to Conflicts of Interest

Our governors and executive officers 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 and executive officers 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. We have not adopted a board policy restricting such potential conflicts of interests at this time.

     In addition, our governors and executive officers have other management responsibilities and business interests apart from our project. 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 for 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. Our executive officers, when we begin operations, will be expected to devote significantly more time to our business, but we expect that GreenWay will provide most of our management expertise and work under the terms of their management contract with us. We currently have a board policy that generally requires the removal of any governor that fails to attend a certain number of meetings in a six-month period. Therefore, our governors and executive officers 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 the governors and executive officers, either individually or collectively, hold a substantial percentage of the units because of their position to substantially influence our business and management.

We may have conflicting interests with GreenWay Consulting, LLC which could cause GreenWay Consulting, LLC to put its interests ahead of ours.

     GreenWay Consulting, LLC has and continues to advise our governors and has been, and is expected to be, involved in substantially all material aspects of our formation, capital formation and operations. In addition, Mick Miller, our General Manager, is an employee of GreenWay Consulting, LLC. Consequently, the terms and conditions of any future agreements and understandings with GreenWay Consulting, LLC may not be as favorable to us as they could be if they were to be obtained from other third parties. We believe that our Development Services Agreement and Management Agreement were negotiated at arms-length and the terms and conditions of each are fair to us and consistent with the terms of such agreements in the industry. In addition, because of the extensive role that GreenWay Consulting, LLC has in the construction and operation of the plant, it may be difficult or impossible for us to enforce claims that we may have against GreenWay Consulting, LLC. Such conflicts of interest may reduce our profitability.

ITEM 2. FINANCIAL INFORMATION

SELECTED FINANCIAL INFORMATION

     The following tables set forth our selected historical financial and other information as of the dates and for the periods indicated.

     Our selected historical balance sheet information as of December 31, 2005, December 31, 2004, December 31, 2003 and the period from inception (July 16, 2003) to December 31, 2005 are derived from our audited balance sheets. Our selected historical statement of operations information for the fiscal years ended December 31, 2005, December 31, 2004, December 31, 2003 and the period from inception (July 16, 2003) to December 31, 2005 are derived from our audited statements of operations.

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

      Except for the historical information, this Form 10 Registration Statement contains forward-looking statements made pursuant to the safe harbor provisions of the Securities Exchange Act of 1934. Such statements consist of any statement other than a recitation of historical facts and can be identified by words such as “may,” “expect,” “anticipate,” “estimate,” “hopes,” “believes,” “continue,” “intends,” “seeks,” “contemplates,” “suggests,” “envisions” or the negative thereof or other variations thereon or comparable terminology. These forward-looking statements represent our expectations or beliefs concerning future events, including statements regarding future construction timetable, future sales, future profit percentages and other results of operations, the continuation of historical trends, the sufficiency of cash balances and cash generated from operating and financing activities for our future liquidity and capital resource needs, and the effects of any regulatory changes. We caution you that any forward-looking statements made in this registration statement or in other reports filed by us with the Securities and Exchange Commission (the “SEC”) are qualified by certain risks and other important factors that could cause actual results to differ materially from those in the forward-looking statements, including developments relating to the following:

	•		The availability and adequacy of our cash flow to meet its requirements, including payment of loans;
	•		Economic, competitive, demographic, business and other conditions in our local, regional and national markets;
	•		Changes or developments in laws, regulations or taxes in the ethanol, agricultural or energy industries;
	•		Actions taken or not taken by third parties, including our suppliers and competitors, as well as legislative, regulatory, judicial and other governmental authorities;
	•		Competition in the ethanol industry;
	•		The loss of any license or permit;
	•		The loss of our plant due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;
	•		Changes in our business strategy, capital to support capital improvements and development; and
	•		Other factors discussed under the section entitled “RISK FACTORS” or elsewhere in this document.

     You should read this document completely and with the understanding that actual future results may be materially different from what we expect. The forward-looking statements contained in this document have been compiled as of the date of this document and should be evaluated with consideration of any changes occurring after the date of this document. Except as required under federal securities laws and SEC rules and regulations, we will not update forward-looking statements even though our situation may change in the future.

Application of Critical Accounting Policies

     Accounting policies, methods and estimates are an integral part of our consolidated financial statements and are based upon management’s current judgments. Certain accounting policies, methods and estimates are particularly important because of their significance to the financial statements. Note 1 of the Notes to Financial Statements includes a summary of the accounting policies and methods we use. The following is a discussion of what we believe to be the most critical of these policies and methods.

Accounting Estimates

     We used estimates and assumptions in preparing our 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 and Equivalents

     We consider 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.

     We maintain our accounts at primarily three financial institutions. At times throughout the year, our cash and equivalents balances may exceed amounts insured by the Federal Deposit Insurance Corporation. At December 31, 2005, our deposits exceeded insurance coverage by approximately $18.9 million.

Property and Equipment

     Property and equipment is stated at the lower of cost or estimated fair value. Assets that are still undergoing development and have not been placed into service are shown on our balance sheet as construction in progress and are not depreciated. Once assets are placed in service, depreciation is provided over estimated useful lives by use of the straight-line method. Maintenance and repairs are expensed as incurred; major improvements and betterments are capitalized.

     We have incurred substantial consulting, permitting, and other pre-construction services related to building its plant facilities. Due to the substantial uncertainties regarding our ability to proceed with the ultimate facility construction until we had raised debt and equity financing, prior to 2005, we 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.

Deferred Offering Costs

     We defer the costs incurred to raise equity financing until the financing occurs. At such time as the issuance of new equity occurs, these costs will be netted against the proceeds received; or if the financing does not occur, they will be expensed.

Income Taxes

     We are treated as a partnership for federal and state income tax purposes and generally do not incur income taxes. Instead, our 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 the financial statements.

Organizational and Start Up Costs

     We expense all organizational and start up costs as incurred.

Derivative Instruments

     We have derivative instruments in the form of interest rate swaps in an agreement associated with bank financing. Market value adjustments and net settlements related to these agreements are charged to interest expense.

Results of Operations

     We are a development stage company with no operations, sales or revenues as of December 31, 2005. We intend to engage in the production and sale of fuel grade ethanol once our plant is operational, expected to be November 2006. We expect to be able to processed 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.

     The following table shows revenues, operating expenses and other items in our statements of income for the years ended December 31, 2005, 2004, 2003 and inception (July 16, 2003) to December 31, 2005:

      Revenues

     We had no sales or revenue for the fiscal years ended 2005, 2004, 2003 or for the period from inception (July 16, 2003) to December 31, 2005.

      Cost of Sales

     We had no costs of sales for the fiscal years ended 2005, 2004, 2003 or for the period from inception (July 16, 2003) to December 31, 2005.

      Operating Expenses

     Our operating expenses were approximately $2,087,800, $433,300, $420,100 and $2,941,300 for the years ended 2005, 2004, 2003 and for the period from inception (July 16, 2003) to December 31, 2005. Our operating expenses increased by approximately $1,654,500 or 382% for 2005 over 2004 and increased by approximately $13,200 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; 4) approximately $77,000 related to office and insurance expenses; and 5) approximately $70,000 related to financing fees related to our loan with First National Bank. In 2004, our material operating expenses were: 1) approximately $105,000 in payments to our project coordinator; 2) approximately $90,000 related to financing fees and accounting expenses; 3) approximately $78,000 for permitting activities; 4) approximately $46,000 related to marketing expenses; and 5) approximately $33,000 in consulting fees. In 2003, our material operating expenses were: 1) approximately $200,000 in consulting fees paid to GreenWay; 2) approximately $87,000 for permitting activities; 3) approximately $65,000 in consulting fees; and 4) approximately $52,000 in payments to our project coordinator. We believe that our operating expenses will increase significantly in 2006 as a result of the completion of our plant, expected in November 2006, the preparation and training for the commencement of operations, and the registration of the membership units with the Securities and Exchange Commission.

      Other Income, Net

     Interest expense was approximately $278,000, $0, $0, and $0 for 2005, 2004, 2003 and for the period from inception (July 16, 2003) to December 31, 2005. Interest expense increased due to the recognition of a derivative loss in connection with our interest rate swap contract which was entered into to effectively fix the interest rate of approximately $27,600,000 of our future debt. As of December 31, 2005, we had not drawn on any of our debt.

     Interest income was approximately $588,200, $47,000, $0 and $635,200 for the years ended 2005, 2004, 2003 and for the period from inception (July 16, 2003) to December 31, 2005. Interest income increased primarily due to interest earned on equity raised from member investments. We do not expect to receive any significant interest income in 2006.

     Grant income was approximately $50,000, $100,000, $0 and $150,000 for the years ended 2005, 2004, 2003 and for the period from inception (July 16, 2003) to December 31, 2005. Grant income relates to the grant we were rewarded from Ag Products Utilization Council in the amount of $150,000.

Plan of Operations Until Start-Up of Ethanol Plant

     We expect the project will cost approximately $99,000,000 to complete. This includes approximately $76,000,000 to build the plant and an additional $23,000,000 in other capital expenditures and working capital. We are still in the development and construction phase, and until the proposed ethanol plant is operational, we will generate no revenue. We anticipate that accumulated losses will continue to increase until the ethanol plant is operational.

     We expect to spend at least the next 12 months focused on plant construction and start-up operations. During this time, we expect to finalize the construction phase within budget, hire and train all plant personnel and operate the plant at the anticipated 50 million gallon per year production capacity efficiently. As of the date of this filing, we have already paid approximately $31,000,000 to Fagen, Inc. our construction company, related to the construction of our plant. We expect to spend approximately $45,000,000 in the next 12 months to complete construction.

      Project Capitalization

     Between September 2003 and January 2004, we raised $1,200,000 in our seed capital offering and an additional $36,717,724 from the sale of our units in a North Dakota-only registered offering from March 30, 2004 to March 1, 2006. In addition, on December 16, 2005, we closed on a construction loan agreement with First National Bank of Omaha of $59,712,000, which includes $55,211,740 for construction costs, a revolving line of credit of $3,500,000 and a Letter of Credit up to $1,000,000. We also closed on three subordinated debt agreements, one each with Fagen, GreenWay and ICM. The subordinated debt agreements are for up to $1,000,000, $1,525,000 and $3,000,000 respectively, and are subordinated in full to the construction loan agreement.

      Site Acquisition and Development

     On March 22, 2004, January 13, 2005 and July 11, 2005, we acquired a total of approximately 135 acres of land just east of Richardton, North Dakota as the site for our plant. We paid approximately $302,000 for the site. Plant construction commenced on the site in October 2005 in accordance with a Lump Sum Design-Build Agreement with Fagen, Inc

      Plant Construction and Start-Up of Plant Operations

     We expect to complete construction of the plant and commence operations in November 2006. We believe we have sufficient cash on hand to cover construction and related start-up costs necessary to make the plant operational. We estimate that we will need approximately $76,000,000 to construct the plant and a total of approximately $23,000,000 to cover all capital expenditures necessary to complete the project, make the plant operational and produce revenue.

Trends and Factors that May Affect Future Operating Results

      Ethanol Supports

     We expect to receive significant benefits from federal and state statutes, regulations and programs. The trend at the governmental level appears to be to continue to try to provide economic support to the ethanol industry. Notwithstanding the above, changes to federal and state statutes, regulations or programs could have an adverse effect on our business. Recent federal legislation, however, has benefited the ethanol industry. In 2005, the Energy Policy Act was passed which contained a new support program, the RFS, which requires fuel refiners to use a certain minimum amount of renewable fuels (including ethanol) which will rise to 7.5 billion gallons by 2012. The Energy Policy Act also provides a small producer credit allowing qualifying producers to deduct from their federal income taxes $0.10 per gallon for the first 15 million gallons of ethanol produced in a given year. The VEETC, which provides a volumetric ethanol excise tax credit of 5.1 cents per gallon of ethanol blended at 10%, also encourages refiners and gasoline blenders to use ethanol.

     Clean air standards mandated by federal agencies continue to require major population centers to blend ethanol into their gasoline supplies as an oxygenate, in order to reduce harmful emissions. These mandates have been challenged legally in certain metropolitan areas. We could be significantly and adversely impacted by an unsuccessful outcome in this litigation, or by the removal of or adverse changes to these standards.

      Competition and Product Demand

     Ethanol demand in the United States in 2005 was approximately equal to ethanol production in the United States in 2005 at 4.3 billion gallons, according to the RFA. Plans to construction new ethanol plants or expand existing plants have been announced which would increase ethanol production (if all plants and expansions are completed) to approximately 6.3 billion gallons.

     Ethanol demand is influenced primarily by its cost in relation to availability and cost of gasoline and other octane enhancing products, and also by availability of alternative oxygenates (where oxygenated fuels are required). The dramatic increase in gasoline prices in 2005 has increased demand for ethanol as a fuel extender, as the net cost of ethanol to blenders became less than unblended gasoline. With continued strong oil prices in 2006, and a corresponding increase in gasoline pricing, ethanol has become a much more competitive product in the marketplace. While a similarly dramatic decrease in the price of oil would have a negative effect on ethanol demand, such a decrease is not currently anticipated by most industry analysts. This increasing interest in ethanol could result in additional demand for ethanol and also additional production capacity being planned and built. The Renewable Fuels Association is predicting an additional two billion gallons of ethanol production in the next 14 months. This additional production will come both from new plants already under construction and existing plants that are currently expanding.

     Demand for ethanol may also 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. E85 is used as an aviation fuel and as a hydrogen source for fuel cells. In the United States, there are approximately 3 million flexible fuel vehicles capable of operating on E85 and 650 retail stations supplying it. Automakers have indicated plans to produce an estimated 2 million more flexible fuel vehicles per year.

     Negative publicity received by a competing oxygenate of ethanol, MTBE, in California and other states has also affected ethanol demand. Based on the discovery of MTBE in local water supplies, then California Governor Gray Davis issued an executive order in March of 1999 calling for the elimination of MTBE from California gasoline supplies by December 31, 2002. Other states have also legislated restrictions on the use of MTBE on the basis that the environmental risk of its use outweighs the air quality benefit. Under the provisions of the Federal 1990 Clean Air Act, gasoline used in certain air quality “non-attainment” areas must contain a certain oxygen content during the wintertime months of September through March. Ethanol and MTBE are the two most common oxygenates. When MTBE use is limited, ethanol demand and usage will be substantially increased. The east coast areas of New York and Connecticut began using ethanol blended gasoline as of January 1, 2005, thus further increasing demand. The continued enforcement of the oxygenate standard could have a significant positive impact on ethanol demand. The replacement of MTBE with ethanol in California, Connecticut and New York will require approximately 1.7 billion gallons of ethanol each year to be consumed in those areas.

     Nationally, there is also a movement to eliminate MTBE. In addition to individual states which have restricted its use, federal legislation (as discussed above) has been proposed which has focused on a compromise solution which would phase out MTBE, eliminate the oxygen requirement of the Clean Air Act, and replace it with a renewable fuels content requirement that gradually increases over the next several years. If this solution were adopted, we believe that it would significantly increase the demand for ethanol over this time period. In short, current law is favorable to ethanol in that it requires oxygenate blending. If MTBE usage is reduced and the law is not changed, or if the oxygen requirement is replaced with a similar “renewable fuels” requirement, the ethanol industry stands to see stronger demand. Conversely, the elimination of the oxygen requirement without adopting a renewable fuels requirement (or other similar incentive for ethanol blending) could have a significantly negative impact on both ethanol demand and pricing.

      Commodity Prices

      Corn

     Our primary grain feedstock will be corn. The cost of corn is dependent upon factors that are generally unrelated to those affecting the price of ethanol. Corn prices generally vary with international and regional grain supplies, and can be significantly affected by weather, planting and carryout projections, government programs, exports, and other international and regional market conditions.

     Due to the significant expansion of the ethanol industry, corn futures have recently started to respond to this new demand. This trend is likely to continue but certainly is not the only factor. Factors such as USDA estimates of acres planted, corn yield increases per acre, export demand and domestic usage also have significant effects on the corn market. Ultimately, weather has and will probably continue to weigh the heaviest on the corn market. Current USDA estimates show a two billion bushel excess supply of corn from 2005. This large amount of excess corn should help limit the volatility of, and increases in, corn prices well into the 2006 spring planting season. Then other factors such as acres planted and weather could start to have more of an impact and lead to potentially volatile and higher corn prices.

      Coal

     Lignite coal is also an important input commodity to our manufacturing process. We estimate that our lignite coal usage will be approximately 3.5% of our annual total production cost. We will use lignite coal to produce ethanol and to dry our distillers grains products to moisture contents at which they can be stored for long periods of time, and can be transported greater distances.

     We expect to purchase coal from Western North Dakota. In 2004, according to the United States Energy Information Agency, North Dakota produced 29,943,000 tons of lignite and 30,775,000 tons in 2003. Coal supply is not expected to be a problem, as North Dakota and reserves in the Unites States are plentiful and expected to last, even with increased demand, for greater than the expected lifespan of our plant. Coal availability is subject to various factors including demand from United States and international customers, governmental regulation and environment and safety issues.

     Recently, the price of lignite 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 lignite coal markets. Any ongoing increases in the price of lignite coal will increase our cost of production and may negatively impact our future profit margins.

Liquidity and Capital Resources

      Overview

     As of December 31, 2005, we had total assets of approximately $36,972,600 consisting primarily of cash and equivalents and construction in progress. As of December 31, 2005, we had current liabilities of approximately $8,258,900 consisting primarily of accounts payable related to the construction of the plant. Total members’ equity as of December 31, 2005, was approximately $28,713,700 consisting primarily of member contributions, net of accumulated losses. Since our inception, we have generated no revenue from operations. From our inception to

December 31, 2005, we have an accumulated net loss of approximately $2,434,100 consisting primarily of start-up business costs.

     As of December 31, 2005, we had material commitments related to our construction agreement with Fagen in the amount of approximately $76,000,000 and remaining material commitments related to our consulting agreement with GreenWay in the amount of approximately $1,550,000. As of December 31, 2005, we paid approximately $9,257,000 to Fagen from the proceeds from our equity financings. Based on 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 construction is completed and payment of the remaining amounts to GreenWay so that we can fund our operations and service our debt until such time as we receive revenues from sales of our ethanol and co-products.

     As of the date hereof, we have expended all funds from our equity financings. All of these proceeds were devoted to our construction expenses and general operating expenses. Current and remaining operating expenses, including all remaining construction costs will be paid for with the proceeds from our loan agreements

      Recent unregistered sales of securities

     Based on our business plan and current construction cost estimates, we believe the total project will cost approximately $99,000,000. We raised $1,200,000 in our seed capital offering and approximately an additional $36,714,700 from our North Dakota only offering. Between September 2003 and January 2004, we received the proceeds from our seed capital offering and between March 2004 and March 2006, we received the proceeds from our North Dakota only offering. In April 2004, we closed on the minimum offering amount and on March 2006, we closed the offering.

      Construction Loan Agreements

     In December 2005, we entered into a construction loan 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 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.

Construction Loan

     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 7.77% at December 31, 2005. The agreement calls for interest only payments to be made every three 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 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 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 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. There were no outstanding borrowings on the construction loan at December 31, 2005.

Revolving Line of Credit

     We entered into a $3,500,000 line of credit agreement with a bank, subject to certain borrowing base limitations, through December 2006. Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over LIBOR, which totaled 7.77% at December 31, 2005. There were no outstanding borrowings at December 31, 2005.

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 any 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 charged to interest expense. For the year ended December 31, 2005, there were no net settlements, and market value adjustments increased interest expense by approximately $278,000.

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. There is no set termination date for these letters of credit and their terms will be based on those requested by a specific supplier, although there will typically be a one year term with a renewal option. The construction loan agreement provides for us to pay a quarterly commitment fee of 2.25% of all outstanding letters of credit. At December 31, 2005, there were no outstanding letters of credit.

Subordinated Debt

     As part of the construction loan agreement, we 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 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. There were no amounts outstanding at December 31, 2005 as subordinated debt agreements are not in effect until amounts withdrawn on construction loan.

     To date we have spent approximately $31,000,000 in construction and related costs on the plant construction. We anticipate that capital expenditures for the remainder of 2006 will be approximately $45,000,000 to complete our plant. We do not anticipate any other material expenditures over the next year.

Grants

     We have been awarded a grant from Ag Products Utilization Council grant in the amount of $150,000 which was used in 2005 and 2004 for general business expenses, including legal and accounting. We also anticipate receiving a grant from the ND Lignite Council in the amount of $350,000. This grant would have provisions for 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.

      Fuel Tax Incentive Program

     We expect to 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 averages as calculated in number 1 and number 2 below:

      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.

     In addition, our investors may be eligible for a tax credit against North Dakota state income tax liability. 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. Under the code section, a “qualified business” is a business that:

	a.		Is incorporated or organized in North Dakota after December 31, 2000, for the primary purpose of processing and marketing agricultural commodities capable of being raised in North Dakota;
	b.		Has been certified by the North Dakota Securities Commissioner to be in compliance under the securities laws of North Dakota;
	c.		Has an agricultural commodity processing facility, or intends to locate one, in North Dakota; and
	d.		Is among the first 10 businesses that meet these requirements.

     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. We may not be able to meet the requirements of a through d above. If we don’t meet the requirements of a “qualified business,” you will not be eligible for a tax credit.

Off-Balance Sheet Arrangements

     We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future affect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contractual Obligations

     We have the following contractual obligations as of December 31, 2005:

Recent Accounting Pronouncements

     In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs – an amendment of ARB No. 43” (“FAS 151”), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. FAS No. 151 requires idle facility expenses, freight, handling costs, and

wasted material (spoilage) costs to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. FAS No. 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of FAS 151 will have no impact on the Company’s consolidated financial position, results of operations or cash flows.

     In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“FAS 154”). FAS 154 replaces APB Opinion No. 20, “Accounting Changes” and FAS No. 3 “Reporting Accounting Changes in Interim Financial Statements,” and changes the requirements for the accounting for and reporting of a change in accounting principle. FAS 154 may require restatement of prior period financial statements for certain changes in accounting principles. The retroactive application of a change in accounting principle should be limited to the direct effect of the change. Changes in depreciation, amortization or depletion methods should be accounted for as a change in accounting estimate. Corrections of accounting errors will be accounted for under the guidance contained in APB Opinion No. 20. The effective date of this new pronouncement is for fiscal years beginning after December 15, 2005 and prospective application is required. The Company does not expect the adoption of FAS 154 to have a material impact on its consolidated financial statements.

     We do not expect that the adoption of other recent accounting pronouncements will have a material impact on our financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our operations will be exposed to market risks primarily as a result of changes in interest rates and commodity prices. We do not intend to use derivative financial instruments for speculative or trading purposes.

      Interest Rate Risk

     We expect to be exposed to market risk from changes in interest rates when we begin to draw upon our existing debt facilities. While we have no outstanding debt as of December 31, 2005 or as of the date hereof, we expect that we will incur significant debt in the near future are construction on our plant proceeds and we need additional capital. Exposure to interest rate risk results from holding our credit agreements. The specifics of each credit agreement are discussed in greater detail in the “Liquidity and Capital Resources” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operation” in this document.

     We expect to use debt to finance a significant amount of our expenditures in 2006. These agreements will expose us to market risk related to changes in interest rates.

      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 and coal 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, 2005, we had no derivative instruments for

corn and 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 today, we have no cash, futures, and option contract price protection for our expected corn usage through December 31, 2006. Once we commence operations, we intend to contract for price protection for our corn usage. As corn 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 market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects but are expected to produce long-term positive growth for the Company.

     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, Renewable Products Marketing Group 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 Renewable Products Marketing Group to ensure that they are not over marketing our group’s ethanol volume by updating them continuously on the estimated startup date for our operation which is currently November 2006. 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 for the Company.

     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. The price of coal has risen substantially over the last several months and our strategy is to purchase coal based on our operating assumptions once the plant is operational..

ITEM 3. PROPERTIES

     The plant will be located just east of the city limits of Richardton, North Dakota, and just north and east of entrance/exit ramps to Highway I-94. The plant complex will be 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 will be perimeter roads, buildings, tanks and equipment. A small administration building and parking area will be located 400 feet from the plant complex and will 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.

     As of the date of this Form 10, our governors and executive officers own membership units, based on 40,373,970 membership units outstanding, as follows:

		Name of		Amount and Nature
Title of Class		Beneficial Owner		of Beneficial Owner				Percent of Class
Class A Membership Units		Ambrose Hoff			270,000	(1)				*
Class A Membership Units		William A. Price			805,000	(2)			1.99	%
Class A Membership Units		William DuToit			160,000	(3)				*
Class A Membership Units		Ron Aberle			372,920	(4)				*
Class A Membership Units		Mike Appert			1,020,000	(5)			2.53	%
Class A Membership Units		Jody Hoff			742,850	(6)			1.84	%
Class A Membership Units		Grant Hoovestol			526,650	(7)			1.30	%
Class A Membership Units		Troy Jangula			500,000	(8)			1.24	%
Class A Membership Units		Tim Gross			440,000	(9)			1.09	%
Class A Membership Units		William Cornatzer			350,000	(10)				*
Class A Membership Units		Kenny Meier			310,000	(11)				*
Class A Membership Units		Marlyn Richter			160,000	(12)				*
Class A Membership Units		Fred Braun			97,056	(13)				*
Class A Membership Units		Don Streifel			95,000	(14)				*
Class A Membership Units		Duane Zent			57,000	(15)				*
All executive officers and governors as a group (15 persons)				Total: 5,906,476				Total: 14.63		%

ITEM 5. GOVERNORS AND EXECUTIVE OFFICERS

     Our Member Control Agreement provides that our Board of Governors is comprised of at least seven members. Currently our Board consists of 15 Governors. At our first Annual Meeting of Members after the plant is operational, our Board size will be reduced to seven Governors. At such time, we will adopt a staggered board of governors, where two governors shall serve for one year, two governors shall serve for two years, and three governors shall serve for three years. The successors for each group of governors shall be elected for a three-year term and at that point. Each governor position is designated as either Group I (serving one year), Group II (serving two years) and Group III (serving three years). None of our governors or executive officers has any experience working with financial accounting and preparation of reports under the Exchange Act.

Identification of Governors, Executive Officers and Significant Employees

     The following table shows the governors and executive officers of Red Trail Energy, LLC as of the date of this Form 10:

Business Experience of Governors and Executive Officers

     The following is a brief description of the business experience and background of our executive officers and governors. Generally, our governors and executive officers have little experience in building, operating and managing an ethanol plant or in marketing, selling and distributing ethanol distillers grains. No company mentioned in these descriptions is publicly traded or required to file reports with the Securities and Exchange Commission.

Ambrose R. Hoff, President, Governor , Age 55, 2461 81 ^st Ave. SW Hebron, North Dakota 58638

     Mr. Hoff is the president of Stone Mill, Inc, a grain processing plant in Richardton, North Dakota. He is also currently the CEO of Amber Waves, Inc., a manufacturing facility in Richardton, North Dakota. Mr. Hoff is an active board member of the Richardton Development Company and served as president of the Richardton Business Association.

     Mr. Hoff has served as our President and as a Governor since our inception.

     Mr. Ambrose Hoff is the father of Mr. Jody Hoff.

William A. Price, Vice President, Governor , Age 43, 2273 River Road, Price, North Dakota, 58530.

     Since 1980, Mr. Price has been the managing partner of Price Cattle Ranch LLP, a cattle operation and the managing partner of Missouri River Feeders LLP, a feedlot and diversified farm, since 1997. He also serves as a governor of Quality Dairy Growers, LLC, a dairy operation and Sunnyside Properties, LLC, a custom feed plant. Mr. Price is a member of multiple associations, including the North Dakota Stockmen’s Association, the National Cattlemen’s Beef Association, the Great Bend Irrigation District, the North Dakota Farm Bureau and has served on the Missouri Slope Irrigation Board of Directors and served as Chairman of the North Dakota Feeder Council.

     Mr. Price has served as Vice President and as a Governor since our inception.

William N. DuToit, Treasurer, Governor , Age 64, 10775 Chokecherry Drive, Bismarck, North Dakota, 58503

     Mr. DuToit was the Branch President for Bremer Corporation of Saint Paul, Minnesota, a bank, from 1993 until 2004. Prior to Bremer Corporation of Saint Paul, Mr. DuToit was the Bank President of 64 MM Independent Bank.

     Mr. DuToit has served as Treasurer and as a Governor since our inception.

Ronald D. Aberle, Secretary, Governor , Age 43, 2300 158 ^th Street Northeast, Menoken, North Dakota, 58558

     Mr. Aberle is an owner and managing partner of a diversified farm and ranch, and most recently added an RV Campground to the enterprise. Mr. Aberle is a board member of the St. Hildegards Church.

     Mr. Aberle has served as a Governor since our inception and has served as Secretary since March 22, 2006.

Mike Appert, Governor , Age 37, 755 Highway 34, Hazelton, North Dakota, 58544

     Mr. Appert has been the owner and President of Appert Acres, Inc., a corn, soybean, sunflowers and small grains farming operation since 1991. In addition, Mr. Appert is the CFO of Appert Farms, Inc., a farming operation as well as operating a Mycogen Seeds Dealership. He also serves on several boards which include the South Central Grain as Secretary, the Hazelton Airport Authority as President, the Goose Lake Chapter Pheasants Forever as Treasurer and the Hazelton Lions Club.

     Mr. Appert served as Secretary until March 22, 2006 when he resigned his position to be appointed to our Audit Committee and has been a Governor since our inception.

Jody Hoff, Governor, Age 33, 8601 Highway 10 East, Richardton, North Dakota, 58652

     Mr. Hoff is a Mechanical Engineer, registered with the State of North Dakota and the State of Minnesota. Since 2002, he has been a partner, Vice President, Chief Engineer and Head of Operations of Amber Waves, Inc, a manufacturing company

     Mr. Hoff has served as a Governor since our inception and is a member of our Audit Committee.

     Mr. Jody Hoff is the son of Mr. Ambrose Hoff.

Grant Hoovestol, Governor , Age 45, 345 Cherry Court, West Fargo, North Dakota, 58078

     Mr. Hoovestol is an owner and operator of Great Plains Tower Properties, a property rental company in addition to owning and operating Autotronics Unlimited and rental property in North Dakota.

     Mr. Hoovestol has served as a Governor since our inception.

Troy Jangula, Governor, Age 35, 702 Western Avenue, Hazelton, North Dakota, 58544

     Mr. Jangula is the owner and operator of Four Star Farm Service Inc. which is a custom farming and application business. In addition, he also operates a small grains and row crop farm in North Dakota.

     Mr. Jangula has served as a Governor since our inception.

Tim Gross, Governor , Age 49, 6331 26 ^th Ave Southeast, Kintyre, North Dakota, 58549

     Mr. Gross operates a small grains, corn and sunflowers farm. In addition to his farming background, Mr. Gross was the President of Gross Construction Company from 1978 to 2001.

     Mr. Gross has served as a Governor since our inception.

William E. Cornatzer, M.D., Governor , Age 50, 400 Restful Dr., Bismarck, North Dakota, 58503

     Dr. Cornatzer has been a practicing physician in Bismarck and Dickinson, North Dakota since 1985. In addition, he owns farms in Oliver County and Burleigh County, North Dakota.

     Dr. Cornatzer has served as a Governor since our inception.

Kenny Meier, Governor , Age 45, 3511 Highway Three, Steele, North Dakota, 58482

     Mr. Meier has been the owner and operator of Meier Farms since 1980 and is a heavy equipment machine operator. He is a board member of his church and serves on the North Dakota Soybean Council.

     Mr. Meier has served as a Governor since our inception.

Marlyn Richter, Governor , Age 46, 14251 76 ^th Avenue Southeast, Menoken, North Dakota, 58558

     Mr. Richter has been the third-generation owner, operator and General Manager of Richter Farms, LLP, a combination dairy, feedlot, ranching and farming enterprise since 1997. In addition, Mr. Richter is a supervisor of the Burleigh County Soil Conservation District and serves on the Telfer Township Board and Telfer/Boyd/Missouri Zoning Board.

Mr. Richter has served as a Governor since our inception .

Fred J. Braun, Governor , Age 55, P.O. Box 1, Richardton, North Dakota, 58652

     Mr. Braun was the Postmaster for the United States Postal Service from 1978 to 2005 and is currently the Chairman of the Richardton Volunteer Fire Department with a service record of eleven years with the fire department.

     Mr. Braun has served as a Governor since our inception and is a member of our Audit Committee.

Donald Streifel, Governor , Age 61, 1076 B Highway 83 Southwest, Washburn, North Dakota, 58577

     Mr. Streifel is a self-employed farmer, who has operated a small grains, wheat, corn, soybeans and pinto bean farm since 1977. He has also operated the Painted Woods Insurance Agency since 1984 and worked for the Farmers Home Administration as a County Supervisor, the NDSU Extension Service, the Bank of North Dakota and on numerous boards including the Rural Fire Department, the McLean County Crop Improvement District, and his School Board, Church Council and Park Board.

     Mr. Streifel has served as a Governor since our inception.

Duane Zent, Governor , Age 47, 9077 50 ^th Street Southwest, Lefor, North Dakota, 58641

     Mr. Zent operates a small grain, corn and cow-calf operation near Lefor, North Dakota. In addition to farming, Mr. Zent serves on several boards including the Stark County Farm Bureau, the South West Grain Advisory Board, the Richardton Public School Board, and the Richardton Community Development.

     Mr. Zent has served as a Governor since our inception.

AUDIT COMMITTEE

     We established an audit committee consisting of three independent board members, Jody Hoff, Fred Braun and Mike Appert. We do not have a financial expert on our board or audit committees. We are not required to have an audit committee because we are not a listed issuer as defined in Rule 10A-3 under the Securities Exchange Act of 1934.

Significant Consultants

     We have entered into agreements with GreenWay Consulting, LLC (“GreenWay”) to manage our start-up and construction, as well as to provide management services once our plant is operational. Pursuant to the Development Services Agreement dated December 17, 2003, GreenWay manages our project development, plant construction and initial plant operations through startup, for a total price of $3,050,000. Pursuant to the Management Agreement dated December 17, 2003, upon commencement of operation of the plant, GreenWay will provide us with operations management, including a general manager and a plant manager, at our plant for $200,000 per year, plus reimbursement of these manager’s salaries and benefits, expected to exceed $100,000 per year. In addition, we are obligated to pay GreenWay 4% of our pre-tax 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 will begin in June 2006. There is a five-year term for the Management Agreement.

ITEM 6. EXECUTIVE COMPENSATION

     Ambrose Hoff is out Chief Executive Officer and has not received any compensation since inception. We do not expect to compensate Mr. Hoff for his work.

     We do not have any compensation arrangements with our governors and executive officers.

ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Since our inception, we have engaged in transactions with related parties. Such transactions included the purchase of 3,600,000 membership units by our governors at inception for a total of $1,200,000 or .33 per unit. Some of these original governors have since resigned. Conflicts of interest may arise in the future as a result of the relationships between and among our members, executive officers, governors and their affiliates, although our executive officers and governors have fiduciary duties to us. We did not have a committee of independent governors or members or an otherwise disinterested body to consider these transactions or arrangements that could have resulted from conflicts of interest. We expect our Audit Committee to consider these transactions in the future. Our Member Control Agreement permits us to enter into agreements with governors, executive officers, members and their affiliates, provided that any such transactions are on terms no more favorable to the governors, executive officers, members or their affiliates than generally afforded to non-affiliated parties in a similar transaction. A majority of our governors who are disinterested in such a transaction must approve the transaction and, acting as fiduciaries, conclude that it is in our best interest.

     In September 2003, we granted our then project coordinator an option to purchase a total of 62,500 units from us as part of completion of his duties as Project Coordinator. In January 2006, he purchased these units at $.10 per unit, for total consideration of $6,250.00

ITEM 8. LEGAL PROCEEDINGS

     The Company is not subject to any material legal proceedings or claims.

ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S
COMMON EQUITY AND OTHER MEMBER MATTERS

Market Information

     There is no established trading market for our membership units. To maintain our partnership tax status, members may not trade their membership units on an established securities market or readily trade the membership units on a secondary market (or the substantial equivalent thereof). All transfers are subject to a determination that the transfer will not cause us to be deemed a publicly traded partnership.

     We have restricted the ability of our members to transfer their membership units in our Member Control Agreement. To help ensure that a secondary market does not develop, our Member Control Agreement prohibits transfers without the approval of our Board of Governors. The Board of Governors will not approve transfers unless they fall within “safe harbors” contained in the publicly traded partnership rules under the Internal Revenue Code and the related rules and regulations, as amended (the “Tax Code”), which include: (a) transfers by gift, (b) transfer upon death of a member, (c) transfers between certain family members, and (d) transfers that comply with the “qualifying matching service” requirements. Any transfers of membership units in violation of the publicly traded partnership rules or without the prior consent of the board will be invalid.

     Under the Tax Code, a matching service is qualified only if it meets a number of specified requirements, including a requirement that the service only displays quotes that do not commit any person to buy or sell an interest at the quoted price (non-firm price quotes) or quotes that express an interest in acquiring an interest without an accompanying price (nonbinding indications of interest) and does not display quotes at which any person is committed to buy or sell an interest at the quoted price (firm quotes). The Tax Code also imposes restrictions on the timing of entering into binding agreements for the sale of membership units and the closing of the sale of such units, and further requires that the sum of the percentage interests transferred during the entity’s tax year (excluding private transfers) cannot exceed 10% of the total interests in partnership capital or profits. We are currently examining whether to adopt such a matching service, but we have made no final decision.

     There are no outstanding warrants or options to purchase, or securities convertible into, our membership units. As of May 23, 2006, there are 40,373,970 membership units that are eligible for sale pursuant to Rule 144, however, our Board of Governors has adopted a policy to restrict the transfer of our membership units for twelve months beginning March 2006 and North Dakota has restricted transfer of the units sold in the North Dakota registered offering for nine months from the date of the last sale in North Dakota, which was March 2006. We have not agreed to register any membership units under the Securities Act for sale by members or that is being, or has been publicly proposed to be, publicly offered by us.

Holders

     As of December 31, 2005, there were approximately 736 unit holders of the Company’s membership units determined by an examination of the Company’s transfer book. As of May 23, 2006, there were 792 unit holders of the Company’s membership units determined by an examination of the Company’s transfer book.

Distributions

     As of December 31, 2005, we had not made any distributions and we do not anticipate doing so until the plant is operational and generating profit and is able to do so pursuant to the terms of our construction loan agreement.

     We will make a public announcement of any distribution to members which have been approved by our Board of Governors within the 60-day period prior to the commencement of the calendar trimester in which the record date for the distribution would occur. The calendar trimester commencement dates are December 1, April 1, and September 1, and the announcement by us would include both the future record date for the distribution and the amount per membership unit of such distribution.

     Our senior lender, First National Bank of Omaha, N.A., (“First National Bank”) must approve any distributions as required under our loan agreements with First National Bank.

     Any 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. The Board of Governors has no obligation to distribute profits, if any, to members, and there can be no assurance as to our ability to declare or pay distributions in the future. In addition, the terms of the permanent debt financing agreements we entered into with First National Bank place certain restrictions on our ability to makes distributions.

Securities Authorized for Issuance under Equity Compensation Plans

     We currently have no equity compensation plan. On September 2003 we issued an option to purchase 62,500 membership units to Frank Kirschenheiter in connection with his work as out project coordinator at $.10 per unit exercise price. On January 9, 2006, Mr. Kirschenheiter exercised the option in full and received 62,500 membership units. This plan was approved by the Board of Governors, but not by the members. There is no registration rights agreement related to these units and we do not intend to register them in the future.

Purchases of Equity Securities by Red Trail Energy

     None.

ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES

     Between September 2003 and December 2003, we sold 1,200,000 Class A Membership Units to our seed capital investors at a price of $1.00 per unit and received aggregate proceeds of $1,200,000, including subscriptions paid in January 2004. During January 2004, we conducted a three for one unit split and issued an additional 2,400,000 Class A Membership Units to our seed capital investors. In 2004 and 2005, we sold 29,998,266 Class A Membership Units to 736 investors at a price of $1.00 per unit and received aggregate proceeds of $29,998,266. From January 2006 until we closed the North Dakota only offering on March 1, 2006, we raised an additional $6,719,458 from the sale of our Class A Membership Units to 56 investors at a price of $1.00 per unit. We claimed exemption from federal registration with respect to our Class A Membership Unit sales due to the application of Section 3(a)(11) of the Securities Act of 1933 (regarding intra-state offerings), and state registration due to application of North Dakota Century Code Chapter 10-04. On January 09, 2006, we received $6,250 from Frank Kirschenheiter when he exercised an option granted to him on August 1, 2003 in connection with his work done as a project coordinator and we issued to Mr. Kirschenheiter 62,500 Class A Membership Units. The issuance of the Units was based on a Rule 701 federal exemption from registration. Between our seed capital round, the North Dakota only offering and the option exercise, we sold 40,380,224 Class A Membership Units to 792 investors. The recipients of securities in each such transaction represented their intention to acquire the securities for investment only and not with a view to, or for sale in connection with, any distribution thereof, and appropriate legends were affixed to unit certificates and instruments issued in such transactions. All recipients had adequate access, through their relationships with us, to information about us. We used the proceeds from the sales of these securities to finance our start-up activities.

ITEM 11. DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED

     We elected to organize as a limited liability company rather than a corporation because we wish to qualify for partnership tax treatment for federal and state income tax purposes with our earnings or losses passing through to our members and subject to taxation at the member level. As a unit holder and a member of the limited liability company, an investor will be entitled to certain economic rights, such as the right to the distributions that accompany the units and to certain other rights, such as the right to vote at our member meetings. In the event that an investor’s membership in the limited liability company later terminates, that investor may continue to own units and retain economic rights such as the right to the distributions. However, termination of the membership would result in the loss of other rights such as the right to vote at our member meetings. At formation we elected a period of perpetual duration.

Membership Units

     Ownership rights in us are evidenced by units. There is one class of membership units in Red Trail Energy, LLC and that is Class A Membership Units. Each unit represents a pro rata ownership interest in our capital, profits, losses and distributions. Unit holders have the right to vote and participate in our management as provided in the Member Control Agreement. We maintain a membership register at our principal office setting forth the name, address, capital contribution and number of units held by each member.

Restrictive Legend on Membership Certificate

     We have placed and will continue to place restrictive legends on your membership certificate or any other document evidencing ownership of our units. The language of the legend will be similar to the following:

THE TRANSFERABILITY OF THE UNITS REPRESENTED BY THIS CERTIFICATE IS RESTRICTED. SUCH UNITS MAY NOT BE SOLD, ASSIGNED, OR TRANSFERRED, NOR WILL ANY ASSIGNEE, VENDEE, TRANSFEREE OR ENDORSEE THEREOF BE RECOGNIZED AS HAVING ACQUIRED ANY SUCH UNITS FOR ANY PURPOSES, UNLESS AND TO THE EXTENT SUCH SALE, TRANSFER, HYPOTHECATION OR ASSIGNMENT IS PERMITTED BY, AND IS COMPLETED IN STRICT ACCORDANCE WITH, THE APPLICABLE STATE AND FEDERAL LAW AND THE TERMS AND CONDITIONS SET FORTH IN THE MEMBER CONTROL AGREEMENT.

THE SECURITIES REPRESENTED BY THIS CERTIFICATE MAY NOT BE SOLD, OFFERED FOR SALE OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION UNDER THE SECURITIES ACT OF 1933, AS AMENDED, AND UNDER APPLICABLE STATE SECURITIES LAWS, OR AN OPINION OF COUNSEL SATISFACTORY TO THE COMPANY THAT SUCH TRANSACTION IS EXEMPT FROM REGISTRATION UNDER THE SECURITIES ACT OF 1933, AS AMENDED, AND UNDER APPLICABLE STATE SECURITIES LAWS.

Voting Limitations

     Each member is entitled to one vote per unit owned. Members may vote units in person or by proxy at a meeting of the unit holders, on all matters coming before a member vote. Members have cumulative voting rights, which means they may vote all or a portion of the units for less than all of the Board of Governor’s candidates. As a result, members owning a minority of the outstanding membership units may be able to elect board members by voting all of the units for one governor candidate. Members do not have preemptive rights.

     Our Member Control Agreement provides that our Board of Governors is comprised of at least seven members. Currently our Board consists of 15 Governors. Our governors and members have the right to call a special meeting of the members for certain purposes, including electing governors. At our first Annual Meeting of Members after the plant is operational, our Board size will be reduced to seven Governors if it has not already been reduced to seven members. At such time, we will adopt a staggered board of governors, where two governors shall serve for one year, two governors shall serve for two years, and three governors shall serve for three years. The successors for each group of governors shall be elected for a three-year term and at that point, one-third of the total number of governors will be elected by the members each year. Each governor position is designated as either Group I (serving one year), Group II (serving two years) and Group III (serving three years).

Loss of Membership Rights

     Although we are managed by our governors, our Member Control Agreement provides that certain transactions, such as amending our Member Control Agreement or dissolving the company, require member approval. An investor in us is both a holder of units and a member of the limited liability company at the time of acceptance of the investment. Each member has the following rights:

	•		To receive a share of our profits and losses;
	•		To receive distributions of our assets, if and when declared by our governors;
	•		To participate in the distribution of our assets in the event we are dissolved or liquidated;
	•		To access information concerning our business and affairs at our place of business; and

•

To vote on matters coming before a vote of the members.

     If you transfer your units, and the transfer is permitted by the Member Control Agreement, or has been approved by the Board of Governors, then the transferee will be admitted as a substituted member of Red Trail Energy, LLC only if the transferee:

	•		Agrees to be bound by our Member Control Agreement;
	•		Provides Red Trail Energy, LLC with an opinion of counsel that the transfer will not violate any securities laws;
	•		Delivers, upon our request, any evidence of the authority such person or entity has to become a member of Red Trail Energy, LLC; and
	•		Delivers, upon our request, any other materials needed to complete transferee’s transfer.

     The Board of Governors, in its discretion, may prohibit the transferee from becoming a member if he or she does not comply with these requirements. The restrictive legend on our membership certificates and the language of our Member Control Agreement will alert subsequent transferees of our units as to the restrictions on transferability of our units and the events by which a member may lose membership rights.

Distributions

     Distributions are payable at the 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. Our board has no obligation to distribute profits, if any, to members. We have not declared or paid any distributions on our units.

     Unit holders are entitled to receive distributions of cash or property if and when a distribution is declared by our governors. Distributions will be made to investors in proportion to the number of units investors own as compared to all of our units that are then issued and outstanding. Our governors have the sole authority to authorize distributions based on available cash (after payment of expenses and resources), however, we will attempt to distribute an amount approximating the additional federal and state income tax attributable to investors as a result of profits allocated to investors.

     We do not expect to generate revenues until the proposed plant is operational. After operations of the proposed plant begin, subject to any loan covenants or restrictions with our senior and subordinated lenders, we anticipate distributing a portion of our net cash flow to our members in proportion to the units held and in accordance with our Member Control Agreement. By net cash flow, we mean our gross cash proceeds received less any portion, as determined by our Board of Governors in their sole discretion, used to pay or establish reserves for our expenses, debt payments, capital improvements, replacements and contingencies. Our board may elect to retain future profits to provide operational financing for the plant, debt retirement and possible plant expansion.

     We do not know the amount of cash that we will generate, if any, once we begin operations. At the start, we will generate no revenues and do not expect to generate any operating revenue until the proposed plant is operating fully. Cash distributions are not assured, and we may never be in a position to make distributions. Whether we will be able to generate sufficient cash flow from our business to make distributions to members will depend on numerous factors, including:

	•		Successful and timely completion of construction since we will not generate any revenue until our plant is constructed and operational;
	•		Required principal and interest payments on any debt and compliance with applicable loan covenants which will reduce the amount of cash available for distributions;
	•		Our ability to operate our plant at full capacity, which directly impacts our revenues;

	•		Adjustments and amounts of cash set aside for reserves and unforeseen expenses; and
	•		State and federal regulations and subsidies, and support for ethanol generally, which can impact our profitability and the cash available for distributions.

Capital Accounts and Contributions

     The purchase price paid for our units constitutes a capital contribution for purposes of becoming a unit holder and will be credited to your capital account. As a unit holder, your capital account will be increased according to your share of our profits and other applicable items of income or gain specially allocated to you pursuant to the special allocation rules described below. In addition, we will increase your capital account for the amount of any of our liabilities that are assumed by you or are secured by any property which we distribute to you. We will decrease your capital account for your share of our losses and other applicable items of expenses or losses specially allocated to you pursuant to the special allocation rules described below. We will also decrease your capital account in an amount equal to the value of any property we distribute to you. In addition, we will decrease your capital account for the amount of any of your liabilities that are assumed by us or are secured by property you have contributed to us. In the event you transfer your units and we have approved such transfer, then your capital account, to the extent it relates to the units transferred, will be transferred to the transferee. Our Member Control Agreement does not require you to make additional capital contributions to us. Interest will not accrue on your capital contributions, and you have no right to withdraw or be repaid your capital contributions made to us.

     No member is liable, based solely on their ownership of our membership units, for capital calls or assessment or for liabilities of the Company.

Allocation of Profits and Losses

     Except as otherwise provided in the special allocation rules described below, profits and losses that we recognize will be allocated to you in proportion to the number of units you hold. Our profits and losses will be determined by our governors on either a daily, monthly, quarterly or other basis permitted under the Internal Revenue Code, as amended, and corresponding Treasury Regulations.

Special Allocation Rules

     The amount of profits and losses that we allocate to you is subject to a number of exceptions referred to as special allocations. These include special allocations required by the Internal Revenue Code, as amended, and Treasury Regulations aimed at highly leveraged limited liability companies that allocate taxable losses in excess of a unit holder’s actual capital contributions. Our Member Control Agreement also requires that our Board of Governors make offsetting special allocations in any manner they deem appropriate and that, after such offsetting allocations are made, each unit holder’s capital account balance is equal to the capital account balance that such unit holder would have had if special allocations required by the Internal Revenue Code, as amended, and Treasury Regulations were not made to such unit holder’s capital account.

Restrictions on Transfers of Units

     The units will be subject to certain restrictions on transfers pursuant to our Member Control Agreement. In addition, transfers of the units are restricted by federal and state securities laws. The state of North Dakota has placed substantial restrictions on the transfer of our membership units for nine months following the date of the closing of the North Dakota offering which took place on March 1, 2006. The Board of Governors has also adopted a policy to restrict the transfer of our membership units for 12 months from March 1, 2006.

     We have restricted the ability to transfer units to ensure that Red Trail Energy, LLC is not deemed a “publicly traded partnership” and thus taxed as a corporation. Under our Member Control Agreement, no transfer may occur without the approval of the Board of Governors. The Board of Governors will only permit transfers that fall within “safe harbors” contained in the publicly traded partnership rules under the Internal Revenue Code, as amended, to include the following:

	•		Transfers by gift;
	•		Transfers upon the death of a member;
	•		Transfers between certain family members; and

•

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

     Any transfer in violation of the publicly traded partnership requirements or our Member Control Agreement will be null and void. Furthermore, there is no public or other market for these securities. We do not anticipate such a market will develop.

     The units are unsecured equity interests in Red Trail Energy, LLC and are subordinate in right of payment to all of our current and future debt. In the event of our insolvency, liquidation, dissolution or other winding up of our affairs, all of our debts, including winding-up expenses, must be paid in full before any payment is made to the unit holders. There is no assurance that there would be any remaining funds for distribution to the unit holders, after the payment of all of our debts.

ITEM 12. INDEMNIFICATION OF GOVERNORS AND MANAGERS

     Under North Dakota law, no governor or manager will be liable for any of the Company’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 Statutes, Section 10-32-99, as amended from time to time, or as required or permitted by other provisions of law. We have obtained directors and executive officers liability and company coverage for the period April 1, 2006 to April 1, 2007 of $3,000,000 in the aggregate with a $25,000 deductible for an annual premium of $10,000.

ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     See “Item 15. Financial Statements and Exhibits.”

ITEM 14. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     Boulay, Heutmaker, Zibell & Co., P.L.L.P. is the Company’s independent auditor at the present time. The Company has had no disagreements with the reports issued by their auditors.

ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS

RED TRAIL ENERGY, LLC

C O N T E N T S

		Page
Report of Independent Registered Public Accounting Firm			1
Financial Statements
Balance Sheet			2
Statement of Operations			3
Statement of Changes in Members’ Equity			4
Statement of Cash Flows			5
Notes to Financial Statements			6-17

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

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

In our opinion, the 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, 2005 and 2004, and the results of its operations and its cash flows for the years ended December 31, 2005, 2004 and 2003 and for the period from inception (July 16, 2003) to December 31, 2005, in conformity with U.S. generally accepted accounting principles.

Certified Public Accountants

Minneapolis, Minnesota
April 25, 2006

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

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