UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

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

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

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

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

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

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

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

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

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

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

      Large accelerated filer o               Accelerated filer o                         Non-accelerated filer o                       Smaller reporting company þ

                                        (Do not check if a smaller reporting company)

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

The aggregate market value of the membership units held by non-affiliates of the registrant as of December 31, 2007 was $47,652,637. There is no established public trading market for our membership units. The aggregate market value was computed by reference to the average sales price of our Class A units recently traded on our Qualified Matching Service.

     As of March 31, 2008 the Company has 40,173,973 Class A Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s 2008 Proxy Statement are hereby incorporated by reference in Part III, Items 10, 11, 12, 13, and 14 of this report.

 

 

TABLE OF CONTENTS

		Page
PART I			2
ITEM 1. BUSINESS			2
ITEM 1A. RISK FACTORS			10
ITEM 2. PROPERTIES			16
ITEM 3. LEGAL PROCEEDINGS			16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			17
PART II			17
ITEM 5. MARKET FOR REGISTRANT’S MEMBER UNITS, RELATED MEMBER MATTERS AND ISSUER PURCHASED OF EQUITY SECURITIES			17
ITEM 6. SELECTED FINANCIAL DATA			18
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION			18
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			27
ITEM 9A. CONTROLS AND PROCEDURES.			27
ITEMS 9B. OTHER INFORMATION			28
PART III			28
PART IV			28
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			28
Third Amendment to Construction Loan Agreement
Fourth Amendment to Construction Loan Agreement
Interest Rate Swap Agreement
Member Ethanol Fuel Marketing Agreement
Contribution Agreement
Coal Sales Order
Distillers Grain Marketing Agreement
302 Certification of Chief Executive Officer
302 Certification of Chief Financial Officer
Section 906 Certification
Section 906 Certification

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “believes,” “continue,” “could,” “estimates,” “expects,” “future,” “hope,” “intends,” “may,” “plans,” “potential,” “predicts,” “should,” “target,” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within “Item 1A — Risk Factors.”

•		Projected growth, overcapacity or contraction in the ethanol market in which we operate;
•		Fluctuations in the price and market for ethanol and distillers grains;
•		Changes in plant production capacity, variations in actual ethanol and distillers grains production from expectations or technical difficulties in operating the plant;
•		Availability and costs of products and raw materials, particularly corn and coal;
•		Changes in our business strategy, capital improvements or development plans for expanding, maintaining or contracting our presence in the market in which we operate;
•		Costs of equipment;
•		Changes in interest rates and the availability of credit to support capital improvements, development, expansion and operations;
•		Our ability to market and our reliance on third parties to market our products;
•		Our ability to distinguish ourselves from our current and future competition;
•		Changes to infrastructure, including

	–		expansion of rail capacity,
	–		possible future use of ethanol dedicated pipelines for transportation
	–		increases in truck fleets capable of transporting ethanol within localized markets,
	–		additional storage facilities for ethanol, expansion of refining and blending facilities to handle ethanol,
	–		growth in service stations equipped to handle ethanol fuels, and
	–		growth in the fleet of flexible fuel vehicles capable of using E85 fuel;

•

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

–

national, state or local energy policy;

	–		federal ethanol tax incentives;
	–		legislation mandating the use of ethanol or other oxygenate additives;
	–		state and federal regulation restricting or banning the use of MTBE;
	–		environmental laws and regulations that apply to our plant operations and their enforcement; or
	–		reduction or elimination of tariffs on foreign ethanol.

•		Increased competition in the ethanol and oil industries;
•		Fluctuations in U.S. oil consumption and petroleum prices;
•		Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agriculture, oil or automobile industries;
•		Anticipated trends in our financial condition and results of operations;
•		The availability and adequacy of our cash flow to meet our requirements, including the repayment of debt;
•		Our liability resulting from litigation;
•		Our ability to retain key employees and maintain labor relations;
•		Changes and advances in ethanol production technology; and
•		Competition from alternative fuels and alternative fuel additives.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A — “Risk Factors.”

PART I

adjacent to our Plant. This project has also been approved by our lender, subject to our debt covenants. We anticipate that the project will be completed in the third quarter of 2008. We estimate that the project will cost approximately $2 million and save us an estimated $800,000 per year on our coal costs as we eliminate the additional trucking cost needed to get the coal to our site. We anticipate paying for this equipment with cash generated from operations.

During 2007, two significant but opposing trends affected ethanol prices. First, a significant amount of new ethanol production became available nationwide, which led to lower ethanol prices during the third quarter of 2007. Second, corn prices began to rise which, along with increased demand for ethanol, helped to raise ethanol prices. Overall, the demand trend raising prices outweighed the new ethanol trend depressing prices, leading to higher overall prices. Both of these trends appear to be continuing in 2008. The rising ethanol prices have thus far more than offset the increased cost of corn for our Plant but we cannot be certain about the future prices of these items as they are both market driven commodities. As corn and ethanol have started to vary more in price, we have taken a more active approach in risk management to attempt to protect our margins on at least a portion of our sales. We have formed a risk management committee (the “Risk Management Committee”) that consists of three of our Board members as well as our chief executive officer (“CEO”) and commodities manager. The Risk Management Committee, along with recommendations from outside consultants, sets the direction for our risk management strategies. As part of this strategy we have used corn options and futures contracts, as well as ethanol swaps. We believe our strategy has been successful to date, but there is no guarantee it will be successful in the future.

In an effort to diversify our revenue stream, we entered into an agreement in March 2008 to operate a third party’s corn oil extraction equipment that will be added to our facility. The agreement has a term of 10 years commencing from the date when the equipment installation is complete. We expect the equipment to be operating in 2009. In return for operating the equipment, we will receive a negotiated price per pound for the corn oil produced. The agreement contains guaranteed minimum pricing and yield provisions, as well as termination provisions in the event production does not meet agreed upon levels. Corn oil can be extracted from our process and marketed as a separate commodity. This process may have the effect of lowering the fat content of our distillers grains. We believe our distillers grains will still be within acceptable feed value and fat content limits as set forth in our distillers grains marketing agreement and that we will not lose revenue as a result of the changes in distillers grains quality. We expect the volume of our distillers grains sales to decrease by approximately three percent, on a dry matter basis, but that the decrease in revenue we believe will be more than offset by the corn oil sales. We anticipate the incremental cost of operating the equipment to be minimal.

We expect to fund the coal unloading facility capital project and our normal operations during the next 12 months using cash flow from our continuing operations and our credit facilities. Due to the nature of the corn oil extraction agreement, we do not expect to have any capital expenditures related to the installation of the corn oil extraction equipment.

Available Information

The public may read and copy materials we file with the Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street NE, Washington, D.C., 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Reports we file electronically with the SEC may be obtained at www.sec.gov .

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

Financial Information

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

Principal Products and Their Markets

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

Ethanol

Ethanol is ethyl alcohol, a fuel component made primarily from corn and other grains. Ethanol can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based gasoline substitute. Approximately 95% of all ethanol is used in its primary form for blending with unleaded gasoline and other fuel products. Used as a fuel oxygenate, ethanol provides a means to control carbon monoxide emissions in large metropolitan areas. The principal purchasers of ethanol are petroleum terminals in the continental United States. The Renewable Fuels Association (“RFA”) estimates annual domestic production capacity to be approximately 7.8 billion gallons as of January 2008.

For our fiscal year ended December 31, 2007, revenue from the sale of ethanol was approximately 88% of total revenues. We did not have any revenues prior to 2007.

Distillers Grains

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

For our fiscal year ended December 31, 2007, revenues from sale of distillers grains was approximately 12% of total revenues. We did not have any revenues prior to 2007.

Marketing and Distribution of Principal Products

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

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

Ethanol

We entered into a new marketing agreement on January 1, 2008 with RPMG for the purposes of marketing and distributing all of the ethanol we produce at the Plant. Prior to January 1, 2008 we had a marketing agreement in place with Renewable Products Marketing Group LLC. During 2007, that contract had been assigned to RPMG. The terms of the new agreement are not materially different than the prior agreement except as discussed below in relation to the fees paid to RPMG. Effective as of January 1, 2008, we also purchased an ownership interest in RPMG. Currently we own 8.33% of the outstanding capital stock of RPMG and anticipate our ownership interest to be reduced as other ethanol plants that utilize RPMG’s marketing services may become owners of RPMG. Our ownership interest in RPMG entitles us a seat on its board of directors which is filled by our CEO. The marketing agreement will be in effect as long as we continue to be a member in RPMG. We currently pay RPMG $.01 per gallon for each gallon RPMG sells, per the terms of the agreement. This fee will decrease to approximately $.005 per gallon once our ownership buy-in is complete, which we expect to occur during 2009.

Distillers Grains

We entered into a marketing agreement on March 10, 2008 with CHS for the purpose of marketing and selling our dried distillers grains. The marketing agreement has a term of six months which is automatically renewed at the end of the term. The agreement can be terminated by either party upon written notice to the other party at least thirty days prior to the end of the term of the agreement. Prior to March 2008 we had a marketing agreement with Commodity Specialists Company (“CSC”) which had assigned all rights, title and interest in the agreement to CHS. The terms of the new agreement are not materially different from the prior agreement. Under the terms of the agreement, we pay CHS a fee for marketing our distillers grains. The fee is 2% of the selling price of the distillers grain subject to a minimum of $1.50 per ton and a maximum of $2.15 per ton. Through the marketing of CHS and our relationships with local farmers, we are not dependent upon one or a limited number of customers for our distillers grains sales.

We market and sell our wet distillers grains internally. Substantially all of our sales of wet distillers grains are to local farmers and feed lots.

Dependence on One or a Few Major Customers

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

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

Seasonal Factors in Business

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

Financial Information about Geographic Areas

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

Sources and Availability of Raw Materials

Corn Feedstock Supply

During 2007, we were able to secure sufficient grain to operate the Plant and do not anticipate any problems securing enough corn during 2008. In January 2008, the United States Department of Agriculture’s 2007 Crop Production Summary listed national corn production at approximately 13.1 billion bushels, which is the largest corn crop on record. North Dakota produced 279 million bushels in 2007, also a record. However, we expect the number of acres of corn planted in North Dakota to decrease in 2008 primarily due to the higher prices of other commodities grown in our state, including wheat, sunflowers and soybeans. We also expect the demand for corn grown in our area to increase resulting from new ethanol plants in North Dakota projected to become operational in 2008. We expect that this increased demand will lead to greater competition for corn in our geographic area, which could push corn prices even higher. While our surrounding area produces a significant amount of corn, our profitability may be negatively impacted if long-term corn prices remain high or continue to increase.

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

Coal

Coal is also an important input to our manufacturing process. During the fiscal year ended December 31, 2007, we used approximately 97,000 tons of coal. During the startup period of January to April 2007, the Plant experienced a number of shutdowns as a result of issues related to lignite coal quality and delivery, as specified in our coal purchase agreement, along with the performance of our coal combustor while running on lignite coal. As a result of these issues, we terminated our lignite coal purchase and delivery contract and switched to powder river basin (“PRB”) coal as an alternative to lignite coal. Since making the change, the Plant has not experienced any shut-downs due to coal quality or delivery. We have entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2009. We have withheld $3.9 million from Fagen pending resolution of this issue with the coal combustor. As a long-term solution, we are working with Fagen and its subcontractors to find ways to modify the coal combustor so that we can continue using lignite coal. If we cannot modify the coal combustor to use lignite coal, we may have to use PRB coal instead of lignite coal as a long-term solution. Whether the Plant runs long-term on lignite or PRB coal, there can be no assurance that the coal we need will always be delivered as we need it, that we will receive the proper size or quality of coal or that our coal combustor will always work properly with lignite or PRB coal. Any disruption could either force us to reduce our operations or shut down the Plant, both of which would reduce our revenues.

We believe we could obtain alternative sources of PRB or lignite coal if necessary, though we could suffer delays in delivery and higher prices that could hurt our business and reduce our revenues and profits. We believe there is sufficient supply of coal from the PRB coal regions in Wyoming and Montana to meet our demand for PRB coal. We also believe there is sufficient supply of lignite coal in North Dakota to meet our demand for lignite coal. The table below shows information related to estimated coal reserves and production numbers for Wyoming, Montana and North Dakota.

Estimated Coal Reserves at 12-31-06 and Production for the 12 months ended September 30, 2007 (in thousands of tons)

If there is an interruption in the supply or quality of coal for any reason, we may be required to halt production. If production is halted for an extended period of time, it may have a material adverse affect on our operations, cash flows and financial performance.

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

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 electricity for any reason, such as supply, delivery or mechanical problems, we may be required to halt production. If production is halted for an extended period of time, it may have a material adverse affect on our operations, cash flows and financial performance.

Water

Water supply is also an important consideration. To meet the Plant’s full operating requirements for water, we have entered into a ten-year contract with Southwest Water Authority to purchase raw water. The contract originally required us to purchase a minimum of 200 million gallons of water per year. During our first year of operations we used significantly less water than anticipated and have amended the contract so the minimum purchase is 160 million gallons per year. Other terms of the contract remain unchanged. Our rate for water usage during fiscal year 2008 will be $2.49 per 1,000 gallons.

Federal Ethanol Supports

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

The most recent ethanol supports are contained in the Energy Independence and Security Act of 2007 (the “2007 Act”). Most notably, the 2007 Act accelerates and expands the renewable fuels standard (“RFS”). The RFS requires refiners, importers and blenders (the “Obligated Party,” or “Obligated Parties”) to show that a required volume of renewable fuel is used in the nation’s fuel supply. The RFS has been accelerated to 9 billion gallons in 2008 and will increase to 36 billion gallons (15 billion gallons from corn based ethanol) by 2022. While the 2007 Act may cause ethanol prices to increase in the short term due to additional demand, future supply could outweigh the future demand for ethanol. This would have a negative impact on our earnings.

On April 10, 2007, the EPA published final rules implementing the RFS program. The RFS program final rules became effective on September 1, 2007. Compliance with the RFS program will be shown through the acquisition of unique Renewable Identification Numbers (“RINs”). RINs are assigned by the producer to every batch of renewable fuel produced to show that a certain volume of renewable fuel was produced. Each Obligated Party is required to meet their own Renewable Volume Obligation. Obligated Parties must produce or acquire sufficient RINs to demonstrate achievement of their Renewable Volume Obligation.

Each RIN may only be counted once toward an Obligated Party’s Renewable Volume Obligation and must be used either in the calendar year in which the RINs were generated, or in the following calendar year. An Obligated Party may purchase RINs from third parties if it fails to produce the adequate RINs in the calendar year to meet its Renewable Volume Obligation. If the Obligated Party fails to satisfy is Renewable Volume Obligation in a calendar year, the Obligated Party may carry the deficit forward for one year. Such deficit will be added to the Obligated Party’s obligation for the subsequent year.

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

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

The two major oxygenates added to reformulated gasoline pursuant to these programs are Methyl Tertiary Butyl Ether (“MTBE”) and ethanol; however, MTBE has caused groundwater contamination and has been banned from use by many states. The Energy Policy Act of 2005 (the “2005 Act”) did not impose a national ban of MTBE but it also did not include liability protection for manufacturers of MTBE. The failure to

include liability protection for manufacturers of MTBE has resulted in refiners and blenders using ethanol as an oxygenate rather than MTBE to satisfy the reformulated gasoline oxygenate requirement. While this may create increased demand in the short-term, we do not expect this to have a long term impact on the demand for ethanol as the 2005 Act repeals the Federal Clean Air Act’s 2% oxygenate requirement for reformulated gasoline immediately in California and 270 days after enactment elsewhere. However, the 2005 Act did not repeal the 2.7% oxygenate requirement for carbon monoxide nonattainment areas which are required to use oxygenated fuels in the winter months. While we expect ethanol to be the oxygenate of choice in these areas, there is no assurance that ethanol will, in fact, be used.

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

The 2005 Act also expanded 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 2005 Act, the size limitation on the production capacity for small ethanol producers increased from 30 million to 60 million gallons. As a 50 MMGY ethanol producer, we expect to qualify for the small ethanol producer tax credit. The credit can be taken on the first 15 million gallons of production. The tax credit is capped at $1.5 million per year per producer. The small ethanol producer tax credit is set to expire December 31, 2010.

In addition, the 2005 Act created 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 fuels in which at least 85% of the volume consists of ethanol, natural gas, compressed natural gas, liquefied natural gas, liquefied petroleum gas, and hydrogen and any mixture of diesel fuel and biodiesel containing at least 20% biodiesel. The provision is effective for equipment placed in service after December 31, 2005 and before December 31, 2010. While it is unclear how this credit will affect the demand for ethanol in the short term, we expect it will help raise consumer awareness of alternative sources of fuel and could positively impact future demand for ethanol.

Other Factors Affecting Demand and Supply

In addition to government supports that encourage production and the use of ethanol, demand for ethanol may increase as a result of increased consumption of E85 fuel. E85 fuel is a blend of 70% to 85% ethanol and gasoline. According to the Energy Information Administration, E85 consumption is projected to increase from a national total of 11 million gallons in 2003 to 47 million gallons in 2025. The demand for E85 is largely driven by flexible fuel vehicle penetration of the United States vehicle fleet, the retail price of E85 compared to regular gasoline and the availability of E85 at retail stations. In the United States, there are about 6 million flexible fuel vehicles capable of operating on E85, and automakers have indicated plans to produce an estimated 2 million more flexible fuel vehicles per year. In addition, Ford and General Motors have national campaigns to promote ethanol and flexible fuel vehicles. Because flexible fuel vehicles can operate on both ethanol and gasoline, if the price of regular gasoline falls below E85, demand for E85 will decrease as well. In addition, gasoline stations offering E85 are relatively scarce. As of January 2008, some 1,400 of the country’s 170,000 gas stations offered E85 as an alternative to ordinary gasoline, according to the RFA. The 2005 Act established a tax credit of 30% for infrastructure and equipment to dispense E85. This tax credit became effective in 2006 and is expected to encourage more retailers to offer E85 as an alternative to regular gasoline. The tax credit, unless renewed, will expire December 31, 2010.

Consumer awareness may also have an impact on demand for ethanol. While we feel strongly that ethanol is a viable product that is an important piece of reducing our reliance on imported oil, not all consumers may agree. Recently there have been many news stories attributing negative economic and environmental impacts to the rise in ethanol production. These concerns have included ethanol production creating higher food prices, using excessive energy in the production process and consuming high quantities of water. While we believe that these perceptions are based on information that is not accurate, we cannot be assured that all consumers will share our views which may impact the overall demand for ethanol.

Our Competition

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

According to the RFA, the ethanol industry has grown to approximately 139 production facilities in the United States with current estimates of domestic ethanol production at approximately 6.5 billion gallons for the year ended December 31, 2007. As reported by the RFA, including our Plant, North Dakota currently has three ethanol plants in operation (Red Trail Energy, LLC, Blue Flint Ethanol, Inc., and Archer Daniels Midland (“ADM”)), with the capacity to produce approximately 123.5 gallons annually. In addition, there are two ethanol plants under construction in North Dakota, which will add over 200 million gallons of annual capacity, and we are aware of plans for at least three additional plants that will add at least 165 million gallons of annual capacity. There are also numerous other producer and privately owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. The largest ethanol producers include POET, ADM, Verasun Energy Corporation, Hawkeye Renewables, LLC, Abengoa Bioenergy Corp. and Aventine Renewable Energy, LLC, all of which are each capable of producing more ethanol than we expect to produce.

Competition from Alternative Ethanol Production Methods

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

Most ethanol is currently produced from corn and other raw grains, such as milo or sorghum - especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. Additionally, the enzymes used to produce cellulose-based ethanol have recently become less expensive. Although current technology is not sufficiently efficient to be competitive on a large scale, a 2005 report by the U.S. Department of Energy entitled “Outlook for Biomass Ethanol Production and Demand” indicates that new conversion technologies may be developed in the future. If an efficient method of collecting biomass for ethanol production and producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. We may not be able to cost-effectively convert the Plant into one that will use cellulose-based biomass to produce ethanol. As a result, it is possible we could be unable to produce ethanol as cost-effectively as cellulose-based producers.

Competition with Ethanol Imported from Other Countries

Ethanol production is also expanding internationally. Brazil has long been the world’s largest producer and exporter of ethanol; however, since 2005, United States ethanol production slightly exceeded Brazilian production. Ethanol is produced more cheaply in Brazil than in the United States because of the use of sugarcane, a less expensive raw material than corn. However, in 1980, Congress imposed a tariff on foreign produced ethanol to make it more expensive than domestic supplies derived from corn. This tariff was designed to protect the benefits of the federal tax subsidies for United States farmers, however, there is still a significant amount of ethanol imported into the United States from Brazil. The tariff is currently set to expire in December 2009. We do not know the extent to which the volume of imports would increase or the effect on United States prices for ethanol if the tariff is not renewed.

Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempted from this tariff under the Caribbean Basin Initiative. Under the terms of the Caribbean Basin Initiative, exports from member nations are capped at 7% of the total United States production from the previous year (with additional exemptions from ethanol produced from feedstock in the Caribbean region over the 7% limit). However, as total production in the United States grows, the amount of ethanol produced from the Caribbean region and sold in the United States will also grow, which could impact our ability to sell ethanol.

Competition from Alternative Fuels

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

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

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

Distillers Grains Competition

Ethanol plants in the Midwest produce the majority of distillers grains and primarily compete with other ethanol producers in the production and sales of distillers grains. According to the RFA, approximately 14.6 million metric tons of distillers grains were produced by ethanol plants in 2007. The amount of distillers grains produced is expected to increase significantly as the number of ethanol plants increase, which will

increase competition in the distillers grains market in our area. In addition, our distillers grains compete with other livestock feed products such as soybean meal, corn gluten feed, dry brewers grain and mill feeds.

Research and Development

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

Costs and Effects of Compliance with Environmental Laws

We are subject to extensive air, water and other environmental regulations and we have been required to obtain a number of environmental permits to construct and operate the Plant. We have obtained all of the necessary permits to operate the Plant. In December 2007, we submitted an air pollution control Title V permit application to the North Dakota Department of Health (“NDDH”). The application was deemed complete by the NDDH in January 2008. However, a revision to the application may be required following the United States Environmental Protection Agency (“EPA”) determination concerning the applicability of the best available control technology program. Although we have been successful in obtaining all of the permits currently required, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources on complying with such regulations. We expect to be subject to ongoing environmental regulations and testing.

Emissions compliance testing was performed at our Plant between June 6, 2007 and June 13, 2007, as well as on July 17, 2007. The emissions test results were submitted to the NDDH on August 20, 2007 and noted that our Plant had not met the conditions in our air permit for the DDGS Cooling Bag house and Boiler Common Stack for Volatile Organic Compounds and Particulate Matter, respectively.

Our Plant also performed a 30 day emissions test from July 18, 2007 to August 16, 2007, gathered by our Continuous Emissions Monitoring System. The 30 day test results were submitted to the NDDH on September 4, 2007 and noted that our Plant had not met the conditions in our air permit for the Nitrogen Oxides emissions limit.

An Air Pollution Control Permit To Construct Amendment application was submitted to the NDDH on November 26, 2007 requesting changes to the air permit allowed under Title 40 Code of Federal Regulations (“CFR”) Parts 52 and 70. NDDH is currently reviewing our submittal. Upon approval of the conditions requested in the amendment, we will be in compliance with all requirements of the air permit. Additionally, we were required to submit a complete application for a Renewable Operating Permit per 40 CFR 70 within one year of start-up of operations. We fulfilled this requirement with a December 31, 2007 application submittal. This application was deemed complete by the NDDH on February 1, 2008.

Additionally, we are working with our design builders to make modifications and improvements to our Plant’s emission control devices. We have found these modifications successful in reducing emissions levels and we have plans for final modifications to be installed during our normal maintenance shutdown which is scheduled for late April 2008. With these modifications and the air pollution control permit to construct amendment that was submitted on November 26, 2007, we expect our Plant will be in compliance with all requirements in our air permit.

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

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

Employees

We presently have 39 full-time employees and two contract employees. The two contract employees are for the positions of President and CEO, Mick Miller, and Plant manager, Edward Thomas, who are contracted to work with us by Greenway Consulting, LLC, a Minnesota limited liability company (“Greenway”), our management consultants. In October 2007, we hired Mark Klimpel as our Chief Financial Officer (“CFO”) .

Currently, eight of our employees are primarily involved in management and administration and the remainder are primarily involved in Plant operations.

Our success depends in part on our ability to attract and retain qualified personnel at a competitive wage and benefit level. We must hire qualified managers, accounting and other personnel. We operate in a rural area with low unemployment. There is no assurance that we will be

successful in attracting and retaining qualified personnel for our Plant within our wage and benefit assumptions. 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.

the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. Any ongoing increases in the price of coal will increase our cost of production and may negatively impact our future profit margins.

The spread between ethanol and corn prices can vary significantly and has started to decrease. Corn costs significantly impact our cost of goods sold. Our gross margins are principally dependent upon the spread between ethanol and corn prices. However, this spread has decreased as corn prices have increased dramatically since the beginning of 2007 based on North Dakota ethanol and corn prices published by AXXIS Petroleum and the National Agricultural Statistics Service, respectively. Any further reduction in the spread between ethanol and corn prices, whether as a result of higher corn prices or lower ethanol prices, would adversely affect our results of operations and financial condition.

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

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

We sell all of the ethanol we produce to RPMG in accordance with an ethanol marketing agreement. RPMG is the sole buyer of all of our ethanol and we rely heavily on its marketing efforts to successfully sell our product. Because RPMG sells ethanol for a number of other producers, we have limited control over its sales efforts. Our financial performance is dependent upon the financial health of RPMG, as a significant portion of our accounts receivable are attributable to RPMG. If RPMG breaches the ethanol marketing agreement or is not in the financial position to purchase all of the ethanol we produce, we could experience a material loss and we may not have any readily available means to sell our ethanol and our financial performance will be adversely and materially affected. If our agreement with RPMG terminates, we may seek other arrangements to sell our ethanol, including selling our own product, but we give no assurance that our sales efforts would achieve results comparable to those achieved by RPMG.

We have withheld $3.9 million from our design-builder, Fagen, Inc. , (“Fagen”) related to the coal combustor. We have withheld $3.9 million from our design-builder, Fagen, due to punch list items which are not complete as of March 31, 2008 and problems with the coal combustor. The punch list are items that must be complete under the terms of the Lump Sum Design-Build Agreement between Fagen and us dated August 29, 2005 (the “Design-Build Contract”) in order for us to sign off on final completion and authorize payment of the $3.9 million. In addition to a number of other punch list items, the Design-Build Contract specified that the coal combustor would operate on lignite coal; however, the coal combustor has not run consistently on lignite coal and we suffered plant shut-downs during early 2007 as a result. We are working with Fagen and its subcontractors on these issues; however, there is no assurance that any potentially agreed upon solution would solve the problems or solve the problems for $3.9 million or less. There is also no assurance that Fagen and its subcontractors will agree on any solution or even agree that the problem is their responsibility to correct. If Fagen disputes the withholding of the $3.9 million and demands payment, we may be forced to pay the $3.9 million and there would be no assurance that the punch list items would be completed or that the coal combustor would be able to use lignite coal.

Risks related to potential ongoing use of PRB coal, and discontinuing the use of lignite coal. We are currently using PRB coal instead of lignite coal. In 2006, we entered into a contract with the State of North Dakota through its Industrial Commission (the “Commission”) for a lignite coal grant not to exceed $350,000. For 2007, we did not meet the minimum lignite usage specified in the grant contract. Based on that information, we expect the Commission to notify us that we will have to repay our grant at an accelerated rate of $35,000 per year for every year we do not meet the specified percentage of lignite use as outlined in our grant. This may have a negative impact on our financial condition.

We currently buy all of our coal from Westmoreland. Westmoreland is currently the sole provider of all of our coal and we rely on them for the coal to run our Plant. If Westmoreland cannot or will not deliver the coal pursuant to the contract terms, our business will be materially and adversely affected. If our contract with Westmoreland terminates, we would seek alternative supplies of coal, but we may not be able to obtain the coal we need on favorable terms, if at all. If we cannot obtain an adequate supply of coal at reasonable prices, or enough coal at all, our financial condition would suffer and we could be forced to reduce or shut down operations.

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

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

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

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

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

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

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

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

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

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

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

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

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

Our process may not contain adequate corn oil to meet our anticipated yield or annual volume of extracted oil. Initial sampling has shown that our process contains enough oil to meet the minimum available volume in our corn oil extraction contract but we cannot be certain that we can maintain these volumes once extraction starts. If our process fails to meet the minimum available volume for extraction, the yield guarantees in our contract become unenforceable. This would result in a lower than anticipated revenue from sales of corn oil which would have a negative impact on our expected future gross profit and net income.

Demand for the corn oil produced at our Plant may decrease due to competition from other extraction technologies or commodities. Due to the high price of soybean oil, corn oil has recently become a viable alternative for producing biodiesel. We cannot be certain that this trend will continue in the future which may decrease the demand for corn oil produced at our Plant. Other extraction technologies that are more efficient or provide alternatives to corn oil may also evolve and decrease the demand for corn oil produced at our Plant. While our contract contains minimum pricing and yield guarantees, these minimum values would decrease our projected incremental gross profit and net income from corn oil sales by approximately fifty percent based on the current market price for corn oil produced at our Plant.

Risks Related to Conflicts of Interest

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

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

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

Our President and CEO may have a conflict of interest in his capacity as a board member of RPMG. While we believe the board members of RPMG will act in the best interest of the member companies, we cannot guarantee that this will always be the case which could have a negative impact on our Company. In addition, our CEO owes a duty to RPMG and may find that his obligations to act in the best interest of RPMG place him at a conflict with the best interests of Red Trail.

We cannot guarantee that our coal unloading facility capital project will move forward as anticipated. While the engineering and design of the project is substantially complete and we have received approval from our Board as well as our lender, the project is still subject to some uncertainty. To date we have not received the necessary permits to begin construction of the project nor have we signed a definitive contract for construction of the facility. We are also in the process of finalizing the purchase of additional land needed for the project. We currently have a verbal agreement in place to purchase the land. If we are unable to complete, or experience delays in completing any of these tasks, our coal unloading facility may not be constructed or the expected completion date could be delayed. This could reduce or eliminate the cost savings we anticipate receiving from this project.

Risks Related to Taxes

We are taxed as a partnership and must comply with certain provisions of the tax code to avoid being taxed as a corporation . 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 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, amount available for distributions to members, 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.

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 . During 2007 we entered into an agreement with Alerus Securities (“Alerus”) to allow our shares to be traded through their qualified matching service (the “Qualified Matching Service”). This arrangement allows buyers and sellers to list their offers to buy or sell our units on the Alerus website.

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

•		Transfers by gift to the member’s descendants;
•		Transfers upon the death of a member;
•		Certain other transfers provided that for the applicable tax year, the transfers in the aggregate do not exceed 2% of the total outstanding units; and
•		Transfers that comply with the Qualified Matching Service requirements.

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

Our units were not valued based on any independent objective criteria, but rather by the amount of funding required to build our Plant. For our North Dakota intrastate offering and our initial seed capital round, we determined the offering price per unit to be $1.00. This determination was based solely on the capitalization requirements necessary to fund our construction and start-up activities. We did not rely upon any independent valuation, book value or other valuation criteria. We do not place any value on the units. Any value is based on our bids received on our Qualified Matching Service, independent from any determination by us.

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 our 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 the North Dakota Century Code, Section 10-32-99, as amended from time to time, or as required or permitted by other provisions of law.

Risks Related to Ethanol Industry

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

We expect to operate in a competitive industry and compete with larger, better-financed entities, which could impact our ability to operate profitably. There is significant competition among ethanol producers with numerous producer and privately-owned ethanol plants planned and operating throughout the United States. The number of ethanol plants being developed and constructed in the United States continues to increase at a rapid pace. If the demand for ethanol does not grow at the same pace as increases in supply, we expect that lower prices for ethanol will result which may adversely affect our ability to generate profits and our financial condition.

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

Certain countries can export ethanol to the United States duty-free, which may undermine the ethanol production industry in the United States . Imported ethanol is generally subject to a 54 cents per gallon tariff and a 2.5% ad valorem tax that was designed to offset the 51 cents per gallon ethanol subsidy available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. There is a special exemption from the tariff for ethanol imported from 24 countries in Central America and the Caribbean islands, which is limited to a total of 7.0% of United States production per year. The tariff is set to expire in December 2009. We do not know the extent to which the volume of imports would increase if the tariff is not renewed.

In addition, the North American Free Trade Agreement countries, Canada and Mexico, are exempt from duty. Imports from the exempted countries have increased in recent years and are expected to increase further as a result of new plants under development.

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

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

	•		additional rail capacity to meet the expanding volume of ethanol shipments;
	•		additional storage facilities for ethanol;
	•		increases in truck fleets capable of transporting ethanol within localized markets;
	•		expansion of and/or improvements to refining and blending facilities to handle ethanol instead of MTBE; and
	•		growth in the fleet of flexible fuel vehicles capable of using E85 fuel.

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

Risks Related to Regulation and Governmental Action

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

Loss of or ineligibility for favorable tax benefits for ethanol production could hinder our ability to operate at a profit and reduce the value of your investment in us. The ethanol industry and our business are assisted by various federal ethanol tax incentives, including those included in the Energy Independence and Security Act of 2007. The provision of this Act most likely to have the greatest impact on the ethanol industry is the amendment to the RFS created in 2005. The revised RFS calls for 9 billion gallons of ethanol and other biofuels to be produced in 2008, growing to 36 billion gallons in 2015, with 15 billion gallons to be derived from conventional biofuels like corn-based ethanol. The RFS helps support a market for ethanol that might disappear without this incentive. The elimination or reduction of tax incentives to the ethanol industry could reduce the market for ethanol, which could reduce prices and our revenues by making it more costly or difficult for us to produce and sell ethanol. If the federal tax incentives are eliminated or sharply curtailed, we believe that a decreased demand for ethanol will result, which could depress ethanol prices and negatively impact our financial performance.

An important provision of the Energy Policy Act of 2005, that is still in effect, involves an expansion of the small ethanol producer definition. Historically, small ethanol producers were allowed a 10-cents per gallon production income tax credit on up to 15 million gallons of production annually. Under the Energy Policy Act of 2005 the size limitation on the production capacity for small ethanol producers increased from 30 million to 60 million gallons.

Changes in environmental regulations or violations of the regulations could be expensive and reduce our profitability. We are subject to extensive air, water and other environmental laws and regulations. In addition, some of these laws require our Plant to operate under a number of environmental permits. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, damages, criminal sanctions, permit revocations and/or plant shutdowns. We can not assure you that we have been, are or will be at all times, in complete compliance with these laws, regulations or permits or that we have had or have all permits required to operate our business. We do not assure you that we will not be subject to legal actions brought by environmental advocacy groups and other parties for actual or alleged violations of environmental laws or our permits. Additionally, any changes in environmental laws and regulations, both at the federal and state level, could require us to invest or spend considerable resources in order to comply with future environmental regulations. The expense of compliance could be significant enough to reduce our profitability and negatively affect our financial condition.

The use of coal as a fuel source could subject us to additional environmental compliance costs. As a consumer of coal, we may be subject to more stringent air emissions regulations in the future. There is emerging consensus that the federal government will begin regulating greenhouse gas emissions, including carbon dioxide, in the near future. Since coal emits more carbon dioxide than alternative fuel sources, including natural gas, which most ethanol plants use, we may need to make significant capital expenditures to reduce carbon dioxide emissions from the Plant. In addition, we may incur substantial additional costs for regulatory compliance, such as paying a carbon tax or purchasing emissions credits under a cap-and-trade regime. If the costs of regulatory compliance become prohibitively expensive, we may have to switch to an alternate fuel source such as natural gas or biomass. The switch to an alternate fuel source could result in a temporary slow down or disruption in operations. The switch to an alternate fuel source like natural gas or biomass could also result in a material adverse effect on our financial performance, as coal is currently the least expensive fuel source available for Plant operations.

proceedings, directly or indirectly, and we are not aware of any claims pending or threatened against us or any of our governors that could result in the commencement of legal proceedings.

Results of Operations

From July 2003 to December 31, 2006, we were a development stage company with no revenues or costs of sales. We commenced production and sale of fuel grade ethanol in January 2007.

Comparison of Fiscal Years Ended December 31, 2007, 2006 and 2005

The following table shows the results of our operations and the percentages of sales and revenues, cost of sales, operating expenses and other items to total sales and revenues in our statements of operations for the years ended December 31, 2007, 2006 and 2005:

Revenues

We began producing and selling ethanol and distillers grains in January 2007. We had no sales or revenues for the fiscal years ended December 31, 2006 or 2005.

2007 Revenue:

	•		Total revenue for 2007 was approximately $101.9 million. Ethanol and distillers grains represented 88% and 12% of revenue, respectively.
	•		Ethanol — Prices received by us for ethanol during 2007 ranged from $1.57 to $2.04 per gallon. Prices peaked in March at $2.04 per gallon and then slowly declined until October 2007 when prices dipped to $1.57 per gallon. Prices improved in November and December to $1.76 per gallon and $2.01 per gallon, respectively.
	•		Distillers grains — Our 2007 distillers grain sales volumes were roughly split 50-50 between DDGS and DMWG. Prices received by us for DDGS ranged from $80 to $100 per ton during 2007 with our average selling price for the year being approximately $87 per ton. The price steadily increased during the last half of 2007 as corn prices started to increase. Prices received by us for DMWG ranged from $35 to $53 per ton with our average selling price for the year being approximately $40 per ton.
	•		During the fourth quarter of 2007, we started to use ethanol derivative instruments in an effort to lock in a margin on a portion of our production relative to corn that we have purchased under contract. We recognize any gains or losses that result from the change in value of our ethanol derivative instruments in revenue as the changes occur. During 2007, we recognized a loss of approximately $2 million in revenue related to the change in value of our ethanol derivative instruments as ethanol prices rose above the prices we had locked in with our ethanol swaps.

Prospective Information:

	•		Ethanol — we believe that ethanol prices may decrease later in 2008 as projected additional ethanol production capacity becomes available but we cannot be certain of how the price of ethanol will change, as it is a market driven commodity.
	•		Distillers Grains — Distillers grains prices normally follow the price of corn. As corn prices have risen during the last half of 2007 and the first quarter of 2008 our distillers grains prices have also increased. We believe distillers grains prices will remain consistent with corn price fluctuations but we cannot be certain of how the price of distillers grains will change, as it is a market driven commodity.

•

Corn Oil Extraction — we have entered into an agreement to add corn oil extraction equipment to our facility. We do not believe the equipment will be operational during 2008 but project that it will be operational during the first quarter of 2009. At current prices and anticipated volumes, we expect that corn oil sales will add approximately $1,000,000 to our revenues on an annual basis.

Cost of Goods Sold and Gross Margin

We began producing and selling ethanol and distillers grains in January 2007. We had no costs of sales for the fiscal years ending December 31, 2006, and 2005.

Our gross margin is very sensitive to fluctuations in the price of corn as we are generally not able to pass through cost increases to customers. Corn prices rose to record levels in 2007 and have continued to increase during the first quarter of 2008. If this trend were to continue, we would expect this to have a negative impact on our gross margin. We have contracts in place for our energy needs (coal, water, electricity and natural gas) in an effort to mitigate future price increases.

2007 Cost of Goods Sold:

	•		Total cost of goods sold for 2007 was approximately $87 million or 85.5% as a percentage of sales. Our gross margin for 2007 was approximately $14.9 million. Purchases of corn represented 78% of the total cost of goods sold.
	•		We use corn derivative instruments in an effort to lock in a margin on a portion of our production relative to ethanol prices. We recognize any gains or losses that result from the change in value of our corn derivative instruments in cost of goods sold as the changes occur. During 2007, we recognized a gain of approximately $3 million that offset our cost of corn in cost of goods sold. As the price of corn fluctuates, the value of our corn derivative instruments are impacted, which affects our financial performance.

Prospective Information:

	•		Corn — we anticipate that the price of corn will continue to rise during 2008. If this trend were to continue, it will have a negative impact on our gross margin. We cannot be certain how the price of corn will change as it is a market driven commodity. We will continue to contract with local farmers to buy corn as well use corn derivative instruments to hedge a portion of our corn needs.
	•		Energy needs — we have contracts in place, for our main energy inputs in an effort to mitigate future price increases. This includes contracts for our coal, water, electricity and natural gas requirements.
	•		Other costs of goods sold — one of our other main production inputs is chemicals. Chemical prices started to rise at the end of 2007 and have continued to rise during 2008. We do not anticipate the price increases to have a material impact on our financial performance but cannot be certain how the price of chemicals will fluctuate in the future.
	•		Corn Oil Extraction — we have entered into an agreement to add corn oil extraction equipment to our facility. We do not believe the equipment will be operational during 2008 but project that it will be operational during the first quarter of 2009. At current prices and anticipated volumes, we expect that corn oil sales will add approximately $1,000,000 to our gross margin and net income on an annual basis.

General and Administrative Expenses

2007 compared to 2006 — general and administrative expenses decreased approximately $534,000 (14.2%) due to:

	•		$1.1 million of start up costs in 2006. These costs were related to the purchase of plant supplies and other start up costs that were allocated to general and administrative expense during 2006 because our Plant was not yet operational. Similar expenses may have been incurred during 2007 but would have been included in cost of goods sold.
	•		$550,000 of pre-production payroll expenses that were charged to general and administrative expense in 2006 because the Plant was not yet operational. Similar expenses incurred during 2007 are shown in cost of goods sold.

Partially offsetting the decreases were:

•

Approximately $1.1 million of increased general and administrative expenses related to the administration and management of the Plant during its first full year of operation.

2006 compared to 2005 — general and administrative expenses increased approximately $1.7 million (79.5%) due to:

•

Costs associated with management and administrative expenses during the construction of our Plant, professional and consulting fees and commencement of Plant operations. The main expenses incurred during 2006 include: $1.5 million related to professional services, $1.1 million in start up expenses and supplies, $649,000 in payroll related expenses, and $249,000 in legal fees.

Prospective Information:

•

We anticipate our general and administrative expenses for 2008 to be approximately $200,000 lower than 2007 as we work to decrease our legal, professional and consulting fees but cannot be certain that these goals will be met due to our changing business climate. We anticipate lower costs in certain areas as our employees take more responsibility for duties previously performed by our legal counsel and/or outside consultants and we also anticipate that certain permitting and legal costs that were incurred during 2007 will not recur in 2008.

Operating Income

Because we had no revenues and cost of sales prior to 2007, our operating loss in fiscal years 2006 and 2005 is the same as our operating expenses. Our operating income in 2007 was approximately $11.7 million. The increase over 2006 is due to the commencement of Plant operations during January 2007, as described above.

Interest Expense and Other Income and Expense

Our interest costs for the fiscal years ended December 31, 2007, 2006 and 2005 were approximately $6.3 million, $1.5 million, and $0, respectively. However, the interest cost of approximately $1.5 million in fiscal year 2006 was capitalized and included in construction in progress. There was no interest expense for the fiscal year ending December 31, 2005. Our interest expense for 2007 includes $5.1 million of interest expense on our long-term debt, approximately $933,000 of losses related to the change in value of our interest rate swaps and approximately $214,000 of expense related to amortization of our capitalized financing costs.

Interest rates trended downward in the fourth quarter of 2007 which caused the value of our interest rate swaps to decrease. This trend continued during the first quarter of 2008 and has negatively impacted our earnings during the first quarter. If this trend continues, we anticipate that it will continue to have a negative impact on our net income. If interest rates begin to trend higher later in 2008, we would expect this to have a positive impact on our net income.

Interest income, resulting primarily from the investment of cash received from our unit sales between inception and Plant construction, was approximately $432,000, $182,000 and $588,000 for the fiscal years ended December 31, 2007, 2006 and 2005, respectively. Interest income increased in 2007 compared to 2006, because of positive cash flows from operations during 2007. As our cash position allows, we use money market accounts to earn interest on our excess cash. We are also holding approximately $3.9 million in a money market account to cover the final construction costs that have not been paid to Fagen. Interest income decreased in 2006 as compared to 2005 as funds raised from member investments were disbursed for Plant construction and pre-production operating expenses. We do not expect to receive any significant interest income in 2008.

Gains (losses) derived from our corn derivative instruments and changes in the value of our interest rate swap were recorded in the other income and expense section for years prior to 2007. During 2007, we recorded gains (losses) associated with our corn derivative instruments in cost of goods sold and we recorded the change in the value of our interest rate swap in interest expense. For the fiscal years ending December 31, 2006 and 2005, there were no settlements, and changes in the value of our interest rate swap resulted in gains (losses) from non-designated hedging derivatives on the interest rate swap contract of approximately $167,000 and $(278,000) respectively. For the fiscal years ending December 31, 2006 and 2005, there were no net settlements, and market value adjustments resulted in a gain associated with our corn derivative instruments of approximately $894,000 and $0. We may recognize significant gains or losses in the near future in connection with our interest rate swap contract and corn and ethanol derivative instruments.

Grant income was approximately $27,750, $0, and $50,000 for the fiscal years ended December 31, 2007, 2006 and 2005, respectively. We do not anticipate receiving any grant income during 2008.

Plant Operations

Operations of Ethanol Plant

Production in 2007 was approximately 50.3 million gallons, just above our name-plate capacity levels of 50 MMGY. Management anticipates that the Plant will be operating at or above name-plate capacity of 50 MMGY for the next twelve months.

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

Critical Accounting Estimates

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

Derivative Instruments

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

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

Inventory

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

Commitments and Contingencies

Contingencies, by their nature, relate to uncertainties that require management to exercise judgment both in assessing the likelihood that a liability has been incurred, as well as in estimating the amount of the potential expense. In conformity with United States generally accepted accounting principles, we accrue an expense when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Long-Lived Assets

Depreciation and amortization of our property, plant and equipment is applied on the straight-line method by charges to operations at rates based upon the expected useful lives of individual or groups of assets placed in service. Economic circumstances or other factors may cause management’s estimates of expected useful lives to differ from the actual useful lives. Differences between estimated lives and actual lives may be significant, but management does not expect events that occur during the normal operation of our Plant related to estimated useful lives to have a significant effect on results of operations.

Long-lived assets, including property, plant, equipment and investments, are evaluated for impairment on the basis of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impaired asset is written down to its estimated fair market value based on the best information available. Considerable management judgment is necessary to estimate future cash flows and may differ from actual cash flows. Management does not expect that an impairment of assets will exist based on their assessment of the risks and rewards related to the ownership of these assets and the expected cash flows generated from the operation of the Plant.

Cash flows

Operating activities. Net income before depreciation and amortization is a significant contributor to cash flows from operating activities. The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.

Cash flows provided by operating activities in 2007 increased $10.3 million from the comparable prior period, as a result of:

	•		Increased net income of $8.7 million, due to the Plant becoming operational in 2007;
	•		Increased depreciation expense of $5.7 million, due to the Plant becoming operational in 2007; and

•

Increased amortization expense and changes in the market value of our interest rate swap that added $1.4 million.

Partially offsetting the increase in cash flows from operating activities were:

•

A net increase in cash flow use of $5.5 million from changes in working capital items related to the Plant becoming operational in 2007. Current assets such as inventory, accounts receivable and the change in market value of our corn and ethanol derivative instruments increased more than our current liabilities during 2007.

Cash flows provided by operating activities in 2006 decreased $7.6 million from the comparable 2005 period, the result of start up expenses incurred in 2006 related to Plant construction activities along with the purchase of inventories in preparation for the inception of production in January 2007.

Investing activities. Cash flows used in investing activities in 2007 decreased $62.9 million compared to the comparable prior period, the result of lower capital expenditures in 2007 due to Plant construction being substantially complete at the end of 2006.

Cash flows used in investing activities in 2006 increased $56.3 million compared to the comparable 2005 period, as a result of increased capital expenditures in 2006 as most of the Plant construction work took place during 2006.

Financing activities. Cash flows provided by financing activities in 2007 decreased $46.8 million compared to the comparable prior period, primarily the result of:

	•		A decrease in the issuance of long-term debt of $38.6 million;
	•		A decrease in member contributions of $6.7 million due to the closing of the equity drive during 2006; and
	•		Higher debt repayments of $1.8 million as we commenced debt service in 2007.

Cash flows provided by financing activities in 2006 increased $42.1 million compared to the comparable 2005 period, primarily the result of an increase in proceeds from long-term debt of $49.8 million as we borrowed money for the construction of the Plant, partially offset by a decrease in member contributions of $7.6 million as the equity drive came to a close during 2006.

We anticipate being able to fund our operations and planned capital projects from our operating cash flow and existing lines of credit during 2008.

Capital Expenditures

We incurred significant capital expenditures in 2005, 2006 and 2007 during Plant construction. For 2008 we anticipate our capital expenditures will be approximately $2.2 million. The majority of our 2008 capital expenditures will be related to our coal unloading facility project, which we expect to cost approximately $2 million. We anticipate funding our capital expenditures from our operating cash flow and existing lines of credit during 2008. Due to the nature of the corn oil agreement, we do anticipate any capital expenditures related to the installation of corn oil extraction equipment at our facility.

Capital Resources

Short-Term Debt Sources

We have a revolving promissory note of up to $3,500,000 with First National Bank of Omaha (the “Bank”) through July 5, 2008, subject to certain borrowing base limitations. Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over LIBOR, which totaled 6.2175% at March 16, 2008. We have no outstanding borrowings on the revolving promissory note as of December 31, 2007, 2006 and 2005.

Long-Term Debt Sources

We had four long-term notes with the Bank (collectively the “Term Notes”) in place as of December 31, 2007. The loan agreements are secured by substantially all of our assets. Three of the notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007. The fourth note was entered into during December 2007 (the “December 2007 Fixed Rate Note”) when we entered into a second interest rate swap agreement which effectively fixed the interest rate on an additional $10 million of debt. The construction loan agreement requires us to maintain certain financial ratios and meet certain non-financial covenants. Each note has specific interest rates and terms as described below.

Fixed Rate Note - The fixed rate note (the “Fixed Rate Note”) had a balance of $26.6 million outstanding at December 31, 2007. Interest payments are made on a quarterly basis with interest charged at 3.0% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of January 14, 2008, the rate was 7.055%. 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 January 2012, with a final principal payment of approximately $17,000,000 at April 2012.

Variable Rate Note - During December 2007, $10 million of the variable rate note (the “Variable Rate Note”) was transferred to the December 2007 Fixed Rate Note as part of the 4 ^th amendment to the loan agreement. The Variable Rate Note had a balance of $6.77 million at December 31, 2007. Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of January 14, 2008, the rate was 7.455%. Principal payments are made quarterly according to the

terms of the construction loan agreement as amended by the fourth amendment to the construction loan agreement. The amendment calls for quarterly payments of $634,700 applied first to interest on the long-term revolving note (the “Long-Term Revolving Note”), next to accrued interest on the Variable Rate Note and finally to principal on the Variable Rate Note. Based on the interest rate noted above we estimate that the remaining Variable Rate Note will be paid off in October 2010. We anticipate the principal payments to be approximately $445,000 per quarter with a final payment of approximately $197,000 in October 2010.

Long-Term Revolving Note - The Long-Term Revolving Note had a balance of $10 million at December 31, 2007. Interest is charged at 3.4% over the one-month LIBOR rate with payments due quarterly. The interest rate is reset monthly. As of March 16, 2008, the rate was 6.2175%.

December 2007 Fixed Rate Note - The December 2007 Fixed Rate Note was created by the fourth amendment to the construction loan agreement as noted above. Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of January 14, 2008, the rate was 7.455%. Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $183,000 and increasing to $242,000 per quarter, from January 2008 to January 2012, with a final principal payment of approximately $6,334,000 at April 2012.

All unpaid amounts on the Term Notes are due and payable in April 2012. We are subject to a number of covenants and restrictions in connection with these loans, including:

	•		Providing the Bank with current and accurate financial statements;
	•		Maintaining certain financial ratios, minimum net worth, and working capital;
	•		Maintaining adequate insurance;
	•		Make, or allow to be made, any significant change in our business or tax structure; and
	•		Limiting our ability to make distributions to members.

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

	•		declaring all the debt owed to the Bank immediately due and payable; and
	•		taking possession of all of our assets, including any contract rights.

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

Interest Rate Swap Agreements

In December 2005, we entered into an interest rate swap transaction that effectively fixed the interest rate at 8.08% on the outstanding principal of the Fixed Rate Note. In December 2007, we entered into a second interest rate swap transaction that effectively fixed the interest rate at 7.695% on the outstanding principal of the December 2007 Fixed Rate Note.

The interest rate swaps were not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements were recorded as a gain or loss from non-designated hedging activities in other income and expense during 2005 and 2006 and are shown in interest expense in 2007.

For the fiscal years ending December 31, 2007, 2006 and 2005 there were settlements of approximately $39,000, $0 and $0, respectively and market value adjustments resulting in a gains/(losses) of approximately $(933,000), $851,000 and $(278,000), respectively.

Letters of Credit

The construction loan agreement provides for up to $1,000,000 in letters of credit with the Bank to be used for any future line of credit requested by a supplier to the Plant. All letters of credit are due and payable at April 2012. The construction loan agreement provides for us to pay a quarterly commitment fee of 2.25% of all outstanding letters of credit. In addition, as of December 31, 2007, we have one outstanding letter of credit for $137,000 for capital expenditures for gas services with Montana-Dakota Utilities Co.

Subordinated Debt

As part of the construction loan agreement, we entered into three separate subordinated debt agreements totaling approximately $5,525,000 and received funds from these debt agreements during 2006. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate (a total of 9.455% at January 14, 2008) and is due and payable subject to approval by the senior lender, the Bank. Interest is compounding with any unpaid interest converted to principal. Amounts will be due and payable in full in April 2012. As of December 31, 2007, the outstanding amounts on these loans was $5,525,000.

Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of December 31, 2007:

To date, we have not incurred any commitments or contractual obligations related to our coal unloading capital project. Due to the nature of the agreement, there are no commitments associated with our corn oil extraction agreement.

Grants

In 2006, we entered into a contract with the State of North Dakota through the Commission for a lignite coal grant not to exceed $350,000. In order to receive the proceeds, we were required to build a 50 MMGY ethanol plant located in North Dakota that utilizes clean lignite coal technologies in the production of ethanol. We also had to provide the Commission with specific reports in order to receive the funds including a final report (the “Final Report”) six months after ethanol production began. After the first year of operation, we will be required to repay a portion of the proceeds in annual payments of $22,000 over ten years. The payments could increase based on the amount of lignite coal we are using as a percentage of primary fuel. We received $275,000 from this grant in 2006. During the first quarter of 2007, we experienced issues with the delivery and quality of lignite coal under the lignite supply agreement as well as combustion issues with the coal combustor. We terminated the contract for lignite coal delivery in April 2007 due to the supplier’s failure to deliver lignite coal as required by the contract. At that time, we entered into short term delivery for PRB coal as an alternative to lignite coal. During December 2007, we extended our PRB coal agreement for two additional years as we continue to try to resolve the issues experienced while running the Plant on lignite coal. Due to the temporary nature of our use of PRB coal, the grant terms remain consistent with that described above; however, a permanent change to a primary fuel source other than lignite coal may accelerate or increase the repayment of these amounts. We intend to use lignite coal in the future if delivery, pricing, quality and performance issues can be resolved favorably. Because we have been temporarily using PRB coal, we made a formal request to extend the Final Report deadline from June 30, 2007 to August 31, 2007. We received the extension but have not yet returned to using lignite coal nor filed the Final Report. In place of the Final Report, we filed a memo with the Commission updating them on the status of using lignite coal at our Plant for 2007. This included supplying information on what percentage lignite coal was of our total coal usage (on a BTU basis) for 2007. For 2007, we did not meet the minimum lignite usage specified in the grant contract. Based on that information, we expect the Commission to notify us that we will have to repay our grant at an accelerated rate of $35,000 per year for every year we do not meet the specified percentage of lignite use as outlined in our grant. We have remained in contact with the Commission about the current state of the Plant as well as future intentions to run on lignite coal.

We have entered into an agreement with Job Service North Dakota for a new jobs training program. This program provides incentives to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training. We will receive up to approximately $170,000 over ten years. We did not receive any funds in the fiscal years ended December 31, 2007 and 2006.

In additional to the Job Service North Dakota training program, we entered into a contract on October 2, 2006 with Job Service North Dakota for the Workforce 20/20 program. The program assists North Dakota employers in training and upgrading workers’ skills. Under this program, we received $27,750 in 2007.

We were awarded a grant from Ag Products Utilization Council in the amount of $150,000, which was used in 2005 and 2004 for general business expenses, including legal and accounting.

North Dakota Ethanol Incentive Program

We have received written assurance from the North Dakota Department of Commerce that our Plant will qualify for North Dakota’s fuel tax fund incentive program. Ethanol plants constructed after July 31, 2003 are eligible for incentives. Under the program, each fiscal quarter eligible ethanol plants may receive a production incentive based on the average North Dakota price per bushel of corn received by farmers during the quarter, as established by the North Dakota agricultural statistics service, and the average North Dakota rack price per gallon of ethanol during the quarter, as compiled by AXXIS Petroleum. We received $227,000 from this program for the fourth quarter of 2007. Because we cannot predict the future prices of corn and ethanol, we cannot predict whether we will receive any funds in the future. The incentive received is calculated by using the sum arrived at for the corn price average and for the ethanol price average as calculated in number 1 and number 2 below:

	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 $1.6 million per year. 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 are eligible for a tax credit against North Dakota state income tax liability. On May 3, 2004, we were approved for the North Dakota Seed Capital Investment Tax Credit. In 2005, North Dakota revised its tax incentive programs and adopted the Agricultural Commodity Processing Facility Investment Tax Credit. We were grandfathered into the new program and do not need to meet the new conditions to qualify for the tax credit. The amount of credit for which a taxpayer may be eligible is 30% of the amount invested by the taxpayer in a qualified business during the taxable year.

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Commodity Price Risk

We also expect to be exposed to market risk from changes in commodity prices. Exposure to commodity price risk results from our dependence on corn in the ethanol production process and the sale of ethanol. We will seek to minimize the risks from fluctuations in the prices of corn through the use of hedging instruments. In practice, as markets move, we will actively manage our risk and adjust hedging strategies as appropriate. Although we believe our hedge positions will accomplish an economic hedge against our future purchases, they likely will not qualify for hedge accounting, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged. We intend to use fair value accounting for our hedge positions, which means as the current market price of our hedge positions changes, the gains and losses are immediately recognized in our cost of sales. For example, our net hedge position had a market value of approximately $3.2 million at December 31, 2007. We would generally expect that a 10% increase in the cash price of corn would produce a $330,000 increase in the fair value of our derivative instruments. Whereas a 10% decrease in the cash price of corn would likely produce a $330,000 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, 2007 and 2006, we had investments of $3.1 million and $300,000 in corn and ethanol derivative instruments, respectively. 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. We intend to continue to contract for price protection for our corn usage. As corn prices move in reaction to market trends and information, our income statements will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects but are expected to produce long-term positive growth.

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

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

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

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

This report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to the attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this Annual Report.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework .

Based on our evaluation under the framework in Internal Control—Integrated Framework , management concluded that our internal control over financial reporting was effective as of December 31, 2007.

/s/ Mick J. Miller   Mick J. Miller		/s/ Mark E. Klimpel   Mark E. Klimpel
President and Chief Executive Officer		Chief Financial Officer

( 3) Exhibits
10.2		Management Agreement made and entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.2 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.3		Development Services Agreement entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.3 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.4		The Burlington Northern and Santa Fe Railway Company Real Estate Purchase and Sale Agreement with Red Trail Energy, LLC, dated January 14, 2004. Filed as Exhibit 10.4 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.5		Grain Origination Contract effective April 1, 2004 between Red Trail Energy, LLC, and New Vision Coop. Filed as Exhibit 10.7 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.6		Warranty Deed made as of January 13, 2005 between Victor Tormaschy and Lucille Tormaschy, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.8 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.7		Warranty Deed made as of July 11, 2005 between Neal C. Messer and Bonnie M. Messer, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.9 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.8		Agreement for Electric Service made the 18th day of August, 2005, by and between West Plains Electric Cooperative, Inc. and Red Trail Energy, LLC. Filed as Exhibit 10.10 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.9+		Lump Sum Design-Build Agreement between Red Trail Energy, LLC, and Fagen, Inc. dated August 29, 2005. Filed as Exhibit 10.12 to the registrant’s registration statement on Form 10-12G/A-3 (000-52033) and incorporated by reference herein.
10.10		Railroad Construction, Design and Repair Contract made as of November 7, 2005, by and between R & R Contracting, Inc. and Red Trail Energy, LLC. Filed as Exhibit 10.13 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.11		Construction Loan Agreement dated as of the 16th day of December by and between Red Trail Energy, LLC, and First National Bank of Omaha. Filed as Exhibit 10.14 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.12		Construction Note for $55,211,740.00 dated December 16, 2005, between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.15 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.13		International Swap Dealers Association, Inc. Master Agreement dated as of December 16, 2005, signed by First National Bank of Omaha and Red Trial Energy, LLC. Filed as Exhibit 10.18 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.14		Security Agreement and Deposit Account Control Agreement made December 16, 2005, by and among First National Bank of Omaha, Red Trail Energy, LLC, and Bank of North Dakota. Filed as Exhibit 10.19 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.15		Security Agreement given as of December 16, 2005, by Red Trail Energy, LLC, to First National Bank of Omaha. Filed as Exhibit 10.20 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.16		Control Agreement Regarding Security Interest in Investment Property, made as of December 16, 2005, by and between First National Bank of Omaha, Red Trail Energy, LLC, and First National Capital Markets, Inc. Filed as Exhibit 10.21 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

( 3) Exhibits
10.17		Loan Agreement between Greenway Consulting, LLC, and Red Trail Energy, LLC, dated February 26, 2006. Filed as Exhibit 10.22 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.18		Promissory Note for $1,525,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to Greenway Consulting, LLC. Filed as Exhibit 10.23 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.19		Loan Agreement between ICM Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.24 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.20		Promissory Note for $3,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to ICM Inc. Filed as Exhibit 10.25 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.21		Loan Agreement between Fagen, Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.26 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.22		Promissory Note for $1,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to Fagen, Inc. Filed as Exhibit 10.27 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.23		Southwest Pipeline Project Raw Water Service Contract, executed by Red Trail Energy, LLC, on March 8, 2006, by the Secretary of the North Dakota State Water Commission on March 31, 2006, and by the Chairman of the Southwest Water Authority on April 2, 2006. Filed as Exhibit 10.28 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.24		Contract dated April 26, 2006, by and between the North Dakota Industrial Commission and Red Trail Energy, LLC. Filed as Exhibit 10.29 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.25		Subordination Agreement, dated May 16, 2006, among the State of North Dakota, by and through its Industrial Commission, First National Bank and Red Trail Energy, LLC. Filed as Exhibit 10.30 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.26		Firm Gas Service Extension Agreement, dated June 7, 2006, by and between Montana-Dakota Utilities Co. and Red Trail Energy, LLC. Filed as Exhibit 10.31 to the registrant’s registration statement on Form 10-12G/A-2 (000-52033) and incorporated by reference herein.
10.27		First Amendment to Construction Loan Agreement dated August 16, 2006 by and between Red Trail Energy, LLC and First National Bank of Omaha. Filed as Exhibit 10.32 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2006 (000-52033) and incorporated by reference herein.
10.28		Security Agreement and Deposit Account Control Agreement effective August 16, 2006 by and among First National Bank of Omaha and Red Trail Energy, LLC. Filed as Exhibit 10.34 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.29		Equity Grant Agreement dated September 8, 2006 by and between Red Trail Energy, LLC and Mickey Miller. Filed as Exhibit 10.35 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.30		Option to Purchase 200,000 Class A Membership Units of Red Trail Energy, LLC by Red Trail Energy, LLC from North Dakota Development Fund and Stark County dated December 11, 2006. Filed as Exhibit 10.36 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.31		Audit Committee Charter adopted April 9, 2007. Filed as Exhibit 10.37 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.32		Senior Financial Officer Code of Conduct adopted March 28, 2007. Filed as Exhibit 10.38 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.

( 3) Exhibits
10.33		Long Term Revolving Note for $10,000,000, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by reference herein.
10.34		Variable Rate Note for $17,065,870, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033).
10.35		Fixed Rate Note for $27,605,870, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by reference herein.
10.36		$3,500,000 Revolving Promissory Note given by the Company to First National Bank of Omaha dated July 18, 2007. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (000-52033) and incorporated by reference herein.
10.37		Second Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated July 18, 2007. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (000-52033) and incorporated by reference herein.
10.38*		Third Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated November 15, 2007.
10.39*		Fourth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007.
10.40*		Interest Rate Swap Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007.
10.41*		Member Ethanol Fuel Marketing agreement by and between Red Trail Energy, LLC and RPMG, Inc dated January 1, 2008.
10.42*		Contribution Agreement by and between Red Trail Energy, LLC and Renewable Products Marketing Group, LLC dated January 1, 2008.
10.43*		Coal Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal Sales Company dated December 5, 2007.
10.44*		Distillers Grain Marketing Agreement by and between Red Trail Energy, LLC and CHS, Inc dated March 10, 2008.
31.1		Certification by Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).
31.2		Certification by Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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

Red Trail Energy, LLC
Financial Statements

December 31, 2007 and 2006

CONTENTS

		Page
Report of Independent Registered Public Accounting Firm			F-2
Financial Statements
Balance Sheet			F-3
Statement of Operations			F-4
Statement of Changes in Members’ Equity			F-5
Statement in Cash Flows			F-6
Notes to Financial Statements			F-7 -19

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 as of December 31, 2007 and 2006, and the related statements of operations, changes in members’ equity, and cash flows for the fiscal years ended December 31, 2007, 2006 and 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 audit provides 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 as of December 31, 2007 and 2006, and the results of their operations and their cash flows for the years ended December 31, 2007, 2006 and 2005 in conformity with U.S. generally accepted accounting principles.

Minneapolis, Minnesota
April 11, 2008

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

Red Trail Energy, LLC
Statement of Operations

Years ended December 31,		2007				2006				2005
Revenues
Ethanol, net of loss on derivative instruments		$	90,100,581			$	—			$	—
Distillers grains			11,785,388				—				—
Total Revenue			101,885,969				—				—
Cost of Goods Sold
Corn costs, net of gain on derivative instruments			67,778,832				—				—
Production costs			13,579,178				—				—
Depreciation			5,655,198				—				—
Total Cost of Goods Sold			87,013,208				—				—
Gross Margin			14,872,761				—				—
General and Administrative			3,214,002				3,747,730				2,087,808
Operating Income (Loss)			11,658,759				(3,747,730	)			(2,087,808	)
Interest Expense			6,268,707				—				—
Other Income, net			767,276				1,243,667				360,204
Net Income (Loss)		$	6,157,328			$	(2,504,063	)		$	(1,727,604	)
Weighted Average Units Outstanding			40,371,238				39,625,843				24,393,980
Net Income (Loss) Per Unit, basic and fully diluted		$	0.15			$	(0.06	)		$	(0.07	)

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

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

Red Trail Energy, LLC

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2007, 2006 and 2005

Derivative Instruments

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

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

Additionally, SFAS No. 133 requires a company to evaluate its contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted as “normal purchases or normal sales.” Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. As of December 31, 2007 and 2006 the Company has no derivatives instruments that meet this criterion.

Revenue Recognition

The Company generally sells ethanol and related products pursuant to marketing agreements. Revenues are recognized when the customer has taken title, which occurs when the product is shipped, has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues are shown net of any fees incurred under the terms of the Company’s agreements for the marketing and sale of ethanol and related products.

Inventory

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

Property and Equipment

Property and equipment is stated at cost. Assets are depreciated over their estimated useful lives by use of the straight-line method. Maintenance and repairs are expensed as incurred; major improvements and betterments are capitalized. Depreciation of assets is computed using the straight-line method over the following estimated useful lives:

Depreciation expense for the years ended December 31, 2007 and 2006 totaled approximately $5.7 million and $16,000, respectively.

Long-lived Assets

The Company tests long-lived assets or asset groups for recoverability when events or changes in circumstances indicate that their carrying amount may not be recoverable. Circumstances which could trigger a review include, but are not limited to: significant decreases in the market price of the asset; significant adverse changes in the business climate or legal factors; accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the asset; current period cash flow or operating losses combined with a history of losses or a forecast of continuing losses associated with the use of the asset; and current expectation that the asset will more likely than not be sold or disposed significantly before the end of its estimated useful life.

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2007, 2006 and 2005

Recoverability is assessed based on the carrying amount of the asset and its fair value which is generally determined based on the sum of the undiscounted cash flows expected to result from the use and the eventual disposal of the asset, as well as specific appraisal in certain instances. An impairment loss is recognized when the carrying amount is not recoverable and exceeds fair value.

Debt Issuance Costs

Debt issuance costs will be amortized over the term of the related debt by use of the effective interest method. Amortization commenced June 2006 when the Company began drawing on the related bank loan. Amortization expense for the year ended December 31, 2007 was $214,000 and is included in interest expense. Amortization expense for December 31, 2006 was approximately $52,000 and was included in construction in progress.

Fair Value of Financial Instruments

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

Grants

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

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

Shipping and Handling

The cost of shipping products to customers is included in cost of goods sold. Amounts billed to a customer in a sale transaction related to shipping and handling is classified as revenue.

Income Taxes

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

Differences between financial statement basis of assets and tax basis of assets is primarily related to depreciation, interest rate swaps, derivatives, inventory, compensation and capitalization and amortization of organization and start-up costs for tax purposes, whereas these costs are expensed for financial statement purposes.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of SFAS No. 109” (“FIN 48”). The Interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions.

The Company adopted the provisions of FIN 48 effective January 1, 2007. The adoption of this accounting principle did not have an effect on the Company’s financial statements at, and for the year ended December 31, 2007.

Organizational and Start Up Costs

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

Advertising

The Company expenses advertising costs as they are incurred. Advertising costs totaled approximately $10,000 and $19,000 for the years ended December 31, 2007 and 2006, respectively.

Equity-Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123R”), Share-Based Payment, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. In January 2005, the SEC issued SAB No. 107, which provides supplement implementation guidance for SFAS No. 123R. SFAS No. 123R eliminates the ability to account for stock-based compensation transaction using the intrinsic value method under

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2007, 2006 and 2005

Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and instead generally requires that such transaction be accounted for using a fair-value-based method. The Company adopted the provisions of SFAS No. 123R using the straight-line attribution method. Under this method, the Company recognizes compensation cost related to service-based awards ratably over a single requisite service period.

The Company recognizes the related costs under these agreements using the straight-line attribution method over the grant period and the current fair value unit price. Equity-based compensation expense for the years ended December 31, 2007 and 2006 totaled approximately $20,000 and $25,000, respectively.

Earnings Per Unit

Earnings per unit are calculated on a basic and fully diluted basis using the weighted average units outstanding during the period. Equity-based compensation, representing 200,000 units, is not considered in the fully diluted calculation since they are anti-dilutive in 2006 and 2005 and contingent on future events.

Environmental Liabilities

The Company’s operations are subject to environmental laws and regulations adopted by various governmental entities in the jurisdiction in which it operates. These laws require the Company to investigate and remediate the effects of the release or disposal of materials at its location. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, occupational health and the production, handling, storage and use of hazardous materials to prevent material, environmental or other damage, and to limit the financial liability which could result from such events. Environmental liabilities, if any, are recorded when the liability is probable and the costs can reasonably be estimated. No such liabilities have been identified as of December 31, 2007 and 2006.

Recent Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (“SFAS 157”), Fair Value Measurements . SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. While the Company has not yet performed an evaluation, the Company does not expect the adoption of SFAS 157 to have a significant impact on its financial position or results of operations.

In February 2007, The FASB issued Statement of Financial Accounting Standards No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115 . SFAS 159 permits a company to choose to measure many financial instruments and other items at fair value that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing a company with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. A company shall report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS 159 will be effective for fiscal years that begin after November 15, 2007. While the Company has not yet done an evaluation, it does not believe that the adoption of SFAS 159 will have a significant impact on its financial position or results of operations.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141-R (“SFAS 141R”), Business Combinations , which revised Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS 141”). SFAS 141R is effective for business combinations for fiscal years beginning after December 15, 2008. Under SFAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. SFAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. SFAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under SFAS 141R, adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of SFAS 141R are applied prospectively, the impact cannot be determined until a transaction occurs, if any.

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 (“SFAS 160”), Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 . SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Among other requirements, SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is to be reported as a separate component of equity in the consolidated financial statements. SFAS 160 also requires consolidated net income to include the amounts attributable to both the parent and the noncontrolling interest and to disclose those amounts on the face of the consolidated statement of income. SFAS 160 must be applied prospectively for fiscal years, and is effective for fiscal years beginning after December 15, 2008, except for the presentation and disclosure requirements, which will be applied retrospectively for all periods presented. As the provisions of SFAS 160 are applied prospectively, the impact cannot be determined until a transaction occurs, if any.

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2007, 2006 and 2005

In March 2008, the FASB issued Statement of Financial Accounting Standard No. 161 (“SFAS 161”), " Disclosures about Derivative Instruments and Hedging Activities ”, an amendment of Statement of Financial Accounting Standard No. 133 (“SFAS 133”). SFAS 161 applies to all derivative instruments and nonderivative instruments that are designated and qualify as hedging instruments pursuant to paragraphs 37 and 42 of SFAS 133 and related hedged items accounted for under SFAS 133. SFAS 161 requires entities to provide greater transparency through additional disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. SFAS 161 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2008. No determination has yet been made regarding the potential impact of this standard on the Company’s financial statements.

2. DERIVATIVE INSTRUMENTS

The Company has derivative instruments in the form of futures, call options, put options and swaps related to the purchase of corn and the sale of ethanol. The fair market value of the asset recorded for these derivative instruments totaled approximately $3.2 million and $320,000 as of December 31, 2007 and 2006, respectively. These derivative instruments are not designated as a cash flow or fair value hedge. Gains and losses based on the fair value change in derivative instruments related to corn are recorded in cost of goods sold. During the years ended December 31, 2007 and 2006, the Company recognized gains of $3.1 million and $894,000, respectively. For 2006, the gain was shown in other income as the Company was not yet operational. Gains and losses based on the fair value change in derivative instruments related to ethanol are recorded in revenue. The Company had not entered into any ethanol related derivatives prior to 2007. During the year ended December 31, 2007, the Company recognized a loss on ethanol related derivatives of approximately $2 million. The Company has derivative instruments in the form of interest rate swaps in an agreement associated with bank financing. Fair market value related to the interest rate swap liabilities totaled approximately $1 million and $111,000 as of December 31, 2007 and 2006, respectively. Market value adjustments and net settlements related to these agreements are recorded as a gain or loss from non-designated hedging derivatives in interest expense. During 2006, the market value adjustment was recorded in other income and expense as the Company was not yet operational. See Note 5 for a description of these agreements.

3. INVENTORY

Inventory is valued at lower of cost or market. Inventory values as of December 31, 2007 and 2006 were as follows:

4. BANK FINANCING

Long-term debt consists of the following:

In December 2005, the Company entered into a Credit Agreement with a bank providing for a total credit facility of approximately $59,712,000 for the purpose of funding the construction of the Plant. The construction loan agreement provides for the Company to maintain certain financial ratios and meet certain non-financial covenants. The loan agreement is secured by substantially all of the assets of the Company and includes the terms as described below. The Company incurred interest expense on these loans of approximately $5.1 million in 2007, which is shown in interest expense, and $1.5 million in 2006 which is included in construction in progress.

Construction Loan

The Company had 4 long-term notes (collectively the “Term Notes”) in place as of December 31, 2007. Three of the notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007. The fourth note was entered into during December 2007 (the “December 2007 Fixed Rate Note”) when the Company entered into a second interest rate swap agreement which effectively fixed the interest rate on an additional $10 million of debt. The construction loan agreement requires the Company to maintain certain financial ratios and meet certain non-financial covenants. Each note has specific interest rates and terms as described below.

Fixed Rate Note

The Fixed Rate Note had a balance of $26.6 million outstanding at December 31, 2007. Interest payments are made on a quarterly basis with interest charged at 3.0% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of December 31, 2007, the rate was 8.22375%. 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 January 2012, with a final principal payment of approximately $17,000,000 at April 2012.

Variable Rate Note

During December 2007, $10 million of the Variable Rate Note was transferred to the December 2007 Fixed Rate Note as part of the 4 ^th amendment to the loan agreement. The Variable Rate Note had a balance of $6.77 million at December 31, 2007. Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of December 31, 2007, the rate was 8.62375%. Principal payments are made quarterly according to the terms of the construction loan agreement as amended by the fourth amendment to the construction loan agreement. The amendment calls for quarterly payments of $634,700 applied first to interest on the Long-Term Revolving Note, next to accrued interest on the Variable Rate Note and finally to principal on the Variable Rate Note. Based on the interest rate noted above the Company estimates that the remaining Variable Rate Note will be paid off in October 2010. The Company anticipates the principal payments to be approximately $445,000 per quarter with a final payment of approximately $197,000 in October 2010.

Long-Term Revolving Note

The Long-Term Revolving Note had a balance of $10 million at December 31, 2007. Interest is charged at 3.4% over the one-month LIBOR rate with payments due quarterly. The interest rate is reset monthly. As of December 31, 2007, the rate was 8.4275%. The maturity date of this note is April 2012.

December 2007 Fixed Rate Note

The December 2007 Fixed Rate Note was created by the fourth amendment to the construction loan agreement as noted above. Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate. The interest rate is reset on a quarterly basis. As of December 31, 2007, the rate was 8.22375%. Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $183,000 and increasing to $242,000 per quarter, from January 2008 to January 2012, with a final principal payment of approximately $6,334,000 at April 2012. All unpaid amounts on the three term notes are due and payable in April 2012.

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2007, 2006 and 2005

Revolving Line of Credit

The Company entered into a $3,500,000 line of credit agreement with its bank, subject to certain borrowing base limitations, through July 5, 2008. Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over LIBOR, which totaled 8.22375% at December 31, 2007. The Company has no outstanding borrowings at December 31, 2007, 2006 and 2005.

Interest Rate Swap Agreements

In December 2005, the Company entered into an interest rate swap transaction that effectively fixed the interest rate at 8.08% on the outstanding principal of the Fixed Rate Note. In December 2007, the Company entered into a second interest rate swap transaction that effectively fixed the interest rate at 7.695% on the outstanding principal of the December 2007 Fixed Rate Note.

The interest rate swaps were not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements were recorded as a gain or loss from non-designated hedging activities in other income and expense during 2005 and 2006 and are shown in interest expense in 2007.

For the fiscal years ending December 31, 2007, 2006 and 2005 there were settlements of approximately $39,000, $0 and $0, respectively and market value adjustments resulting in a gains/(losses) of approximately $(933,000), $851,000 and $(278,000), respectively.

Letters of Credit

The construction loan agreement provides for up to $1,000,000 in letters of credit with the bank to be used for any future line of credit requested by a supplier to the Plant. All letters of credit are due and payable at April 2012. The construction loan agreement provides for the Company to pay a quarterly commitment fee of 2.25% of all outstanding letters of credit. In addition, the Company has one outstanding letter of credit for capital expenditures for gas services with Montana-Dakota Utilities Co. The balance outstanding on this letter of credit was $137,000 as of December 31, 2007 and 2006, respectively.

Subordinated Debt

As part of the construction loan agreement, the Company entered into three separate subordinated debt agreements totaling approximately $5,525,000 and received funds from these debt agreements during 2006. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate (a total of 10.62375% at December 31, 2007) 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. The balance outstanding on these loans was $5,525,000 as of December 31, 2007 and 2006, respectively

5. LEASES

The Company leases equipment under operating and capital leases through 2011. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under an operating lease includes rail cars. Rent expense for operating leases was $27,000 and $11,000 and $0 for the years ending December 31, 2007, 2006 and 2005, respectively. Equipment under capital leases consists of office equipment and plant equipment.

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