Red Trail Energy (REGX) 10-K 2008 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934.
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM   ___________ TO ________________

COMMISSION FILE NUMBER: 000-1359687

RED TRAIL ENERGY, LLC

(Exact name of registrant as specified in its charter)

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

P.O. Box 11

3682 Highway 8 South

Richardton, ND 58652

(Address and Zip Code of Principal Executive Offices)

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

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

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

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

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

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

Large accelerated filer o      Accelerated Filer o      Non-accelerated filer o    Smaller Reporting Company x

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

The aggregate market value of the membership units held by non-affiliates of the registrant as of December 31, 2008 was $43,560,069.  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, 2009 the Company has 40,188,973 Class A Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s 2009 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		18
ITEM 3. LEGAL PROCEEDINGS		18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		18
PART II		18
ITEM 5. MARKET FOR REGISTRANT’S MEMBER UNITS, RELATED MEMBER MATTERS AND ISSUER PURCHASED OF EQUITY SECURITIES		18
ITEM 6. SELECTED FINANCIAL DATA		19
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION		20
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		33
ITEM 9A(T). CONTROLS AND PROCEDURES.		33
ITEM 9B. OTHER INFORMATION		34
PART III		34
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.		34
ITEM 11. EXECUTIVE COMPENSATION		34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		34
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		34
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		34
PART IV		34
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		34
Signatures

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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.”

• Our ability to secure a waiver or forbearance agreement for future possible defaults on our loan agreements or renegotiate the terms of our loan agreements with our lenders;

• Our possible future violation of loan covenants under existing loan agreements with our lenders;

• 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;

• Our ability to secure an agreement with our supplier for a proposed corn oil extraction operation;

• 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;

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• 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;

• Ongoing disputes with our management consultant and design-build contractor;

• 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

ITEM 1. BUSINESS.

Overview

Red Trail Energy, LLC (“Red Trail” or the “Company”) owns and operates a 50 million gallon per year (“MMGY”) corn-based ethanol manufacturing plant located near Richardton, North Dakota in Stark County in western North Dakota (the “Plant”). (Red Trail is referred to in this report as “we,” “our,” or “us.”).  We were formed as a North Dakota limited liability company in July 2003.

Fuel grade ethanol and distillers grains are our primary products.  Both products are marketed and sold primarily within the continental United States.  For the year ended December 31, 2008, the Plant produced approximately 54.8 million gallons of ethanol and approximately 103,000 tons of dry distillers grains and 119,000 tons of wet distillers grains from approximately 19.8 million bushels of corn.

General Development of Business

During 2008 the Plant had a successful year operationally but suffered financially from the rapid decline in the overall economy and specifically, the commodities markets, that occurred during the last six months of 2008 and has continued in 2009.

In terms of operations, the Plant produced 54.8 million gallons of ethanol – approximately 110% of nameplate capacity.  Fiscal 2008 was the first full year of the plant operating on powder river basin (“PRB”) coal and the operational benefits continued as the Plant did not experience any down time related to coal quality.  The Plant maintained an excellent safety record during 2008 with no lost time accidents recorded.

At various times during 2008, the Plant asked for, and received, coal with slightly different chemical compositions as we continue to try and meet the emissions requirements of our air quality permits.  We have applied for a new designation from the North Dakota Department of Health (“NDDH”) that would increase the emissions limits relative to our current permits.  As of March 15, 2009 we are still waiting for a decision from the NDDH on our request to be reclassified to a different permit limit.  The Company has maintained very close communication with the NDDH by submitting monthly update reports explaining various trials with different coal quality to show the Company’s best efforts to find a solution to meet certain emissions limits within our air permit.  If we were to receive the new permit, we believe the Plant would run in compliance with the new permit limits if it can continue to receive coal with the correct chemical composition.  The Plant was originally designed to run on lignite coal which is typically higher in emissions than PRB coal.  Problems were encountered with running the Plant on lignite during the first three to four months of operation in 2007 when a decision was made to switch to PRB coal.  Compliance with our air quality permits while running the plant on lignite (higher emission generating) coal was guaranteed by the general contractor that constructed the Plant.  The Company withheld $3.9 million from the general contractor until these issues have been resolved. An amount approximately equal to the final payment has been set aside in a separate money market account. Any amounts remaining in this account after satisfactory resolution of this issue could be used to pay down the Company’s long-term debt, make necessary upgrades to its plant or be used for operations pending bank approval.  We have been in contact with the general contractor on an on-going basis regarding this issue but no progress was made in resolving the issue during 2008 or as of March 2009.

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The Company installed a coal unloading facility adjacent to our Plant site.  The coal unloading facility became operational in September 2008.  Since that time, the Company has seen a decrease in its coal cost of approximately $10 per ton.  On an annual basis, this savings should amount to approximately $900,000 to $1 million.

During 2008, the Company entered into an agreement to operate a third party’s corn oil extraction equipment to be installed in our Plant.  Due to the downturn in the economy that occurred during the last six months of 2008, the third party we contracted with was unable to obtain financing for its operation until December 2008.  The third party is still in the final processes of negotiating the financing and has received initial approval subject to certain conditions.  As part of their financing arrangement, significant changes were made to the original contract we signed in March 2008.  We are still negotiating certain aspects of the agreement with the third party.  As of March 15, 2009, we do not know whether we will be able to reach an agreement on the contract terms nor whether the third party will be able to meet the conditions necessary for final approval of their financing.

In an effort to diversify our revenue stream even further, the Company explored and continues to explore the possibility of selling the carbon dioxide (CO2) generated by the ethanol production process.  Due to the collapse in commodity prices in general and specifically oil prices during the last six months of 2008, the Company was not successful in entering into an agreement to sell its CO2.  We will continue to pursue avenues to sell our CO2.

Financially the Plant suffered during 2008 due to the collapse of the world economy and commodities markets that occurred during the last six months of 2008.  In accordance with industry practice and, due to the location of our Plant, we enter into fixed price contracts for corn to ensure the Plant has an adequate supply to operate.  The Company reaped the benefits of this practice during the first six months of 2008 as corn had been purchased under fixed price contracts whose prices came to be significantly lower than market prices as corn prices rose to record levels in June 2008.  The Company continued to follow its practice of entering into fixed price contracts during this time and, as corn prices declined from July – November, the market price became significantly lower than the fixed prices on those contracts.  For the period January 2008 – November 2008, ethanol prices “tracked” the price of corn.  That is to say, as corn prices increased or decreased, ethanol prices increased or decreased accordingly.  Thus, when corn prices increased during the first six months of 2008 and then declined over the last six months of 2008, ethanol prices increased accordingly and then decreased accordingly.  As a result, the Company had net income of approximately $7.8 million during the first six months of 2008 but incurred net losses of approximately $13.2 million over the last six months of 2008.  This resulted in a net loss for 2008 of $5.4 million.  Counter to traditional fundamentals, corn prices rose during the month of December 2008 but ethanol prices did not rise correspondingly.  This has further exacerbated the Company’s financial situation as the difference between ethanol and corn prices has narrowed to the point where the Company cannot operate at a positive cash flow under these conditions.  Through March 2009 we have seen improvement in the difference between ethanol and corn prices but still not enough for the plant to operate at a positive cash flow.

The losses sustained have put the Company in a difficult financial position and have resulted in the Company violating certain of its loan covenants as of December 31, 2008.  The Company was notified on March 27, 2009 by its senior lender, First National Bank of Omaha (“FNBO” or the “Bank”), that it was in violation of certain loan covenants as of December 31, 2008 and that it has been granted a waiver of those covenant violations.  Our projections show that we will be in violation of certain of our loan covenants during 2009.  As a result of these projected covenant violations, which make it reasonably likely that the Bank will be able to call our long-term debt due and payable during 2009, we have reclassified all of our long-term debt to a current liability on the balance sheet.  As part of our ongoing communication with the Bank we have requested the Bank consider entering into a forbearance agreement.  A forbearance agreement would typically allow the Company to forgo principal payments for a period of time in exchange for an increase in the interest rates on the associated debt along with requirements for the Company to take certain actions and/or maintain or attain certain financial milestones.  There is no certainty that we will be able to reach agreement with the Bank on the terms of a forbearance agreement or that the Bank will grant us waivers for future projected loan covenant violations.  Due to the nature of these uncertainties and the current negative margin structure in the market place, the Company’s ability to continue as a going concern is uncertain.  As such, the Company may be forced to cease operations, declare bankruptcy and/or surrender its assets to the Bank.

The Company has limited ability to raise new capital through either debt financing or equity offerings and is currently exploring its options in this area to allow the Plant to continue to operate.  The Company is also exploring options to partner with all major stakeholders in an effort to maintain the long-term viability of the Company.

The ethanol industry as a whole was hurt by the collapse of the economy and commodities markets.  As of March 15, 2009, estimates indicate that approximately 2.2 billion gallons (roughly 20%) of domestic ethanol production capacity was either shut down or operating at a reduced rate.  The economic downturn has caused a decrease in demand for gasoline which has, in turn, decreased demand for ethanol.  As of January 31, 2009, current demand for ethanol is at an annualized rate of approximately 9.5 billion gallons.  The amount of ethanol required to be blended for 2009 under the Federal Renewable Fuels Standard is 10.5 billion gallons.  We anticipate that, unless market conditions improve, more plants will shut down or slow down which we believe should eventually lead to higher ethanol prices.

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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 12.5 billion gallons as of January 2009.  A significant amount of new production capacity came on-line during 2008 which has had the effect of creating an oversupply of ethanol in the market place.  Due the economic downturn and resulting lower demand for gasoline and less favorable blending economics for oil companies, the demand for ethanol has decreased which has further increased the oversupply of ethanol.

Revenue from the sale of ethanol was approximately 84%, 88% and 0% of total revenues for the years ended December 31, 2008, 2007 and 2006, respectively.

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 60% DDGS and 40% DMWG.

Revenues from sale of distillers grains was approximately 16%, 12% and 0% of total revenues for the years ended December 31, 2008, 2007 and 2006, respectively.

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.

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Ethanol

We have a marketing agreement with RPMG for the purposes of marketing and distributing all of the ethanol we produce at the Plant.  RPMG markets a total of approximately 1 billion gallons of ethanol on an annual basis.  Effective as of January 1, 2008, we 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 Chief Executive Officer (“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 amount is being allocated with approximately 60% going to pay off our ownership buy-in and 40% going to marketing fees.  This fee is expected to decrease to approximately $.005 per gallon once our ownership buy-in is complete, which we expect to occur during 2009.

Distillers Grains

We have a marketing agreement with CHS for the purpose of marketing and selling our DDGS.  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.  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 DMWG internally.  Substantially all of our sales of DMWG 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 we could locate another entity to market the ethanol.  However, any interruption or termination of this relationship could temporarily disrupt the sale and production of ethanol and adversely affect our business and operations and potentially result in a higher cost to the Company.

We are substantially dependent on CHS for the purchase, marketing and distribution of our DDGS. CHS purchases 100% of the DDGS 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 DDGS. In the event that our relationship with CHS is interrupted or terminated for any reason, we believe that another entity to market the DDGS could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale and production of DDGS 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.  Due to other ethanol use mandates, including the Federal Renewable Fuels Standard (“RFS”) which requires a certain amount of ethanol be used each year in the United States, the seasonal effect of the Clean Air Act oxygenation requirement has been reduced.

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 and marketed in the United States.

Sources and Availability of Raw Materials

Corn Feedstock Supply

During 2008, we were able to secure sufficient grain to operate the Plant and do not anticipate any problems securing enough corn during 2009.  We do anticipate that, due to poor growing conditions in our region, at least a portion of the corn we procure will be at a lower quality.  We have typically been able to procure corn that has been graded #2 Yellow.  During January 2009 we procured corn that was graded #3 Yellow.  Due to the lower starch content of this lower grade corn, we have seen an approximate 3% decrease in our yield.  We are working proactively to offset the decrease in yield through various modifications in our production process.  The cost of lower grade corn can be significantly cheaper (than #2 Yellow corn) and we believe we may be able to operate the plant at a break even cash flow level using the offgrade corn.  The amount of offgrade corn that is available will likely represent only a portion of our overall corn needs.  While we cannot accurately predict the volume of offgrade corn we will be able to procure nor the success of this strategy but we believe that, in general, being able to procure some offgrade corn will have a positive impact on our cash flow.

In January 2009, the United States Department of Agriculture’s 2008 Crop Production Summary listed national corn production at approximately 12.1 billion bushels, which is the second largest corn crop on record.  North Dakota produced an estimated 285 million bushels in 2008, which is a record. However, we expect the number of acres of corn planted in North Dakota to decrease in 2009 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 that became operational during 2008.  We expect that this increased demand will lead to greater competition for corn in our geographic area, which could increase the price we pay for corn.  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 without a corresponding increase in the price of ethanol.

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Coal

Coal is also an important input to our manufacturing process. During the fiscal year ended December 31, 2008, we used approximately 97,600 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 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, Inc. (“Fagen”), our design-build contractor, 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 switch back to using lignite coal and meet the emissions requirements of our air quality permits.  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 12-31-07 and Production for the 12 months ended September 30, 2008 (in millions of tons)

State	Estimated Reserves		12 month Production
Wyoming		73,300		465.17
Montana		12,510		44.82
North Dakota		12,520		29.43

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.  As of March 24, 2009, we were notified by Westmoreland that a work stoppage has occurred at the mine from which we normally receive coal.  We have enough coal on hand to operate our Plant for approximately one month.  Westmoreland has more than one mine from which we can purchase coal and we are actively communicating with them to ensure we can receive shipments from another location if the work stoppage is not resolved shortly.

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 Roughrider Electric Cooperative 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.  Our rate for electric usage has increased 18% for fiscal year 2009 as compared to 2008 and 2007.

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.  Our contract requires us to purchase a minimum of 160 million gallons per year.  Our rate for water usage during fiscal year 2009 will be $2.54 per 1,000 gallons.  The rates for fiscal years 2008 and 2007 were $2.49 per 1,000 gallons and $2.45 per 1,000 gallons, respectively.

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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.  The RFS calls for 10.5 billion gallons of corn based ethanol to be blended in 2009.  As of January 2009, the ethanol industry in the United States has an annual production capacity estimated at 12.6 billion gallons which is greater than the amount needed to meet the 2009 RFS requirements.  This oversupply has caused many plants to shutdown or slow down (approximately 20% of production capacity is projected to be off-line or slowed down) and has also had a negative impact on ethanol prices.  If the supply continues to outweigh the demand for ethanol we believe this will have a negative impact on our earnings and our ability to continue to operate the Plant.

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 (4.5 cents per gallon starting January 1, 2009) 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.

On June 18, 2008, the United States Congress overrode a presidential veto to approve the Food, Conservation and Energy Act of 2008 (the “2008 Farm Bill”) and to ensure that all parts of the 2008 Farm Bill were enacted into law.  Passage of the 2008 Farm Bill reauthorizes the 2002 farm bill and adds new provisions regarding energy, conservation, rural development, crop insurance as well as other subjects.   The energy title continues the energy programs contained in the 2002 farm bill but refocuses certain provisions on the development of cellulosic ethanol technology.  The new legislation provides assistance for the production, storage and transport of cellulosic feedstocks and provides support for ethanol production from such feedstocks in the form of grants, loans and loan guarantees.  The 2008 Farm Bill also reduced the VEETC from 51 cents per gallon to 45 cents per gallon beginning in 2009.  The bill also extends the 54 cent per gallon ethanol tariff on imported ethanol for two years, to January 2011.

Other Factors Affecting Demand and Supply

Demand for ethanol may increase as a result of increased consumption of E85 fuel. E85 fuel is a blend of 85% ethanol and 15% gasoline.  According to United States Department of Energy estimates, there are currently more than 7 million flexible fuel vehicles capable of operating on E85 in the United States.  Further, the United States Department of Energy reports that there are currently more than 1,600 retail gasoline stations supplying E85.  The number of retail E85 suppliers increases significantly each year, however, this remains a relatively small percentage of the total number of U.S. retail gasoline stations, which is approximately 170,000.  In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it.  As public awareness of ethanol and E85 increases along with E85’s increased availability, management anticipates some growth in demand for ethanol associated with increased E85 consumption.

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.

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In February 2009, the United States Congress passed the American Reinvestment and Recovery Act (“ARRA”).  Provisions of the ARRA increase a federal income tax credit for alternative fuel infrastructure that was included in the 2005 Act.  The ARRA allows retailers to claim up to 50% or $50,000 of the cost to install or retrofit equipment for dispensing E85 at their facilities.  In addition, the ARRA may further boost the expansion of E85 infrastructure by granting up to $300 million to the Clean Cities Program for implementing Section 721 of the 2005 Act which we believe will increase the demand for ethanol and, in particular, higher blends of ethanol fuel.

In February 2009, Underwriters Laboratories (“UL”) announced that it supports Authorities Having Jurisdiction who decide to permit legacy system dispensers, listed to UL 87, and currently installed in the market, to be used with fuel blends containing a maximum ethanol content of up to 15 percent.  UL stresses that existing fuel dispensers certified under UL 87 were intended for use with ethanol blends up to E10, which is the current legal limit for non-flex fuel vehicles in the United States under the federal Clean Air Act.  However, data gathered by UL through its ongoing research to investigate the impact of using higher ethanol blends in fuel dispensing systems supports that existing dispensers can be used with ethanol blends up to 15 percent.  This indication and announcement may also increase the demand for ethanol.

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, as of January 2009, the ethanol industry has grown to 172 production facilities in the United States.  There are 23 new plants currently under construction along with 4 plant expansions.  North Dakota currently has the capacity to produce over 300 million gallons of ethanol annually.  The Renewable Fuels Association currently estimates that the United States ethanol industry has capacity to produce more than 10.5 billion gallons of ethanol per year.  The new ethanol plants under construction along with the plant expansions under construction could push United States production of fuel ethanol in the near future to nearly 13 billion gallons per year.  The largest ethanol producers include Archer Daniels Midland, Aventine Renewable Energy, Inc., BioFuels Energy Corp, Hawkeye Renewable, POET, The Andersons, Inc. and VeraSun Energy Corporation each of which are capable of producing more ethanol than we produce.  However, VeraSun recently filed for Chapter 11 Bankruptcy which may result in the sale of some or all of VeraSun’s ethanol production facilities.  One of the other large ethanol producers or an oil company may be in a position to purchase the assets of VeraSun which could further consolidate the ethanol industry.

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.  Cellulose is the main component of plant cell walls and is the most common organic compound on earth.  Cellulose is found in wood chips, corn stalks, rice straw, amongst other common plants. Cellulosic ethanol is ethanol produced from cellulose.  Many of the government incentives that have recently been passed, including the expanded Renewable Fuels Standard and the 2008 Farm Bill, have included significant incentives to assist in the development of commercially viable cellulosic ethanol.  Currently, the technology is not sufficiently advanced to produce cellulosic ethanol on a commercial scale, however, due to these new government incentives we anticipate that commercially viable cellulosic ethanol technology will be developed in the near future.  Several companies and researchers have commenced pilot projects to study the feasibility of commercially producing cellulosic ethanol.  If this technology can be profitably employed on a commercial scale, it could potentially lead to ethanol that is less expensive to produce than corn based ethanol, especially if corn prices remain high.  Cellulosic ethanol may also capture more government subsidies and assistance than corn based ethanol.  This could decrease demand for our product or result in competitive disadvantages for our ethanol production process.

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 January 2011.  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.

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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 27 million tons of distillers grains were produced by ethanol plants in 2008. 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 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 (“VOC”) and Particulate Matter (“PM”), 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 (“CEMS”). 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 (“NOx”) 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.

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Our Plant performed emissions compliance testing again on August 13, 2008.  The emissions test results were submitted to the NDDH on September 16, 2008 and noted that, based on the emissions compliance test results, our Plant has not met the conditions in our air permit for the Boiler Common Stack for PM.  The emissions test results did verify that our Plant is in compliance with the pending Air Pollution Control Permit to Construct Amendment application that was submitted to the NDDH on November 26, 2007.

Our Plant performed a Relative Accuracy Test Audit (“RATA”) on our CEMS between September 30, 2008 and October 31, 2008.  The test results were submitted to the NDDH on November 11, 2008 and indicated that the CEMS equipment was operating accurately.

Additionally, the NDDH performed the annual Compliance Evaluation of our Plant on September 16, 2008.  The resulting report from the NDDH indicated “Based on the inspection findings, and on reports submitted to our office, it appears that the facility is in compliance with the applicable Air Pollution Control Rules and with the current Permit to Operate, with exception of DDGS cooling (S01) VOC, Boiler (S60) PM (filterable and condensable) and NOx.”  All three of the exceptions listed in the findings will be in compliance upon  approval of the pending Air Pollution Control Permit to Construct Amendment application discussed above.

Additionally, we worked with our design builders to make modifications and improvements to our Plant’s emission control devices.  We found that these modifications had been successful in reducing emissions levels and the final modifications were installed during our normal maintenance shutdown which took place in 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.

We do not anticipate any capital expenditures for environment control facilities during fiscal 2009 or 2010.  This could change if new federal or state legislation is passed which imposes additional regulation on emissions typical of our Plant.

Employees

We presently have 38 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.

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.

ITEM 1A. RISK FACTORS.

You should carefully read and consider the risks and uncertainties below and the other information contained in this Report. The risks and uncertainties described below are not the only ones we may face. The following risks, together with additional risks and uncertainties not currently known to us or that we currently deem immaterial could impair our financial condition and results of operation.

Risks Relating to Our Business

We may continue to violate the terms of our credit agreements and financial covenants which could result in our lender demanding immediate repayment of our loans.  We have been involved in discussions with our primary lender, FNBO, regarding present and potential future loan covenant violations that have resulted from current conditions in the ethanol industry and our financial condition.  On March 27, 2009, we received notice from FNBO that we were in violation of certain loan covenants as of December 31, 2008.  Also on March 27, 2009, FNBO granted us a waiver of those covenant violations.  We anticipate that we will be in violation of certain of our loan covenants during our 2009 fiscal year.  We are in discussions with FNBO regarding this situation and are pursuing possible modifications to our loan covenants and/or loan agreements (through a forbearance agreement).  However, there is nothing in place at this time and we may not be successful in negotiating revised terms that are favorable to us.  If we violate the terms of our loan, our primary lender could deem us in default of our loans and require us to immediately repay the entire outstanding balance of our loans. If we do not have the funds available to repay the loans or we cannot find another source of financing, FNBO could seize our assets without compensation to the Company.

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Our audit report contains a going concern qualifier which may impede our access to normal trade credit from our vendors.  Due to uncertainties disclosed in Note 3 to our financial statements which are also disclosed in the “General Development of Business” section above, our Company’s ability to continue as a going concern may be uncertain.  While we believe that the forbearance agreement we are currently negotiating with our Bank along with other cost cutting and revenue enhancing measures we are implementing will allow us to continue to operate, our vendors may not be willing to extend us normal trade credit which could further impact our ability to survive as a going concern.

Our inability to secure credit facilities we may require in the future may negatively impact our liquidity.  Due to current conditions in the credit markets, it has been increasingly difficult for businesses to secure financing.  Although we do not currently require more financing (as of December 31, 2008) than we have, our projections, based on current market conditions, show that, in the future, we may need additional financing.  If we require financing in the future and we are unable to secure such financing, or we are unable to secure the financing we require on reasonable terms, it may have a negative impact on our liquidity.  This could negatively impact the value of our units.

Our member control agreement contains restrictions that make it very difficult to raise additional equity.  Our member control agreement requires that we receive written consent from all of our members in order to sell additional units in the Company unless we sell units in an intrastate offering.  We have over 900 members which we believe would make it difficult, if not impossible, to receive written consent from all members.  This restriction imposes a limitation that makes it difficult for the Company to sell units to raise needed capital and may significantly harm the Company and value of your units.  We are currently evaluating our member control agreement to eliminate this restriction.

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.  During the period January 2008 through November 2008 the spread between corn and ethanol prices remained fairly constant as ethanol prices tended to increase or decrease in tandem with corn prices.  However, this spread decreased during December 2008 as corn prices rose by approximately $1 per bushel and ethanol prices did not increase.  While we have seen some slight improvement in the spread between corn and ethanol prices during January and February of 2009, the spread has narrowed to the point where our Plant cannot maintain a positive cash flow from operations.  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 financial performance is significantly dependent on corn prices and generally we cannot pass on increases in corn prices to our customers.  Our results of operations and financial condition are significantly affected by the cost and supply of corn. Changes in the price and supply of corn are subject to and determined by market forces over which we have no control.  Ethanol production requires substantial amounts of corn. Corn, as with most other crops, is affected by weather, disease and other environmental conditions. The price of corn is also influenced by general economic, market and government factors. These factors include weather conditions, farmer planting decisions, domestic and foreign government farm programs and policies, global supply and demand and quality. Changes in the price of corn can significantly affect our business. Generally, higher corn prices will produce lower profit margins and, therefore, represent unfavorable market conditions. This is especially true if market conditions do not allow us to pass along increased corn costs to our customers. The price of corn has fluctuated significantly in the past and may fluctuate significantly in the future.  We cannot offer any assurance that we will be able to offset any increase in the price of corn by increasing the price of our products. If we cannot offset increases in the price of corn, our financial performance may be adversely affected.  We seek to minimize the risks from fluctuations in the prices of corn through the use of hedging instruments. However, these hedging transactions also involve risks to our business. See “Item 1A. Risks Relating to Our Business — We engage in hedging transactions which involve risks that can harm our business.”

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 or options 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.

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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.

We have withheld $3.9 million from our design-builder, 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, 2009 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 and meet the emissions requirements in our air quality permits; however, the coal combustor has not run consistently on lignite coal and we suffered plant shut-downs during early 2007 as a result.  In addition, while running on lignite coal and subsequently, while running on cleaner burning PRB coal, we have not been able to maintain compliance with our air quality permits.  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.

Declines in the price of ethanol or distiller’s grain would significantly reduce our revenues. The sales prices of ethanol and distiller’s grains can be volatile as a result of a number of factors such as overall supply and demand, the price of gasoline and corn, levels of government support, and the availability and price of competing products.  Recently, the price of ethanol and distiller’s grains have trended downward as the prices of corn and gasoline have fallen.  We are dependant on a favorable spread between the price we receive for our ethanol and distiller’s grains and the price we pay for corn, coal and electricity.  Any continued lowering of ethanol and distiller’s grains prices, especially if it is associated with increases in corn, coal and electricity prices, may reduce our revenues and affect our ability to operate profitably.  Based on financial forecasts performed by our management, we anticipate that due to current ethanol and distiller’s grains prices compared to the costs of the raw materials required to make them, the Plant may operate unprofitably during the early part of our 2009 fiscal year.  As a result, management decided to reduce production at the Plant in January 2009.  We will use this opportunity to try and enhance Plant efficiencies.  We anticipate continually evaluating the profitability of operating the Plant and increasing or decreasing production by the Plant accordingly.

The average price we received for our ethanol and co-products, on a per gallon basis, increased by approximately 16% during our 2008 fiscal year compared to our 2007 fiscal year, however the price we paid for corn increased by approximately 40% during the same time periods.  We anticipate the price of ethanol and distiller’s grains to continue to be volatile during our 2009 fiscal year as a result of the net effect of changes in the price of gasoline and corn and increased ethanol supply offset by increased ethanol demand.  Continued declines in the prices we receive for our ethanol and distiller’s grains will lead to decreased revenues and may result in our inability to operate the Plant profitably for an extended period of time which could decrease the value of our units.

Our financial performance is significantly dependent on coal prices and generally we cannot pass on increases in coal prices to our customers.  The prices for and availability of coal may be subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices as a result of colder than average weather conditions, overall economic conditions, including energy prices, and foreign and domestic governmental regulations and relations. Significant disruptions in the supply of coal could impair our ability to manufacture ethanol for our customers. Furthermore, long-term increases in coal prices or changes in our costs relative to energy costs paid by competitors may adversely affect our results of operations and financial condition.  Coal prices are considerably higher than the 10-year average, due to increased economic and industrial activity in the United States and internationally, most notably China. We assume that there will be continued volatility in the coal markets. Any ongoing increases in the price of coal will increase our cost of production and may negatively impact our future profit margins.

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.  As of March 24, 2009, we were notified by Westmoreland that a work stoppage has occurred at the mine from which we normally receive coal.  We have enough coal on hand to operate our Plant for approximately one month.  Westmoreland has more than one mine from which we can purchase coal and we are actively communicating with them to ensure we can receive shipments from another location if the work stoppage is not resolved shortly.

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

• effectively manage our business and operations;

• recruit and retain key personnel;

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

• manage rapid growth in personnel and operations;

• develop new products that complement our existing business; and

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

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

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 belief 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.

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.  During 2008, we successfully operated our Plant at approximately 110% of nameplate capacity.  However, in the event our Plant is not capable of operating 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.

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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 and an ongoing work stoppage at Westmorland.

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.

We sell all of the ethanol we produce to RPMG in accordance with an ethanol marketing agreement and we rely heavily on RPMG’s marketing efforts for our ethanol distribution. 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 are running the Plant using PRB coal instead of lignite coal and may have to repay, at an accelerated rate,  the lignite grant we received from the State of North Dakota. 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 the years ended December 31, 2007 and 2008, 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.

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

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.

We may not be financially able to install corn oil extraction equipment at our Plant site.  We entered into a contract during March 2008 to operate a third party’s corn oil extraction equipment that was to be installed at our Plant site.  Due to the downturn in the economy and resulting global economic crisis, the third party was not able to obtain financing for their project.  Recently, they have entered into a financing arrangement that is contingent upon completion of certain conditions.  As a result of this new financing arrangement, the terms of our original contract have been substantially modified.  We are currently negotiating some of the terms of the contract with the third party but there is no guarantee they will agree to the changes we have suggested.  In the event they do not agree to the changes it is unlikely we would be able to obtain financing to install the corn oil extraction equipment on our own.  While we currently do not have any revenue from corn oil extraction, not being able to install this equipment will hurt our effort to diversify our revenue stream and may adversely impact the financial viability of our Plant.

We are seeking to install corn oil equipment at our Plant. If we are successful, 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 we expect to produce 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 we expect to produce at our Plant.  

Risks Related to Conflicts of Interest

Our board of governors has elected to withhold payment to Greenway for services provided under the terms of the Management Agreement.  The Management Agreement (“MA”) that is in place between our Company and Greenway calls for annual payment of $200,000 plus 4% of the net income of the Plant to be paid on a quarterly basis.  The MA does not specifically state whether the payment related to 4% of the net income of the Plant is to be determined on a quarterly basis or on an annual basis.  During 2008, we paid Greenway based on our quarterly net income even though we ended the year at a net loss.  Our governors feel the contract should be interpreted such that the 4% of net income payment would be based on our annual net income and that we should not have paid Greenway any funds during the year ended December 31, 2008.  As a result, the board has elected not to pay Greenway the $200,000 annual payment starting in January 2009.  This could create conflict between Greenway and our Company that may adversely affect Greenway’s willingness to continue assisting the Company or could even result in Greenway taking legal action against the Company to recover these funds.  We cannot be sure of the result of any such potential lawsuit and if commenced, and the Company is not successful, a financial award against the Company could have an adverse material impact on our financial condition.

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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 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 difficulty 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.

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 President and CEO, in his capacity as an RPMG board member, 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.

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 and cash available to pay debt obligations and expenses.

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.

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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 Bank. 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. We believe that the disconnect that occurred between corn and ethanol prices during December 2008 was due to an oversupply of ethanol in the market place.  Demand for ethanol decreased during 2008 as demand for gasoline decreased first, in response to record high oil and gas prices that were present during 2008 and second, due to the global economic crisis that started during the third quarter of 2008.  Because of this oversupply and the resulting negative cash flow margins created by the decrease in the spread between corn and ethanol prices, many plants have been forced to shut down or operate at a reduced capacity.  Estimates show that enough capacity has currently been idled to bring ethanol production capacity more in line with current ethanol demand.  We believe the industry is going to operate in a period of fluctuating supply and demand until the demand increases to meet total available ethanol production capacity.

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.

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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 January 2011.  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.

Negative media attention associated with the use of corn in the ethanol production process may lead to decreases in demand for the ethanol we produce which could negatively affect our profitability.  Recent media attention associated with the use of corn as the feedstock in ethanol production has been unfavorable to the ethanol industry.  This negative media attention has focused on the effect ethanol production has on domestic and foreign food prices.  While some recent media reports have recognized that food prices have remained high despite significant decreases in the price of corn following peaks in early July 2008, some of this negative perception of ethanol production may persist.  Ethanol production has previously received favorable coverage by the news media which may have increased demand for ethanol.  This negative perception of ethanol production may have a negative effect on demand for ethanol which may decrease the price we receive for our ethanol.  Decreases in the selling price of ethanol may have a negative effect on our 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 higher blends of ethanol, up to 85% ethanol.

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

The use of coal as a fuel source could limit the markets in which ethanol produced at our Plant can be marketed.  At least one state (California) has recently initiated the development a “low-carbon fuel standard” to reduce the carbon intensity of transportation fuels used within the state.  Such a standard is expected to be developed using a lifecycle approach meaning that carbon emissions resulting from the production process would increase the carbon intensity of the fuel produced.  Since we are a coal fired Plant we may not be able to market our ethanol in California and other states that develop such standards.  This could potentially have a severe negative impact on the viability of our Plant unless we can devise a way to limit our carbon emissions.  We have started to explore alternatives for reducing our carbon emissions there is no guarantee we will be able to find an acceptable, cost effective process for doing so.

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.

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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.

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 and the 2008 Farm Bill. The provision of the Energy Independence and Security Act of 2007 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 10.5 billion gallons of corn based ethanol to be produced in 2009, growing to 36 billion gallons in 2022, 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.

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.

ITEM 2. PROPERTIES.

The Plant is located just east of the city limits of Richardton, North Dakota, and just north and east of the entrance/exit ramps to Highway I-94. The Plant complex is situated inside a footprint of approximately 25 acres of land which is part of an approximately 135 acre parcel.  We acquired ownership of the land in 2004 and 2005. Included in the immediate campus area of the Plant are perimeter roads, buildings, tanks and equipment. An administrative building and parking area are located approximately 400 feet from the Plant complex.  During 2008 we purchased an additional 10 acre parcel of land that is adjacent to our current property.  Our coal unloading facility and storage site was built on this property.

ITEM 3. LEGAL PROCEEDINGS.

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

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

We did not submit any matter to a vote of our unit holders through the solicitation of proxies or otherwise during the fourth quarter of 2008.

PART II

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

Market Information

There is no established trading market for our membership units.  We have engaged Alerus to create a Qualified Matching Service (“QMS”) in order to facilitate trading of our units.  The QMS consists of an electronic bulletin board that provides information to prospective sellers and buyers of our units.  The average price of all trades on the QMS that occurred during the year ended December 31, 2008 was $1.19 per unit.  The average was calculated based on a total of 451,000 units that were traded in ten separate transactions during the year ended December 31, 2008.  During 2008, the highest trade occurred at $1.30 per unit and the lowest trade occurred at $1.00 per unit.  The average price of all trades on the QMS that occurred during the year ended December 31, 2007 was $2.00 per unit.  The average was calculated based on a total of 21,000 units that were traded in five separate transactions during the year ended December 31, 2007.  During 2007, the highest trade occurred at $2.25 per unit and the lowest trade occurred at $1.75 per unit.  We do not become involved in any purchase or sale negotiations arising from the QMS and we take no position as to whether the average price, or the price of any particular sale is an accurate gauge of the value of our units.  We have no role in effecting the transactions beyond approval, as required under our Operating Agreement and the issuance of new certificates.  So long as we remain a public reporting company, information about us will be publicly available through the SEC’s EDGAR filing system.  However, if at any time we cease to be a public reporting company, we may continue to make information about us publicly available on our website.

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Unit Holders

As of March 15, 2009, we had 40,188,973 Class A Membership Units outstanding and a total of 947 membership unit holders. There is no other class of membership units issued or outstanding.  In December 2007, we acquired and held 200,000 units in treasury related to equity based compensation agreements for our President and Plant Manager.  These units vest and will be issued over a ten year term as stated in the agreements.  During the year ended December 31, 2008, 15,000 units vested and were issued pursuant to the terms of the equity based compensation agreements.

Distributions

We did not make any distributions to our members for the fiscal years ended December 31, 2008 or 2007. Distributions are payable at the discretion of our Board, subject to the provisions of the North Dakota Limited Liability Company Act and our Member Control Agreement. Distributions to our unit holders are also subject to certain loan covenants and restrictions that require us to make additional loan payments based on excess cash flow. These loan covenants and restrictions are described in greater detail under “ Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources.” We may distribute a portion of the net profits generated from Plant operations to unit holders. A unit holder’s distribution is determined by dividing the number of units owned by such unit holder by the total number of units outstanding. Our unit holders are entitled to receive distributions of cash or property if and when a distribution is declared by our Board. Subject to the North Dakota Limited Liability Company Act, our Member Control Agreement and the requirements of our creditors, our Board has complete discretion over the timing and amount of distributions, if any, to our unit holders. There can be no assurance as to our ability to declare or pay distributions in the future.

Purchases of Equity Securities

During December 2007, we exercised an option to purchase 200,000 units from a member for use in employee compensation plans.  The only existing plans are in place for our President and Plant Manager.  These plans provide for the issuance of membership units pursuant to a 10-year vesting schedule with full vesting occurring on July 1, 2015 and June 15, 2016, respectively.

We did not purchase any equity securities during the year ended December 31, 2008.

Unregistered Sales of Equity Securities.

We did not have any unregistered sales of equity securities during the year ended December 31, 2008.

ITEM 6. SELECTED FINANCIAL DATA.

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

We have been involved in discussions with our primary lender, FNBO, regarding present and future loan covenant violations that have resulted from current conditions in the ethanol industry and our financial condition.  Due to uncertainty regarding our ability to meet these covenants in the future, we have classified this debt as a current liability as of December 31, 2008.  For more information about our financial condition, please see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation” and Note 3 to the financial statements that appear elsewhere in this Annual Report on Form 10-K.

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Statement of Operations

For the year Ended December 31,	2008				2007			2006				2005			2004
Revenues, net of derivative loss		$	131,903,514			$	101,885,969		$	―		$	―		$	―
Cost of goods sold			131,025,238				87,013,208			―			―			―
Gross margin			878,276				14,872,761			―			―			―
General and administrative expenses			2,857,091				3,214,002			3,747,730			2,087,808			433,345
Operting income (loss)			(1,978,815	)			11,658,759			(3,747,730	)		(2,087,808	)		(433,345	)
Interest expense			6,013,299				6,268,707			―			―			―
Other income, net			2,625,542				767,276			1,243,667			360,204			147,004
Net income (loss)		$	(5,366,572	)		$	6,157,328		$	(2,504,063	)	$	(1,727,604	)	$	(286,341	)
Weighted average units - basic			40,176,974				40,371,238			39,625,843			24,393,980			3,591,180
Weighted average units - fully diluted			40,226,974				40,416,238			39,650,843			24,401,480			3,591,180
Net income (loss) per unit - basic		$	(0.13	)		$	0.15		$	(0.06	)	$	(0.07	)	$	(0.08	)
Net income (loss) per unit - fully diluted		$	(0.13	)		$	0.15		$	(0.06	)	$	(0.07	)	$	(0.08	)

Balance Sheet Data	2008			2007			2006
Cash and equivalents		$	4,433,839		$	8,231,709		$	421,722
Total current assets			15,372,678			25,733,307			4,761,974
Net property, plant and equipment			78,010,042			81,942,542			84,039,740
Total assets			94,751,401			108,524,254			89,864,228
Total current liabilities			60,917,396			16,807,461			9,781,240
Other noncurrent liabilities			275,000			275,000			275,000
Long-term debt			―			52,538,310			46,878,960
Members' equity			33,559,005			38,903,483			32,929,088
Book value per weighted share		$	0.84		$	0.96		$	0.83

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

Except for the historical information, the following discussion contains forward-looking statements that are subject to risks and uncertainties. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the risks described in “Item 1A — Risk Factors ” and elsewhere in this Annual Report on Form 10-K. Our discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and related notes and with the understanding that our actual future results may be materially different from what we currently expect.

Overview

We operate a 50 MMGY name-plate ethanol plant near Richardton, North Dakota. Construction of the Plant began in 2005 and was completed in December 2006.

Since January 2007, our revenues have been derived from the sale and distribution of ethanol and distillers grains throughout the continental United States.  During the year ended December 31, 2008, we produced approximately 54.8 million gallons of ethanol (approximately 110% of name-plate capacity).  We also produced approximately 103,000 tons of DDGS and 119,000 tons of DMWG.

While our Plant operated consistently throughout the year, our financial performance was severely impacted by unprecedented volatility in the commodities markets and the collapse of the world economy and financial markets that started in August 2008.  Our results of operations and how this volatility impacted our financial results are described in greater detail below.

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Results of Operations

Comparison of Fiscal Years Ended December 31, 2008, 2007 and 2006

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, 2008, 2007 and 2006:

For the years ended December 31,	2008						2007						2006
	Amount			Percent			Amount			Percent			Amount			Percent
Revenues, net of derivative loss	$	131,903,514			100.00	%	$	101,885,969			100.00	%	$	―			―
Cost of goods sold		131,025,238			99.33	%		87,013,208			85.50	%		―			―
Gross margin	$	878,276			0.67	%	$	14,872,761			14.50	%	$	―			―
General and administrative expenses		2,857,091			2.17	%		3,214,002			3.20	%		3,747,730			―
Operating income (loss)	$	(1,978,815	)		-1.50	%	$	11,658,759			11.40	%	$	(3,747,730	)		―
Interst expense	$	(6,013,299	)		-4.56	%	$	(6,268,707	)		-6.20	%	$	―			―
Other income (expense)
Grant income		73,207			0.06	%		27,750			0.00	%		―			―
Interest income		426,233			0.32	%		432,265			0.40	%		182,277			―
Other income		2,126,102			1.61	%		307,261			0.30	%		1,061,390			―
Net income (loss)	$	(5,366,572	)		-4.07	%	$	6,157,328			5.90	%	$	(2,504,063	)		―

Additional Data for the year ended December 31,	2008		2007
Ethanol sold (thousands of gallons)		55,148		50,184
Ethanol average sales price per gallon (net of hedging activity)	$	2.01	$	1.82
Dried distillers grains average sales price per gallon of ethanol sold	$	0.25	$	0.24
Corn costs per gallon of ethanol sold (net of hedging activity)	$	1.97	$	1.37
Corn costs per bushel (net of hedging activity)	$	5.19	$	3.78

Revenues

2008 compared to 2007

During 2008, our total revenues increased by 29.5% to $131.9 million.  Ethanol and distillers grains represented 84% and 16% of 2008 revenue, respectively.  The increase in revenue is attributable to a number of factors, including:

•       Ethanol prices, net of hedging activity, averaged 10% higher in 2008 than 2007 ($2.01 per gallon in 2008 vs. $1.82 per gallon in 2007).  We believe ethanol prices were higher overall due to the increase in commodity prices (primarily corn, crude oil and gasoline) during the first six months of 2008.  We believe ethanol prices are generally positively impacted by higher corn, gasoline and crude oil prices.  All three of these commodities reached record prices in late June/early July 2008.  The average price we received for ethanol during 2008 ranged from $1.46 to $2.50.  The high was achieved in June 2008.  Prices steadily declined the rest of the year to the low of $1.46 received in December.  We believe the decrease was again due to the decrease in corn, crude oil and gasoline prices the last half of the year along with decreases in demand for these commodities as well as ethanol due to the collapse of the world economy.

•    Distillers grains – Our 2008 distillers grain sales volumes were roughly split 50-50 between DDGS and DMWG.  Prices received by us for DDGS ranged from $126 to $157 per ton during 2008 with our average selling price for the year being approximately $136 per ton.  The price of DDGS generally follows the price of corn so, as corn prices increased during the first half of 2008, the price we received for DDGS also increased to the high of $157 per ton received in June 2008.  Prices have since declined along with corn prices and we received an average price of approximately $135 per ton in December 2008.  Due to the high quality of our DDGS and the markets in which our product is typically sold we have been able to capture a small premium for our DDGS relative to other markets and plants.  Due to this premium, the price we receive for DDGS actually increased slightly from September 2008 through December 2008.  Prices received by us for DMWG ranged from $50 to $75 per ton with our average selling price for the year being approximately $56 per ton.  Prices for DMWG also follow the price of corn and, as such, our price for DMWG peaked in July 2008 and steadily declined the rest of the year.  Our price was also positively impacted, compared to 2007, due to a change made in our contract pricing to index the price we receive for DMWG to the price of corn.  All of our 2007 contracts were based on a flat pricing schedule.

•       During 2008 we recognized a loss on hedging from ethanol derivative instruments of approximately $2.4 million.  We held some ethanol swap contracts through July 2008.  The value of these swap contracts decreased as ethanol prices increased during the first half of 2008.  We exited the swaps as ethanol prices started to decrease in July 2008.  These losses are included in revenue on our financial statements.

2007 compared to 2006

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

•    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.

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•      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 – ethanol prices have remained relatively constant during the January and February of 2009.  We anticipate that ethanol prices will continue to increase or decrease with the price of corn, gasoline and crude oil.  There has been a significant decrease in demand for both oil and gas but we believe that production cuts for both of those products may increase their respective prices during 2009.  We believe this, along with a decrease in supply of ethanol due to plant shutdowns and slow downs, will have a positive impact on ethanol prices later in 2009 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.  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 are currently negotiating the terms of an agreement to add corn oil extraction equipment to our facility.  At this time we are not certain whether we will be able to reach agreement with the counter party to the agreement.  If we do reach an agreement, we project that the equipment will be operational during the third quarter of 2009.

Cost of Goods Sold and Gross Margin

Our gross margin is very sensitive to fluctuations in the spread between ethanol and corn prices.  From January 2008 – November 2008, ethanol prices generally increased and decreased with the price of corn, maintaining a spread between the prices of the two commodities that would have allowed our Plant to maintain at least a positive cash flow if we would have purchased corn and sold ethanol at the average market prices for those months.  During December 2008, corn prices increased without a corresponding increase in the price of ethanol causing the spread between ethanol and corn prices to narrow to the point where our Plant could not maintain a positive cash flow.  While the spread has improved slightly during January and February 2009, we are still operating at a negative cash flow.  If the spread between corn and ethanol prices does not improve to the point where our Plant can operate at a positive cash flow, we may be forced to shut down and this may adversely impact our ability to continue as a going concern.

2008 compared to 2007

Our gross margin for 2008 was approximately $900,000.  Our total cost of goods sold per gallon of ethanol produced increased by 38% compared to 2007 ($2.39 per gallon vs. $1.73 per gallon).  The increase in cost of goods sold is attributable to a number of factors including:

•    Corn cost – our corn costs per gallon of ethanol produced increased 42.5% during 2008.  As an end user of corn we typically enter in to fixed price contracts to ensure an adequate supply of corn to operate our Plant.  We reaped the benefits of this strategy during the first seven months of the year as we had entered in to fixed price contracts to purchase corn at prices that became significantly under the market value of corn as commodity prices increased to their peak in late June/early July 2008.  Because ethanol prices increased along with corn prices we were able to operate profitably during this period.  The decrease in prices during the last half of 2008 had the opposite effect on our margins as we had entered in to fixed price contracts to purchase corn at prices that became significantly higher than the market value of corn.  Because ethanol prices decreased along with corn prices we incurred significant losses during this period which more than offset the profit earned during the first six months of 2008.  Further exacerbating our losses was the fact that we had to accrue losses on the corn under fixed price contracts that had not yet been delivered.  We recognized a loss on firm purchase commitments of approximately $3.1 million during the third quarter of 2008 and had approximately $1.4 million accrued as of December 31, 2008.  Our total loss on firm purchase commitments for 2008 was approximately $3.7 million.  In addition, we had to write down our corn and ethanol inventory to the lower of cost or market.  As of December 31, 2008 this amounted to a write down of $212,000 for corn inventory and $559,000 for ethanol.

•    Partially offsetting the increase in corn costs were gains recognized from our corn hedging activities of approximately $5.9 million.  The losses we sustained during 2008 along with difficulties we encountered in trying to raise additional short term liquidity through increasing our short term line of credit have left us with an amount of available capital that will not allow us to take aggressive hedge positions even if the opportunity arises where we could lock in a margin using either corn or ethanol related derivative instruments.

•    Other cost of goods sold – our other cost of goods sold consists primarily of chemical ingredients, depreciation, repairs, energy and labor needed to operate the Plant.  We experienced increases in our chemical, coal and repair costs during the year.  Chemical costs increased due to price increases for some of our main chemicals (including anhydrous ammonia, sodium bicarbonate and sulfuric acid) as world demand for these chemicals increased causing a shortage in supply.  Our coal costs increased due to running a full year on more expensive PRB coal during 2008.  Repair costs increased as we entered our second year of operation and took the Plant down for two scheduled maintenance outages.

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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 –  corn prices have remained fairly constant during January and February 2009.  We cannot be certain how the price of corn will change as it is a market driven commodity.  At the end of 2008 we reorganized our corn procurement strategy and are focused on building relationships with and purchasing more of our corn needs from local farmers.  We believe this will have a positive impact on our gross margin as corn purchased from farmers is typically lower priced than corn purchased via unit trains.  We anticipate that we will continue to contract with local farmers but will not contract as far out into the future as we have in the past.  As our working capital position allows, we also intend to use corn derivative instruments to hedge a portion of our corn needs.

•    Energy needs – we have contracts in place for our main energy needs.  See below for information on our main energy costs:

•    Coal – we have a contract in place through the end of 2009 for coal supply.  We anticipate entering in to a new contract this year with similar terms to what we had in the past.  Our current two year agreement allowed for a small per ton increase in the second year.  We anticipate that our coal costs, including freight and unloading costs, will be lower than 2008 due to the successful implementation of our coal unloading facility during September 2008.  During the fourth quarter of 2008, our coal costs averaged approximately $10 per ton less than the first three quarters.  We expect to maintain this cost savings throughout 2009.

•    Electricity – we have an agreement with Roughrider Electric for our electric needs.  This contract does not offer price protection, however, and we have received notice that our rates will increase 18% in 2009 compared to 2008 rates.

•    Chemicals – we have contracts in place for our chemical supply needs.  The contracts call for competitive market pricing.  We anticipate that our chemical costs will be lower than 2008 due to decreasing prices for some of our main chemicals as world wide demand has decreased due to the global economic slow down.  As we have fine tuned our production process we have also lowered our usage of certain chemicals due to requesting coal of a certain chemical makeup from our coal supplier in addition to other process related changes.  The corresponding reduction in chemical usage has decreased our chemical costs.  We anticipate our costs to continue to be lower as long as our coal supplier is able to provide coal with requisite chemical makeup.

•   

•    Labor costs – due to our current financial situation, we temporarily suspended our employee bonus program during the fourth quarter of 2008.  We also eliminated management bonuses for the year ended December 31, 2008.  If our financial condition does not improve, we anticipate that our labor costs will be slightly lower during 2009 as our bonus programs will not be reinstated until we see improvement financially.

General and Administrative Expenses

2008 compared to 2007

General and administrative expenses decreased approximately $357,000 (11.1%) primarily due to:

•    A decrease of approximately $594,000 in professional service fees (including legal, consulting on permits and other professional services) as our employees started to take over additional responsibilities in these areas in an effort to reduce our dependence on outside services.

The decrease in general and administrative costs was partially offset by:

•    An increase in our real estate taxes of approximately $157,000 as 2008 represented the first year of the phase-out of our tax exemption.

•    An increase in accounting fees of approximately $60,000 primarily related to additional audit costs associated with our first full year of operation along with additional travel costs as we had our audit firm travel to our site for our quarterly reviews during 2008.

2007 compared to 2006

General and administrative expenses decreased approximately $534,000 (14.2%) primarily 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.

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•    $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.

Prospective Information:

•    We anticipate our general and administrative expenses for 2009 to be similar to 2008.  We are scheduled to have an increase in our real estate taxes of approximately $157,000 as we enter the second year of the phase out of our tax exemption.  We have requested a full exemption of our real estate taxes due to the financial difficulties facing our Plant but were turned down. We are planning to continue to communicate with local real estate tax commission but cannot be certain of the outcome.  We anticipate continuing to decrease our reliance on outside consultants as we continue to transition more duties to our employees but we cannot be certain that these goals will be met due to our changing business climate.

Interest Expense

Our interest costs for the fiscal years ended December 31, 2008 and 2007 were approximately $6.0 million and $6.3 million, respectively.  We incurred interest costs of approximately $1.5 million during the fiscal year ended December 31, 2006 which was related to plant construction and capitalized accordingly.

•    2008 interest expense – includes approximately $4.0 million of interest expense on our long-term debt, a loss of approximately $1.8 million related to the change in market value of our interest rate swaps and approximately $200,000 of expense related to amortization of our capitalized financing costs.  Interest costs on our long-term debt were lower in 2008 due to lower interest rates and also lower outstanding debt balances for a portion of the year as we paid down part of our Long-Term Revolving Note as a way to use our excess cash earlier in the year.  The change in the market value of our interest rate swaps was higher than 2007 as interest rates reached record low levels toward the end of 2008 causing the value of our swaps to decline.

•    2007 interest expense - includes approximately $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.

•    2006 interest expense – we had approximately $1.5 million of interest expense on our long-term debt during 2006 all of which was related to plant construction and capitalized accordingly.

Interest rates trended downward for much of 2008 which caused the value of our interest rate swaps to decrease.  As interest rates reached record low levels at the end of 2008 we do not anticipate that they will continue to decrease.  Rates did increase slightly in January 2009.  We do not feel we can accurately predict interest rates for the rest of 2009 as it remains to be seen what impact the government attempts to stimulate the global economy worldwide will have on interest rates.  In general, an increase in interest rates will have a positive impact on the value of our interest rate swaps but will increase the amount of interest we pay on the variable interest rate portion of our notes.

Other Income and Expense

Other income includes payments from our state ethanol incentive program, interest income and grant income.  Other income, net was approximately $2.6 million, $800,000, and $1.2 million for the fiscal years ended December 31, 2008, 2007 and 2006, respectively.

During 2008, conditions were met that triggered payments to be made under the state of North Dakota’s ethanol incentive program.  We received approximately $2.1 million under this program during 2008.  We did not receive any payments during the years ended December 31, 2007 or 2006, respectively.  The program ran out of funds at the end of 2008 and will not be funded again until June 2009.  We cannot accurately predict how much we may receive from this program in the future but anticipate that it will most likely be significantly less than the amount received in 2008 and could ultimately be $0.

Interest income was approximately $426,000, $432,000 and $182,000 for the fiscal years ended December 31, 2008, 2007 and 2006, respectively.

•    2008 interest income – primarily the result of interest earned on sales and use tax paid during Plant construction.  We received an exemption from sales and use tax for items used in the construction of our Plant.  Because our general contractor paid for most of the items and then billed us they had to pay the requisite sales and use tax and then turn around and request a refund of those amounts.  Due to the volume of invoices for materials used to construct the Plant a refund request was not completed until June 2008.  We have received a portion of the refund along with interest. The interest portion totaled approximately $380,000.  The remaining interest income of approximately $46,000 was derived from excess operating cash and approximately $4.2 million set aside to cover the final construction costs that have not been paid to our general contractor.

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•    2007 interest income – primarily the result of funds held in money market accounts.  The funds consisted of excess operating cash along with approximately $3.9 million set aside to cover the final construction costs that have not been paid to Fagen.

•    2006 interest income – primarily from holding funds raised from members in money market accounts.

Approximately 60% of the requested sales and use tax refund was denied by the state of North Dakota due to improper documentation.  Our general contractor is working on supplying the appropriate information so the refund can be processed.  If we were to receive the remaining portion of the refund we anticipate that our interest income would be similar to the amount received in 2008.  We cannot accurately predict the amount of the refund and corresponding interest income that will be received.  We do anticipate receiving interest income on the cash set aside to pay our general contractor for the final construction costs but feel the amount will not be material.

Because we had not yet started the production and sale of ethanol, 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.  Starting in 2007, we recorded gains (losses) associated with our corn derivative instruments in cost of goods sold, the gains (losses) associated with our ethanol derivative instruments in revenue and we recorded the change in the value of our interest rate swap in interest expense.  For the fiscal year ended December 31, 2006 changes in the value of our interest rate swap resulted in a gain of approximately $167,000, and we also recognized a gain from changes in the market value of our corn derivative instruments of approximately $894,000.

Grant income was approximately $73,000, $27,750, and $0 for the fiscal years ended December 31, 2008, 2007 and 2006, respectively.  We do not anticipate receiving any significant grant income during 2009.

Plant Operations

Operations of Ethanol Plant

We produced approximately 54.8 million gallons in 2008 which is approximately 110% of name-plate capacity.  At various times during 2009 we have operated the plant at a reduced rate for economic reasons.  Management will continue to evaluate the plant production rate based on a number of factors, including market economics and corn availability.

Based on current market conditions, we expect to have negative cash from cash flow generated by continuing operations.  At this time, we cannot be certain that we have enough available capital, which consists of 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.  Our projections show that we could possibly run out of available capital within the first two months of 2010.  We are currently in discussions with our bank regarding our options for obtaining additional capital whether it be through restructuring our long-term debt, raising capital from our membership, pursuing a private equity partner or possibly partnering with our corn suppliers to help the plant cash flow.  Other cost containment measures and marketing strategies are under evaluation and implementation in an effort to improve our projected cash flow and profitability.

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.

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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.

Liquidity and Capital Commitments

Statement of Cash Flows for the years ended December 31,	2008			2007			2006
Cash flows from (used in) operating activities	$	8,495,564		$	2,684,633		$	(7,662,308	)
Cash flows used in investing activities		(2,300,195	)		(3,974,839	)		(66,903,860	)
Cash flows from financing activities		(9,993,239	)		9,100,193			55,944,079

Cash flows

Operating activities.

Typically our net income or loss before depreciation, amortization and certain other noncash charges was 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.

2008 Compared to 2007

Cash flows provided by operating activities in 2008 increased $5.8 million from the comparable prior period, as a result of:

•    A net increase in cash flow from changes in working capital items (including the change in value of derivative instruments) of approximately $15.5 million.  This change is primarily the result of:

•    A net decrease in cash flow from working capital items during 2007 as the Plant started operations.  All working capital items started at a balance close to zero on January 1, 2007 and were built to their resulting balance at the end of December 31, 2007 through normal plant operations.  This resulted in a net use of cash from changes in working capital items of approximately  $10.3 million.  At December 31, 2008, the change in the balance of our working capital items resulted in a positive cash flow of approximately $5.2 million - primarily as a result of the following:

•    Our receivable balances were lower by approximately $3.2 million due to lower ethanol prices.

•    The combined total of inventory and prepaid inventory  decreased approximately $557,000 due lower inventories on hand, the result of normal fluctuations and timing of production and delivery of corn.

•    The market value of our derivative instruments was lower by approximately $2.7 million as our risk management committee had reduced our hedging position in response to the uncertain market conditions.

•    Our accounts payable and accrued expenses decreased by a combined $1.8 million due to lower inventories being maintained and the fluctuations due to the timing of purchases.

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•    A net increase in various non-cash charges of approximately $2 million primarily related to an increase in the change in the accrual for losses on firm purchase commitments of approximately $1.4 million along with an increase in the change in market value of our interest rates swaps of approximately $400,000.

Partially offsetting the increase in cash flows from working capital items was:

•    A decrease in net income of approximately $11.5 million.  Please review the “Results of Operations” for an in depth explanation of our net income for 2008 as compared to 2007.

2007 Compared to 2006

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.

Investing activities. 

Cash flows used in investing activities in 2008 decreased $1.7 million compared to 2007, the result of lower capital expenditures in 2008.  We only had one major capital project during 2008 which was to build a coal unloading facility on our site.  The capital expenditures made during 2007 were made to finalize Plant construction.

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.

Financing activities. 

Cash flows used in financing activities in 2008 decreased $19.1 million compared to 2007, primarily the result of a transition to debt service.  We issued approximately $9.3 of long-term debt under our construction loan agreements during 2007 as Plant construction was finalized.  During 2008 we made principal payments of approximately $10.1 million on our long term debt.  This consisted of our scheduled principal payments of approximately $4.3 million along with an additional principal payment of $2.3 million in accord with the excess cash flow payment terms of our note agreements.  In addition we made a temporary pay down of $3.5 million on our Long-Term Revolving note as a way to better use our excess cash.

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.

Capital Expenditures

We incurred significant capital expenditures in 2006 and 2007 during Plant construction.  We also had one major capital expenditure project during 2008 related to the construction of a coal unloading facility on our site.  The coal unloading facility became operational in September 2008 and thus far, is meeting our cost savings expectations.  Since the coal unloading facility became operational, our average coal costs have declined by approximately $10 per ton.  This will yield an approximate $1 million annual cost savings.  For 2009 we do not have any major capital expenditures planned due to current market conditions and our limited ability to raise additional capital and/or borrow additional funds.

Capital Resources

We are subject to a number of covenants and restrictions in connection with our credit facilities, including:

•    Providing the Bank with current and accurate financial statements;

•    Maintaining certain financial ratios including minimum net worth, working capital and fixed charge coverage ratio;

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•    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.

We have been notified by FNBO that we were in violation of certain of the covenants in our loan agreements at December 31, 2008.  These include the covenants requiring a minimum working capital balance, minimum net worth and a minimum fixed charge coverage ratio.  The Company has been granted a waiver of these violations by the Bank.  For further information please see the discussion in Item 1. Business labeled “General Development of Business”

The construction loan agreement also contains a number of events of default (including violation of our loan covenants) 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.

As of February 2009, our Plant, and we believe, many other plants in the ethanol industry, are operating in a negative cash flow environment.  We anticipate that, if margins do not improve, we may need to raise additional capital to meet our operating cash flows during 2009.  As of February 2009, we had available capital (cash plus borrowing capacity) of approximately $9.8 million.  This included $6 million of cash on hand, $1 million of capacity available under our Long-Term Revolving Note and $3.5 million of capacity under our Line of Credit.  Our available capital does not include $4.2 million that has been aside in conjunction with amounts withheld from Fagen as described earlier in this document.  Under current market conditions we anticipate that we will have available capital to operate our business through the end of 2009 but that the level of available capital that we have left may be insufficient to sustain operations through the first quarter of 2010.  If we continue to violate our loan covenants, it is possible that, in the future, the Bank may limit our access to the available lines of credit mentioned above.  We are evaluating, on an on-going basis, the capacity at which to operate our Plant, including possibly shutting down until margins improve.  At this time, we believe that operating our Plant, even at a reduced rate, is a more favorable option than shutting down.

We have a limited capacity to borrow additional funds due to the collateral position of FNBO.  We also have a limited ability to raise additional capital through an equity offering due to language in our Member Control Agreement that limits issuing additional units without the written consent of all members.  We have been proactively discussing these items with FNBO and are working with them to find a solution for our Plant.

The construction loan agreement contains incentive pricing language whereby we are eligible for lower interest rates if it meets certain financial criteria.  During July 2008, we did qualify for incentive pricing which decreased the interest rate on some of our debt (as noted below) by ..15%.  Because we are no longer meeting the necessary financial criteria, our rates will return to the regular pricing schedule in April 2009.

Short-Term Debt Sources

We have a revolving promissory note of up to $3,500,000 with the Bank through July 5, 2009, subject to certain borrowing base limitations.  Interest is payable quarterly and charged on all borrowings at a rate of 3.4% over the one-month LIBOR.  The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Variable Rate Note is being charged at 3.25% over the one-month LIBOR.  As of February 17, 2009, the rate was 3.70%.  We had no outstanding borrowings on the revolving promissory note as of December 31, 2008, 2007 and 2006.  Under current market conditions, we anticipate that we will need to borrow from this facility during 2009 to fund our operations.

Long-Term Debt Sources

We have four long-term notes in place with the Bank (collectively the “Term Notes”) as of December 31, 2008.  The loan agreements are secured by substantially all of the Company’s assets.  Three of the Term Notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007.  The fourth Term 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 Term 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 $24.7 million outstanding at December 31, 2008.  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 16, 2009, the rate was 4.0825%.  Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $520,000 and increasing to $653,000 per quarter, from January 2009 to January 2012, with a final principal payment of approximately $17.3 million at April 2012.

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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 4th amendment to the loan agreement.  The Variable Rate Note had a balance of $3 million at December 31, 2008.  Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate.  The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Variable Rate Note is being charged at 3.25% over the three-month LIBOR.  The interest rate is reset on a quarterly basis.  As of January 16, 2009, the rate was 4.3325%.  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 April 2010.  We anticipate the principal payments to be approximately $550,000 per quarter with a final payment of approximately $320,000 in April 2010.

Long-Term Revolving Note - The long-term revolving note (the “Long-Term Revolving Note”) has a capacity of $10 million.  This note had a balance of $6.4 million at December 31, 2008.  During January 2009, we borrowed an additional $2.5 million on this note which brought the available capacity to approximately $1 million.  Based on current interest rates and the anticipated pay off date of the Variable Rate Note, we expect scheduled principal payments to start being applied to this note in April 2010.  The payments will range from approximately $540,000 to $576,000.  We anticipate a final payment of approximately $4.9 million in April 2012.  Interest is charged at 3.4% over the one-month LIBOR rate with payments due quarterly. The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Long-Term Revolving Note is being charged at 3.25% over the one-month LIBOR.  The interest rate is reset monthly.  As of February 17, 2009, the rate was 3.705%.

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.  This note had a balance of $9.2 million as of December 31, 2008.  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 16, 2009, the rate was 4.4825%.  Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $191,000 and increasing to $242,000 per quarter, from January 2009 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.  As previously discussed in this document (see Item 1. Business – “General Development of Business”) the interest rates and payment amounts of the Term Notes may be impacted by the forbearance agreement currently being negotiated with the Bank.

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 2006 and are shown in interest expense in 2007 and 2008.

For the fiscal years ending December 31, 2008, 2007 and 2006 there were settlements of approximately $449,000, $39,000 and $0, respectively and market value adjustments resulting in a gains/(losses) of approximately $(1.8 million), $(933,000) and $167,000, 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, 2008, 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 6.3325% at January 16, 2009) and is due and payable subject to approval by the senior lender, the Bank. Interest is compounded quarterly. Amounts will be due and payable in full in April 2012. As of December 31, 2008, the outstanding amounts on these loans was $5,525,000.

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Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of December 31, 2008:

Contractual Obligations	Total		Less than 1 Yr		1-3 Years		3-5 Years		More than 5 Yrs
Long-term debt obligations *	$	61,562,230	$	8,443,950	$	16,706,998	$	36,411,282	$	―
Capital leases		108,335		61,701		46,634		―		―
Operating lease obligations		1,900,725		489,660		959,965		451,100		―
Corn Purchases **		18,871,000		18,871,000		―		―		―
Coal purchases		1,288,800		1,288,800		―		―		―
Water purchases		3,187,200		398,400		796,800		796,800		1,195,200
Total	$	86,918,290	$	29,553,511	$	18,510,397	$	37,659,182	$	1,195,200

* - Amounts determined assuming current interest rates as disclosed above in the “Long-Term Debt Sources” section for the Long-Term Revolving Note and Variable Rate Note.  Used the rates fixed in the interest rate swap agreements (see “Interest Rate Swap Agreements” section above) for the Fixed Rate Note and December 2007 Fixed Rate Note, respectively in order to account for possible net cash settlements on the interest rate swaps.  Although the outstanding balance of the Term Notes have been reclassified as current on our balance sheet, this schedule reflects the scheduled maturities of our debt.  While we cannot be certain that the Bank will not call our debt if we continue to violate our loan covenants, we do not currently anticipate paying all of this debt during the next 12 months.  Also assumed permanent repayment of $1 million in unscheduled principal payments applied to the Long-Term Revolving Note as we cannot accurately anticipate when these funds will be needed although we believe we will need them in the future to fund operations based on current market conditions.  If we do need to issue these funds for operations, our long-term debt obligations will increase accordingly with interest computed at the rates stated above.

** - Amounts determined assuming prices, including freight costs, at which corn had been contracted for cash corn contracts and current market prices as of December 31, 2008 for basis contracts that had not yet been fixed.

Due to the nature of the agreement being negotiated, 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 Industrial 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 and 2008, 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 $270,000 over ten years. For the years ended December 31, 2008, 2007 and 2006 we received $73,000, $0 and $0, respectively.  We anticipate receiving approximately $40,000 from this grant for the year ended December 31, 2009.

North Dakota Ethanol Incentive Program

Under the program, 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 approximately $2.1 million from this program during 2008.  Because we cannot predict the future prices of corn and ethanol, we cannot predict whether we will receive any funds in the future.  The fund used to pay for this incentive program is only funded once every two years.  Currently, there are no funds available for this program and it will not be funded again until June 2009.  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.

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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 during the State of North Dakota’s fiscal year (July 1 – June 30).  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.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to the impact of market fluctuations associated with interest rates and commodity prices as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in Unites States Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. We use cash, futures and option contracts to hedge changes to the commodity prices of corn and we use ethanol swaps to hedge changes in the commodity price of ethanol.  We do not enter into these derivative financial instruments for trading or speculative purposes, nor do we designate these contracts as hedges for accounting purposes pursuant to the requirements of SFAS 133, Accounting for Derivative Instruments and Hedging Activities.

Interest Rate Risk

We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding a revolving promissory note and construction term notes which bear variable interest rates. Approximately $15 million of our outstanding long-term debt is at a variable rate as of December 31, 2008.  We anticipate that a hypothetical 1% change in interest rates, from those in effect on December 31, 2008, would change our interest expense by approximately $150,000 on an annual basis.  In order to achieve a fixed interest rate on the construction loan and reduce our risk to fluctuating interest rates, we entered into an interest rate swap contracts that effectively fix the interest rate at 8.08% on approximately $27.6 million of the outstanding principal of the construction loan.  We entered into a second interest rate swap in December 2007 and effectively fixed the interest rate at 7.695% on an additional $10 million of our outstanding long-term debt.  The interest rate swaps are 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 for 2006 and are recorded in interest expense in 2007 and 2008. For the fiscal years ending December 31, 2008, 2007 and 2006, the net settlement amounts were $449,000, $38,650 and $0, respectively.  The market value adjustments resulted in gains/(losses) of approximately of $(1.8 million), $(933,000) and $167,000, respectively.  We anticipate that a hypothetical 1% change in interest rates, from those in effect on December 31, 2008, would change the fair value of our interest rate swaps by approximately $700,000.

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Commodity Price Risk

We 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.  A trend has developed where ethanol and corn prices appear to be “linked,” meaning that as corn prices move up or down, ethanol prices also move up or down accordingly.  Over the last 18 months, corn and ethanol prices have generally maintained a spread that has been large enough to allow plants to operate at a positive cash flow level.  This changed during the month of December 2008 when corn prices increased approximately $1 per bushel but ethanol prices did not increase accordingly.  This “delinking” of corn and ethanol prices had the effect of decreasing the spread between corn and ethanol prices to the point where, we believe, many plants are operating at a negative cash flow level.  Since that time, corn and ethanol prices have again become “linked” and are moving in tandem.  We have come to believe that, as long as ethanol prices are following corn prices, our exposure to price changes in corn and ethanol is greatest when we have locked in a price for these commodities through fixed price contracts.  Accordingly, we changed our hedging strategy in late 2008 in reaction to this trend.  If this trend changes, it may warrant another change in our current hedging strategy.  Through the experience gained while the commodity markets crashed during the last six months of 2008, we now feel we have a better understanding of how and when to adjust our hedging strategy.  This does not mean our strategy will always work but we feel we will be able to make more timely adjustments to our strategy in response to changes in the markets.

We enter in to fixed price contracts for corn purchases on a regular basis.  It is our intent that, as we enter in to these contracts, we will use various hedging instruments (puts, calls and futures) to maintain a near even market position.  For example, if we have 1 million bushels of corn under fixed price contracts we would generally expect to enter into a short hedge position to offset our price risk relative to those bushels we have under fixed price contracts.  Because our ethanol marketing company (RPMG) is selling substantially all of the gallons it markets on a spot basis we also include the corn bushel equivalent of the ethanol we have produced that is inventory but not yet priced as bushels that need to be hedged.

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.

As of December 31, 2008 we had approximately 1.7 million bushels of corn under fixed price contracts.  We had accrued a loss on firm purchase commitments of approximately $1.4 million related to these bushels as average fixed price of these contracts was approximately $.80 above market value.  We would expect a $0.10 change in the price of corn to have an approximate $170,000 impact on our net income.  We also had approximately 642,000 gallons (equivalent of approximately 238,000 bushels of corn) of ethanol in inventory that was not priced.  As described above, we had entered in to various hedging instruments to protect the bushels under fixed price contracts and equivalent bushels that had been converted to ethanol but were not yet priced, from fluctuations in the market price of corn.  As of December 31, 2008, our net hedge position was short the equivalent of 404 futures contracts or approximately 2 million bushels of corn.  We would generally expect that a $0.10 change in the price of corn would produce a $200,000 margin excess or deficiency.

While we have previously used ethanol swap contracts to lock in a price for a small portion of our ethanol production, we do not anticipate using these types of contracts during 2009 but may use them, if we believe it will produce positive results for the Plant.  It is the position of RPMG (our ethanol marketing company) that, under current market conditions, selling ethanol in the spot market will yield the best price for our ethanol.  RPMG will, from time to time, contract a portion of the gallons they market with fixed price contracts.

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, 2008 and 2007, we had investments of $447,000 and $3.1 million 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.

We estimate that our expected corn usage will be between 18 million and 20 million bushels per year for the production of approximately 50 million - 54 million gallons of ethanol.  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.

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our financial statements and supplementary data are included on pages F-1 to F-22 of this Report.

32

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

Boulay, Heutmaker, Zibell & Co., P.L.L.P. has been our independent auditor since 2005 and is our independent auditor at the present time. We have had no disagreements with our auditors.

ITEM 9A(T). CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer of the effectiveness of the design and operation of our disclosure controls and procedures.  The term “disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (“Exchange Act”), as amended, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms.  Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures as of December 31, 2008, have concluded that our disclosure controls and procedures are effective and are adequately designed to ensure that information required to be disclosed by us in the reports we file or submit under with the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company.   Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. 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, 2008.

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.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the fiscal quarter ended December 31, 2008, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Inherent Limitations on the Effectiveness of Controls

Management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all errors and all fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that objectives of the control systems are met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.  Because of the inherent limitations in a cost-effective control system, no evaluation of internal controls over financial reporting can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, have been detected or will be detected.

These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of a simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.  Projections of any evaluation of controls effectiveness to future periods are subject to risks.  Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies and procedures.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

33

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     The information required by Item 10 is incorporated by reference to the sections labeled “Election of Two Members to the Board of Governors,” “Governors,” “Corporate Governance,” “Information about Officers,” “Code of Ethics,” and “Section 16(a) Beneficial Ownership Reporting Compliance,” all of which appear in our definitive proxy statement to be filed with the SEC within 120 days after the close of the fiscal year covered by this Annual Report (December 31, 2008).for our 2009Annual Meeting.

ITEM 11. EXECUTIVE COMPENSATION

     The information required by Item 11 is incorporated herein by reference to the sections entitled “Executive Officer Compensation” and “Governors’ Compensation,” all of which appear in our definitive proxy statement for our 2009 Annual Meeting.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

     The information required by Item 12 is incorporated herein by reference to the sections entitled “Security Ownership of Certain Beneficial Owners and Management and Related Member Matters,” and “Equity Compensation Plan Information” which appear in our definitive proxy statement for our 2009 Annual Meeting.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

     The information required by Item 13 is incorporated herein by reference to the sections entitled “Governor Independence” and “Transactions with Related Persons, Promotors and Certain Control Persons,” which appear in our definitive proxy statement for our 2009 Annual Meeting.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

     The information required by Item 14 is incorporated herein by reference to the section entitled “Auditors’ Fees,” which appears in our definitive proxy statement for our 2009 Annual Meeting.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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

      (1) Financial Statements

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

      (2) Financial Statement Schedules

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

      (3) Exhibits

3.1	Articles of Organization, as filed with the North Dakota Secretary of State on July 16, 2003. Filed as Exhibit 3.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
3.2	Amended and Restated Operating Agreement of Red Trail Energy, LLC. Filed as exhibit 3.1 to our Current Report on Form 8-K on August 6, 2008. (000-52033) and incorporated by reference herein.
4.1	Membership Unit Certificate Specimen. Filed as Exhibit 4.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
4.2	Member Control Agreement of Red Trail Energy, LLC. Filed as Exhibit 4.2 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.

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10.1	The Burlington Northern and Santa Fe Railway Company Lease of Land for Construction/ Rehabilitation of Track made as of May 12, 2003 by and between The Burlington Northern and Santa Fe Railway Company and Red Trail Energy, LLC. Filed as Exhibit 10.1 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.2**	Management Agreement made and entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.2 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.3	Development Services Agreement entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.3 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.4	The Burlington Northern and Santa Fe Railway Company Real Estate Purchase and Sale Agreement with Red Trail Energy, LLC, dated January 14, 2004. Filed as Exhibit 10.4 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.5	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.

10.6	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.
10.7	Agreement for Electric Service made the dated August 18, 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.
10.8+	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.
10.9	Construction Loan Agreement dated as of the December 16, 2005 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.
10.10	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.
10.11	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.
10.12	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.
10.13	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.
10.14	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.

35

10.15	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.
10.16	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.
10.17	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.
10.18	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.
10.19	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.
10.20	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.
10.21	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.
10.22	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 second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.23	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 second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.24	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 second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.25	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.
10.26	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.
10.27**	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.
10.28	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.
10.29	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.
10.30	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.

36

10.31	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.
10.32	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).
10.33	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.
10.34	$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.
10.35	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.
10.36	Third Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated November 15, 2007.  Filed as Exhibit 10.38 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.37	Fourth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007.  Filed as Exhibit 10.39 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.38	Interest Rate Swap Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007.  Filed as Exhibit 10.40 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.39	Member Ethanol Fuel Marketing agreement by and between Red Trail Energy, LLC and RPMG, Inc dated January 1, 2008.  Filed as Exhibit 10.41 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.40	Contribution Agreement by and between Red Trail Energy, LLC and Renewable Products Marketing Group, LLC dated January 1, 2008.  Filed as Exhibit 10.42 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.41	Coal Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal Sales Company dated December 5, 2007.  Filed as Exhibit 10.43 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.42	Distillers Grain Marketing Agreement by and between Red Trail Energy, LLC and CHS, Inc dated March 10, 2008.  Filed as Exhibit 10.44 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.43	Assignment and Assumption Agreement dated April 1, 2008, by and between Commodity Specialist Company and Red Trail Energy, LLC.  Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (000-52033) and incorporated by reference herein.
10.44	$3,500,000 Revolving Promissory Note given by the Company to First National Bank of Omaha dated July 19, 2008.  Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (000-52033) and incorporated by reference herein.
10.45	Fifth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated July 19, 2008.  Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (000-52033) and incorporated by reference herein.
10.46**	Employment Agreement dated August 8, 2008 by and between Red Trail Energy, LLC and Mark Klimpel.  Filed as exhibit 99.1 to our Current Report on Form 8-K filed with the SEC on August 13, 2008 (000-52033) and incorporated by reference herein.

37

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.

+	Confidential treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the Securities and Exchange Commission.
*	Filed herewith.
**	Management contract or compensatory plan or arrangement.

38

SIGNATURES

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

Date: March 31, 2009	/s/ Mick J. Miller
	Mick J. Miller
	President and Chief Executive Officer
	(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, the report has been signed below by the following persons on behalf of the registrant and in the capacities and dates indicated.

Date: March 31, 2009	/s/ Mick J. Miller
	Mick J. Miller
	President and Chief Executive Officer
	(Principal Executive Officer)
Date: March 31, 2009	/s/ Mark E. Klimpel
	Mark E. Klimpel
	Chief Financial Officer
	(Principal Financial and Accounting Officer)
Date: March 31, 2009	/s/ Mike Appert
	Mike Appert, Chairman of the Board
Date: March 31, 2009	/s/ William A. Price
	William A. Price, Secretary and Governor
Date: March 31, 2009	/s/ Ron Aberle
	Ron Aberle, Governor
Date: March 31, 2009	/s/ Jody Hoff
	Jody Hoff, Vice Chairman and Governor
Date: March 31, 2009	/s/ Frank Kirschenheiter
	Frank Kirschenheiter, Treasurer and Governor
Date: March 31, 2009	/s/ Tim Meuchel
	Tim Meuchel, Governor

39

Red Trail Energy, LLC

Financial Statements

December 31, 2008, 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 -22

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Governors

Red Trail Energy, LLC

Richardton, North Dakota

We have audited the accompanying balance sheets of Red Trail Energy, LLC as of December 31, 2008 and 2007, and the related statements of operations, changes in members’ equity, and cash flows for each of the years in a three-year period ended December 31, 2008.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in a three-year period ended December 31, 2008 in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Notes 1 and 3 to the financial statements, the Company is in default on certain covenants of its loan agreements as of December 31, 2008, primarily as a result of a net loss of $5,366,572 incurred in 2008.  The lenders can demand repayment of the loans.  No such demand has been made.  Negotiations are presently under way to obtain revised loan agreements.  The Company cannot predict what the outcome of negotiations will be.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern.  The financials statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Boulay, Heutmaker, Zibell & Co. PLLP 

Certified Public Accountants

Minneapolis, Minnesota

March 31, 2009

F-2

Red Trail Energy, LLC

Balance Sheet

December 31,	2008		2007
ASSETS
Current Assets
Cash and equivalents	$	4,433,839	$	8,231,709
Accounts receivable		2,697,695		5,960,041
Corn and ethanol derivative instruments, at market		447,739		3,190,790
Inventory		3,353,592		8,297,356
Prepayments of corn purchases		4,398,046	─
Prepaid expenses		41,767		53,411
Total current assets		15,372,678		25,733,307
Property, Plant and Equipment
Land		351,280		300,602
Plant and equipment		79,898,657		78,139,237
Land improvements		3,939,294		3,918,766
Buildings		5,312,995		5,312,995
Construction in progress		33,679	─
		89,535,905		87,671,600
Less accumulated depreciation		11,525,863		5,729,058
Net property, plant and equipment		78,010,042		81,942,542
Other Assets
Debt issuance costs, net of amortization		567,385		768,405
Investment in RPMG		605,000	─
Patronage equity		116,296	─
Deposits		80,000		80,000
Total other assets		1,368,681		848,405
Total Assets	$	94,751,401	$	108,524,254
LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
Current maturities of long-term debt	$	49,063,201	$	6,578,004
Accounts payable		5,720,764		6,682,330
Accrued expenses		1,845,101		2,502,936
Accrued loss on firm purchase commitments		1,426,800	─
Interest rate swap, at market		2,861,530		1,044,191
Total current liabilities		60,917,396		16,807,461
Other Liabilities
Contracts payable		275,000		275,000
Long-Term Debt	─			52,538,310
Commitments and Contingencies
Members' Equity		33,559,005		38,903,483
Total Liabilities and Members' Equity	$	94,751,401	$	108,524,254

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

F-3

Red Trail Energy, LLC

Statement of Operations

Years ended December 31,	2008			2007		2006
Revenues
Ethanol, net of loss on derivative instruments	$	111,086,858		$	90,100,581	$	―
Distillers grains		20,816,656			11,785,388		―
Total Revenue		131,903,514			101,885,969		―
Cost of Goods Sold
Cost of goods sold		121,042,965			81,358,010		―
Loss on firm purchase commitments		3,470,110			―		―
Lower of cost or market adjusment for inventory on hand		771,200			―		―
Depreciation		5,740,963			5,655,198		―
Total Cost of Goods Sold		131,025,238			87,013,208		―
Gross Margin		878,276			14,872,761		―
General and Administrative		2,857,091			3,214,002		3,747,730
Operating Income (Loss)		(1,978,815	)		11,658,759		(3,747,730	)
Interest Expense		6,013,299			6,268,707		―
Other Income, net		2,625,542			767,276		1,243,667
Net Income (Loss)	$	(5,366,572	)	$	6,157,328	$	(2,504,063	)
Weighted Average Units Outstanding - basic		40,176,974			40,371,238		39,625,843
Weighted Average Units Outstanding - fully diluted		40,176,974			40,416,238		39,625,843
Net Income (Loss) Per Unit - basic	$	(0.13	)	$	0.15	$	(0.06	)
Net Income (Loss) Per Unit - fully diluted	$	(0.13	)	$	0.15	$	(0.06	)

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

F-4

Red Trail Energy, LLC

Statement of Changes in Members’ Equity

	Class A Member Units					Additional Paid			Retained			Treasury Units						Total Members'
Years Ended December 31, 2008, 2007 and 2006	Units (a)			Amount		in Capital			Earnings			Units			Amount			Equity
Balance - December 31, 2005		33,598,266			31,090,951		56,825			(2,434,082	)		―			―			28,713,694
Capital contributions - $1 per unit,
January 1 - March 31		6,713,207			6,713,207		―			―			―			―			6,713,207
Units issued under option exercised -
62,500 units, $0.10 per unit		62,500			6,250		―			―			―			―			6,250
Net Loss		―			―		―			(2,504,063	)		―			―			(2,504,063	)
Balance - December 31, 2006		40,373,973			37,810,408		56,825			(4,938,145	)		―			―			32,929,088
Unit-based compensation		―			―		45,000			―			―			―			45,000
Treasury units repurchased -
$1.13 per unit, December 2007		(200,000	)		―		―			―			200,000			(227,933	)		(227,933	)
Net Income		―			―		―			6,157,328			―			―			6,157,328
Balance - December 31, 2007		40,173,973			37,810,408		101,825			1,219,183			200,000			(227,933	)		38,903,483
Unit-based compensation		―			―		20,000			―			―			―			20,000
Units issued under compensation -
agreement		15,000			―		(15,000	)					(15,000	)		17,094			2,094
Net Loss		―			―		―			(5,366,572	)		―			―			(5,366,572	)
Balance - December 31, 2008		40,188,973		$	37,810,408	$	106,825		$	(4,147,389	)		185,000		$	(210,839	)	$	33,559,005

(a) - Amounts shown represent member units outstanding.  Authorized and issued units were 33,598,266, 40,373,973, 40,373973 and 40,373,973 as of December 31, 2005, December 31, 2006, December 31, 2007 and December 31, 2008, respectively.

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

F-5

RED TRAIL ENERGY, LLC

Statements of Cash Flows

Years ended December 31,	2008			2007			2006
Cash Flows from Operating Activities
Net income (loss)	$	(5,366,572	)	$	6,157,328		$	(2,504,063	)
Adjustment to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depreciation		5,796,805			5,713,042			16,016
Amortization of debt financing costs		201,020			214,169			―
Change in market value of derivative instruments		2,743,051			(2,870,449	)		(320,341	)
Change in market value of interest rate swap		1,368,307			894,256			(167,017	)
Non-cash patronage equity		(116,296	)		―			―
Grant income applied to long-term debt		(59,874	)		―			―
Unrealized loss on firm purchase commitments		1,426,800			―			―
Changes in assets and liabilities
Equity-based compensation		22,094			20,000			25,000
Accounts receivable		3,262,346			(5,960,041	)		―
Inventory		4,943,764			(4,341,227	)		(3,956,129	)
Prepaid expenses		(4,386,402	)		10,371			(38,437	)
Other assets		―			―			(80,000	)
Accounts payable		(1,130,676	)		2,603,723			(1,423,115	)
Accrued expenses		(657,835	)		204,461			510,778
Other liabilities		―			―			275,000
Net settlements on derivative instruments		449,032			39,000			―
Net cash provided by (used in) operating activities		8,495,564			2,684,633			(7,662,308	)
Cash Flows from Investing Activities
Investment in RPMG		(435,890	)		―			―
Capital expenditures		(1,864,305	)		(3,974,839	)		(66,903,860	)
Net cash used in investing activities		(2,300,195	)		(3,974,839	)		(66,903,860	)
Cash Flows from Financing Activities
Payments for debt issuance costs		―			―			(563,566	)
Debt repayments		(10,153,739	)		(1,813,376	)		―
Proceeds from long-term debt		160,500			11,141,502			49,788,188
Member contributions		―			―			6,719,457
Treasury units repurchased		―			(227,933	)		―
Net cash provided by (used in) financing activities		(9,993,239	)		9,100,193			55,944,079
Net Increase (Decrease) in Cash and Equivalents		(3,797,870	)		7,809,987			(18,622,089	)
Cash and Equivalents - Beginning of Period		8,231,709			421,722			19,043,811
Cash and Eqivalents - End of Period	$	4,433,839		$	8,231,709		$	421,722
Supplemental Disclosure of Cash Flow Information
Interest paid net of swap settlements	$	4,404,790		$	4,119,744		$	―
Interest paid and capitalized in construction in process	$	―		$	―		$	1,474,638
SUPPLEMENT DISCLOSURE OF NON-CASH
INVESTING AND FINANCING ACTIVITIES
Debt issuance costs included in accounts payable	$	―		$	―		$	799
Capital expenditures included in accounts payable	$	―		$	―		$	4,297,665
Investments included in accounts payable	$	169,110		$	―		$	―
Capital expenditures included in accrued liabilities	$	―		$	―		$	1,778,201
Amortization of deferred financing costs capitalized in
construction in process	$	―		$	―		$	52,291

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

F-6

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Red Trail Energy, LLC, a North Dakota limited liability company (the “Company”), owns and operates a 50 million gallon annual production ethanol plant near Richardton, North Dakota.  The Plant commenced production on January 1, 2007.  Fuel grade ethanol and distillers grains are the Company’s primary products.  Both products are marketed and sold primarily within the continental United States.  Prior to January 1, 2007, the Company was considered a development stage company.

Fiscal Reporting Period

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

Use of Estimates

The preparation of the financial statements, in accordance with generally accepted principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Significant items subject to such estimates and assumptions include the useful lives of property, plant and equipment; valuation of derivatives, inventory and equity-based compensation; analysis of intangibles impairment, the analysis of long-lived assets impairment and other contingencies. Actual results could differ from those estimates.

Cash and Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The carrying value of cash and equivalents approximates the fair value.  The Company has money market funds in cash equivalents at December 31, 2008 and 2007.

The Company maintains its accounts at various financial institutions. At times throughout the year, the Company’s cash and equivalents balances may exceed amounts insured by the Federal Deposit Insurance Corporation.

Accounts Receivable and Concentration of Credit Risk

The Company generates accounts receivable from sales of ethanol and distillers grains.  The Company has entered into agreements with RPMG, Inc. (“RPMG”) and CHS, Inc. (“CHS”) for the marketing and distribution of the Company’s ethanol and dried distillers grains, respectively.  Under the terms of the marketing agreements, both RPMG and CHS bear the risk of loss of nonpayment by their customers.  The Company markets its wet distillers grains internally.

The Company is substantially dependent upon RPMG for the purchase, marketing and distribution of the Company’s ethanol. RPMG purchases 100% of the ethanol produced at the Plant, all of which is marketed and distributed to its customers. Therefore, the Company is highly dependent on RPMG for the successful marketing of the Company’s ethanol. In the event that the Company’s relationship with RPMG is interrupted or terminated for any reason, the Company believes 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 the Company’s business and operations.  Amounts due from RPMG represent approximately 61% and 80% of the Company’s outstanding receivable balance as of December 31, 2008 and 2007, respectively.

The Company is substantially dependent on CHS for the purchase, marketing and distribution of the Company’s 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, the Company is highly dependent on CHS for the successful marketing of the Company’s dried distillers grains. In the event that the Company’s relationship with CHS is interrupted or terminated for any reason, the Company believes that another entity to market the dried distillers grains could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale of dried distillers grains and adversely affect the Company’s business and operations.

For sales of wet distillers grains, credit is extended based on evaluation of a customer’s financial condition and collateral is not required. Accounts receivable are due 30 days from the invoice date.  Accounts outstanding longer than the contractual payment terms are considered past due.  Internal follow up procedures are followed accordingly.  Interest is charged on past due accounts.

All receivables are stated at amounts due from customers net of any allowance for doubtful accounts.  The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s perceived current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. There was no allowance for doubtful accounts at December 31, 2008 or December 31, 2007.

F-7

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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”).  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, 2008 and 2007 the Company has no derivatives instruments that meet this criterion.

Firm Purchase Commitments

Beginning in December 2008, in connection with the execution of forward purchase commitments, the Company has elected to create a hedging relationship by selling exchanged traded futures or options as an offsetting position.  In this situation, the forward purchase contract is designated to be valued at market price until delivery was made against the contract.  On an on-going basis we intend to closely monitor the number of bushels we have hedged using this strategy to avoid an unacceptable level of margin exposure.

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.

Long-lived Assets

Property, plant, and equipment are stated at cost. Depreciation is provided over estimated useful lives by use of the straight line method. Maintenance and repairs are expensed as incurred. Major improvements and betterments are capitalized.  The present values of capital lease obligations are classified as long-term debt and the related assets are included in plant and equipment.  Amortization of equipment under capital leases is included in depreciation expense.

Long-lived assets, such as property, plant, and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including, but not limited to, discounted cash flow models, quoted market values and third-party independent appraisals.

Indefinite lived intangible assets are reviewed for impairment at least annually and if events or changes in circumstances indicate that the carrying amount of the indefinite lived intangible may not be recoverable.

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 years ended December 31, 2008 and 2007 was $201,000 and $214,000, respectively.  These amounts are included in interest expense.

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.

F-8

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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.  In addition, the Company considers production incentive payments received to be economic grants and includes such amounts in other income when received, as this represents the point at which they are fixed and determinable.

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 FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the requirements of SFAS 109, Accounting for Income Taxes, relating to the recognition of income tax benefits. FIN 48 provides a two-step approach to recognizing and measuring tax benefits when realization of the benefits is uncertain. The first step is to determine whether the benefit meets the more-likely-than-not condition for recognition and the second step is to determine the amount to be recognized based on the cumulative probability that exceeds 50%. Primarily due to the Company’s tax status as a limited liability company, the adoption of FIN 48 on January 1, 2007, had no material effect on the Company’s financial condition or results of operations.

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 $5,700 and $10,000 for the years ended December 31, 2008 and 2007, 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 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 grant date fair value unit price. Equity-based compensation expense for the years ended December 31, 2008 and 2007 totaled approximately $22,000 and $20,000, respectively.

Earnings (Loss) Per Unit

Basic earnings (loss) per unit is calculated by dividing net earnings (loss) by the weighted average units outstanding during the period.  Fully diluted earnings per unit is calculated by dividing net earnings by the weighted average member units and member unit equivalents outstanding during the period.  For 2008, 2007 and 2006, the Company had 50,000, 45,000 and 25,000 member unit equivalents.  For 2008 and 2006, member unit equivalents were not included in diluted equivalents outstanding as their effect is anti-dilutive.

F-9

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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, 2008 and 2007.

Recent Accounting Pronouncements

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, or interim period, 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.

Going Concern and Management’s Plans  

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.  The Company has incurred operating loses and negative operating cash flow since August 2008.  The Company anticipates continuing to incur losses and negative cash flow, based on current market conditions in the ethanol industry.  As of March 27, 2009, the Bank gave notice that we were in violation of certain of the covenants in our loan agreements at December 31, 2008.  Also on March 27, 2009, the Bank granted us a waiver of those covenant violations.  We are currently projecting that we will be in violation of certain of our loan covenants during 2009.  Due to the projected covenant violations, it is likely the Bank will have the ability to call our debt due and payable during 2009 which has resulted in the reclassification of our long-term debt to a current liability.

These factors raise substantial doubt about the Company’s ability to continue as a going concern.  Realization of assets is dependent upon continued operations of the Company, which in turn is dependent upon management’s plans to meet its financing requirements and the success of its future operations.  The ability of the Company to continue as a going concern is dependent on improving the Company’s profitability and cash flow, possibly securing additional financing or raising additional equity, and working with the Bank to avoid being declared in default on its loans. While the Company believes in the viability of its strategies to return to a positive cash flow and, ultimately, profitability, there can be no assurances to that effect. These financial statements do not include any adjustments related to the recoverability and classification of asset amounts or the amounts and classification of liabilities that might be necessary if the Company is unable to continue as a going concern.

Please see Note 3 for further detail on these items along with management’s plans to mitigate the effect of these items.

2.  CONCENTRATIONS

Coal

Coal is also an important input to our manufacturing process. During the fiscal year ended December 31, 2008, we used approximately 97,600 tons of coal.  We have entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2009.  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.

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.  As of March 24, 2009, we were notified by Westmoreland that a work stoppage has occurred at the mine from which we normally receive coal.  We have enough coal on hand to operate our Plant for approximately one month.  Westmoreland has more than one mine from which we can purchase coal and we are actively communicating with them to ensure we can receive shipments from another location if the work stoppage is not resolved shortly.

F-10

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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.

3.  NATURE OF CURRENT OPERATIONS

Both the corn and ethanol markets experienced significant decreases in price during the last six months of 2008 as compared to the first six months of 2008.  The decreases have occurred in conjunction with the decline in most other major commodities and world financial markets in response to the current global economic crisis.  This decrease has had a significant negative impact on the Company.  As part of its corn procurement strategy, the Company enters into contracts with local farmers and elevators in advance to ensure an adequate supply.  The Company had approximately 1.7 million bushels under fixed price contracts as of December 31, 2008 at an average price that was significantly higher than market prices.  From January through November 2008, ethanol prices have tracked very closely with changes in corn prices.  As corn prices moved up or down, ethanol prices moved up or down accordingly.  As such, the Company benefited greatly during the first part of the year from having fixed price contracts for corn purchases that were under the market value at the time of delivery.  As the price of corn rose to record levels during the first six months, ethanol prices also increased, with the result being higher gross margins for the Company during that time period.  During the last six months of 2008, the drop in corn prices has had the opposite effect on gross margins.  Prices dropped very quickly in a short period of time and, at December 31, 2008, the Company’s average price for corn under fixed contracts was approximately $0.85 per bushel above the market value.  Because these contracts are considered firm purchase commitments of inventory and inventory is valued at the lower of cost or market, the Company had to record a loss during the third quarter of 2008 of approximately $0.90 per bushel for fixed price corn contracts in place at September 30, 2008 that were not hedged by fixed price ethanol sales.  The amount of this loss was approximately $3.1 million.  Our total loss on firm purchase commitments for 2008 was approximately $3.5 million and is shown as a loss on firm purchase commitments on the statement of operations.

During the fourth quarter of 2008, corn and ethanol prices continued to decrease while we continued to process through the corn we had under fixed price contracts.  During the fourth quarter of 2008, we took delivery of approximately 2.8 million bushels of the corn that was under contract at September 30, 2008.  We have continued to enter into fixed price contracts but, at this time, they are much closer to market prices.

Through the experience of the last six months of 2008 we have come to believe that the Company’s greatest exposure to changes in the price of corn and ethanol comes when it has fixed price contracts for the purchase of corn and/or the sale of ethanol.  As such, the Company’s risk management committee has adjusted its hedging strategy in an effort to protect the Company when it does enter into fixed price contracts.  As long as ethanol prices are generally following changes in corn price, the Company’s strategy is to maintain an approximate even corn position.  For example, the Company had approximately 1.7 million bushels under fixed price contracts as of December 31, 2008.  In order to mitigate the risk associated with these fixed price contracts, the Company used various hedging instruments (puts, calls and futures) to short this position.  As of December 31, 2008, the Company had a short hedge position equal to 404 futures contracts, or approximately 2 million bushels of corn.  As corn is purchased or processed, this short position will be periodically adjusted so the Company stays at a net even position.

As of February 2009, our Plant, and, we believe, many other plants in the ethanol industry, are operating in a negative cash flow environment.  We anticipate that, if margins do not improve, we may need to raise additional capital to meet our operating cash flows during 2009.  As of February 2009, we had available capital (cash plus borrowing capacity) of approximately $9.8 million.  This included $6 million of cash on hand, $1 million of capacity available under our Long-Term Revolving Note and $3.5 million of capacity under our Line of Credit.  Our available capital does not include $4.2 million that has been aside in conjunction with amounts withheld from Fagen, Inc as described in Note 12.  Under current market conditions we anticipate that we will have available capital to operate our business through the end of 2009 but that the level of available capital that we have left may be insufficient to sustain operations through the first quarter of 2010.  If we continue to violate our loan covenants, the Bank may limit the amounts we can borrow under our lines of credit.  We are evaluating, on an on-going basis, the capacity at which to operate our Plant, including possibly shutting down until margins improve.  At this time, we believe that operating our Plant, even at a reduced rate, is a more favorable option that shutting down.

We have a limited capacity to borrow additional funds due to the collateral position of First National Bank of Omaha (“FNBO” or the “Bank”).  We also have a limited ability to raise additional capital through an equity offering due to language in our Member Control Agreement that limits issuing additional units without written consent of all members.  We have been proactively discussing these items with FNBO and are working with them to find a solution for our Plant.

The Company’s loan agreements, as described in Note 6, require the Company to maintain certain financial ratios and meet certain non-financial covenants.  The Company was notified on March 27, 2009 by its senior lender, First National Bank of Omaha (“FNBO” or the “Bank”), that it was in violation of certain loan covenants as of December 31, 2008 and that it has been granted a waiver of those covenant violations.  Our projections show that we will be in violation of certain of our loan covenants during 2009.  As a result of these projected covenant violations, which make it reasonably likely that the Bank will be able to call our long-term debt due and payable during 2009, we have reclassified all of our long-term debt to a current liability on the balance sheet.  As part of our ongoing communication with the Bank we have requested the Bank consider entering into a forbearance agreement.  A forbearance agreement would typically allow the Company to forgo principal payments for a period of time in exchange for an increase in the interest rates on the associated debt along with requirements for the Company to take certain actions and/or maintain or attain certain financial milestones.  There is no certainty that we will be able to reach agreement with the Bank on the terms of a forbearance agreement or that the Bank will grant us waivers for future projected loan covenant violations.  Due to the nature of these uncertainties and the current negative margin structure in the market place, the Company’s ability to continue as a going concern is uncertain.  As such, the Company may be forced to cease operations, declare bankruptcy and/or surrender its assets to the Bank.

F-11

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

To offset the current poor market conditions, the Company has taken a number of steps including:

1.  Temporarily suspending employee bonuses and eliminating management bonuses for the year ended December 31, 2008.

2.  The Company’s Chief Executive Office and Chief Financial Officer took voluntary pay cuts totaling $45,000 annually.

3.  The Company’s board of governors has opted out of the compensation they receive for attending board and committee meetings.

4.  The Company has reduced its production rate to approximately 80% of capacity.  The rate is being monitored on an on-going basis in conjunction with industry margins to determine the best rate at which to operate the Plant.

5.  The Company has adjusted its hedging strategy, as mentioned above.

6.  The Company has undertaken various measures to improve efficiency in the Plant in an effort to get the most ethanol out of each bushel of corn.  This is an on-going process.

7.  The Company has reorganized its corn procurement practices in an effort to procure more corn from North Dakota farmers and less via rail, resulting in lower transportation costs.

8.  The Company is also evaluating other potential cost cutting measures.

4. 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 $448,000 and $3.2 million as of December 31, 2008 and 2007, 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, 2008 and 2007, the Company recognized gains of approximately $6.2 million and $3.1 million, respectively.  Gains and losses based on the fair value change in derivative instruments related to ethanol are recorded in revenue.  During the years ended December 31, 2008 and 2007, the Company recognized losses on ethanol related derivatives of approximately $2.3 million and $2 million, respectively.  The Company has derivative instruments in the form of interest rate swaps in an agreement associated with bank financing that is not designated as a cash flow hedge.  Fair market value related to the interest rate swap liabilities totaled approximately $2.9 million and $1 million as of December 31, 2008 and 2007, 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.  The amount charged to interest expense related to the interest rate swaps was $1.8 million and $933,000 during 2008 and 2007, respectively.  In addition, the Company recorded net settlements, in interest expense, related to the interest rate swaps of $449,000 and $39,000 for 2008 and 2007, respectively.

5. INVENTORY

Inventory is valued at lower of cost or market.  At December 31, 2008, the Company recorded an adjustment of $212,000 to its corn inventory and $559,000 to its ethanol inventory to record it at the lower of cost or market value.  As of December 31, 2008, the Company had paid for, but not yet received, two unit trains of corn.  As such, approximately $4.4 million is included in prepaid inventory because the Company had not yet taken possession of the corn as of December 31, 2008.  The bushels were not taken into account in the lower of cost or market calculation related to inventory on hand but were taken into account in the calculation of the accrued loss on firm purchase commitments.  Inventory values as of December 31, 2008 and 2007 were as follows:

As of December 31,	2008		2007
Raw materials, including corn, chemicals and supplies	$	1,636,631	$	5,576,077
Work in process		681,187		902,560
Finished goods, including ethanol and distillers grains		1,035,774		1,818,719
Total inventory	$	3,353,592	$	8,297,356

F-12

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

Lower of cost or market adjustments for the years ended December 31, 2008 and 2007 were as follows:

For the years ended December 31,	2008		2007
Loss on firm purchase commitments	$	3,470,110	$	―
Lower of cost or market adjustment for inventory on hand		771,200		―
Total lower of cost or market adjustments	$	4,241,310	$	―

The Company has entered into forward corn purchase contracts under which it is required to take delivery at the contract price.  Currently, some of these contract prices are above current market prices for corn.  Given the declining ethanol price, upon taking delivery under these contracts, the Company would incur a loss.  Accordingly the Company recorded a loss on these purchase commitments of approximately $3.5 million for the year ended December 31, 2008.  The loss was recorded in “Loss on firm purchase commitments” on the statement of operations.  The amount of the loss was determined by applying a methodology similar to that used in the impairment valuation with respect to inventory.  Given the uncertainty of future ethanol prices, this loss may not be recovered, and further losses on the outstanding purchase commitments could be recorded in future periods.

As of December 31, 2008, we recorded an inventory valuation impairment of $771,000 attributable primarily to decreases in market prices of corn and ethanol.  The inventory valuation impairment was recorded in “Lower of cost or market adjustment related to inventory on hand” on the statement of operations.

6. BANK FINANCING

Long-term debt consists of the following:

As of December 31,	2008		2007
Notes under loan agreement payable to bank, see details below	$	43,436,721	$	53,437,367
Subordinated notes payable, see details below		5,525,000		5,525,000
Capital lease obligations (Note 5)		101,480		153,947
Total Long-Term Debt		49,063,201		59,116,314
Less amounts due within one year *		49,063,201		6,578,004
Total Long-Term Debt Less Amounts Due Within One Year	$	0	$	52,538,310

* - The Company has projected that it will not meet compliance with certain of its loan covenants throughout 2009 and it has not been able to secure a waiver from the bank for current or projected violations.  Because of this, the Company is required to show all of its debt subject to those covenant violations as a current liability.  In accord with the covenant waiver received for violations at December 31, 2008, the Bank has not called the debt due and payable.  The Company has shown the scheduled debt maturities below under the assumption that it will continue to make its scheduled note payments under the original terms of the agreement.

The estimated maturities of long-term debt and capital lease obligations are as follows:

As of December 31,	2008
2009	$	5,226,147
2010		5,413,175
2011		5,715,198
2012		32,696,221
2013		12,460
Thereafter		―
Total	$	49,063,201

We are subject to a number of covenants and restrictions in connection with our credit facilities, including:

• Providing the Bank with current and accurate financial statements;

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

• Maintaining adequate insurance;

• Not making, or allowing to be made, any significant change in our business or tax structure; and

• Limiting our ability to make distributions to members.

F-13

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

We have been notified by FNBO that we were in violation of certain of the covenants in our loan agreements at December 31, 2008 and that we were granted a waiver of those violations.  These include the covenants requiring a minimum working capital balance, minimum net worth and a minimum fixed charge coverage ratio.  Please see Note 3 for further discussion of the covenant violations, future projected waiver requests and forbearance agreement negotiations.  If we are successful in negotiating a forbearance agreement, the terms of the agreement may impact the interest rates and payment amounts of the company’s outstanding long-term debt (see “Term Notes” below).

The construction loan agreement also contains a number of events of default (including violation of our loan covenants) 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.

Credit Agreement

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 $4.2 million and $5.1 million for the years ended December 31, 2008 and 2007, respectively.

Construction Loan

The Company has four long-term notes (collectively the “Term Notes”) in place as of December 31, 2008.  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 an outstanding balance of $24.7 million and $26.6 million at December 31, 2008 and 2007, respectively.  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, 2008 and 2007, the rate was 7.635% and 8.22375%, respectively.  Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $520,000 and increasing to $653,000 per quarter, from January 2009 to January 2012, with a final principal payment of approximately $17.3 million 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 4th amendment to the loan agreement.  The Variable Rate Note had an outstanding balance of $3 million and $6.8 million at December 31, 2008 and 2007, respectively.  Interest payments are made on a quarterly basis with interest charged at 3.4% over the three-month LIBOR rate.  The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Variable Rate Note is being charged at 3.25% over the three-month LIBOR.  The interest rate is reset on a quarterly basis.  As of December 31, 2008 and 2007, the rate was 7.885% and 8.62375%, respectively.  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 April 2010.  The Company anticipates the principal payments to be approximately $550,000 per quarter with a final payment of approximately $320,000 in April 2010.

Long-Term Revolving Note

The Long-Term Revolving Note had an outstanding balance of $6.4 million and $10 million at December 31, 2008 and 2007, respectively.  The Company did borrow an additional $2.5 million of the available capacity on the Long-Term Revolving Note during January 2009.  Taking this borrowing into account and, based on current interest rates and the anticipated pay off date of the Variable Rate Note, we expect scheduled principal payments to start being applied to this note in April 2010.  The payments will range from approximately $540,000 to $576,000.  We anticipate a final payment of approximately $4.9 million in April 2012.  Interest is charged at 3.4% over the one-month LIBOR rate with payments due quarterly.  The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Long-Term Revolving Note is being charged at 3.25% over the three-month LIBOR.  The interest rate is reset monthly.  As of December 31, 2008 and 2007, the rate was 4.29% and 8.4275%, respectively.  The maturity date of this note is April 2012.

F-14

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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.  The balance on this note at December 31, 2008 and 2007 was $9.2 million and $10 million, respectively.  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, 2008 and 2007, the rate was 8.035% and 8.22375%, respectively.  Principal payments are to be made quarterly according to repayment terms of the construction loan agreement, generally beginning at approximately $192,000 and increasing to $242,000 per quarter, from January 2009 to January 2012, with a final principal payment of approximately $6.3 million at April 2012.  All unpaid amounts on the three term notes are due and payable in April 2012.

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 one-month LIBOR.  The interest rate is subject to an incentive pricing clause where the Company will be charged a lower rate if it meets certain financial criteria.  As of July 2008, the Company had qualified for the incentive pricing.  As such, interest on the Revolving Line of Credit is being charged at 3.25% over the three-month LIBOR.  The interest rate is reset on a quarterly basis.   As of December 31, 2008 and 2007, the rate was 4.29% and 8.22375%, respectively. The Company has no outstanding borrowings at December 31, 2008, 2007 and 2006.

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 2006 and are shown in interest expense in 2007 and 2008.

For the fiscal years ending December 31, 2008, 2007 and 2006 there were settlements of approximately $449,000, $39,000, and $0, respectively and market value adjustments resulting in a gains/(losses) of approximately $(1.8 million), $(933,000) and $167,000, 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, 2008 and 2007, 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 9.885% at December 31, 2008) and is due and payable subject to approval by 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, 2008 and 2007, respectively

7. FAIR VALUE

Effective January 1, 2008, the Company, adopted Statement of Financial Accounting Standard No. 157, Fair Value Measurements (SFAS 157), and Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159).  SFAS 157’s requirements for certain nonfinancial assets and liabilities recognized or disclosed at fair value on a nonrecurring basis are deferred until fiscal years beginning after November 15, 2008 in accordance with FASB Staff Position 157-2 (“FSP 157-2”).

SFAS 157 defines fair value, outlines a framework for measuring fair value, and details the required disclosures about fair value measurements. The adoption of SFAS 157 did not have a material effect on the Company’s financial position, results of operations, or cash flows for 2008.

F-15

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

SFAS 159 permits the Company to irrevocably choose to measure certain financial instruments and other items at fair value. Except for those assets and liabilities which are required to be recorded at fair value the Company elected not to record any other assets or liabilities at fair value, as permitted by SFAS 159.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in the principal or most advantageous market. The Company uses a fair value hierarchy that has three levels of inputs, both observable and unobservable, with use of the lowest possible level of input to determine fair value. Level 1 inputs include quoted market prices in an active market or the price of an identical asset or liability. Level 2 inputs are market data, other than Level 1, that are observable either directly or indirectly. Level 2 inputs include quoted market prices for similar assets or liabilities, quoted market prices in an inactive market, and other observable information that can be corroborated by market data. Level 3 inputs are unobservable and corroborated by little or no market data. The Company uses valuation techniques in a consistent manner from year-to-year.

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis.

	December 31, 2008
	Fair Value Carrying Amount in the Balance		Fair Value Measurement Using
	Sheet		Level 1		Level 2		Level 3
Assets
Money market funds (included in cash equivalents)	$	4,366,121	$	4,366,121	$	―	$	―
Corn and ethanol related derivative instruments		447,739		447,739		―		―
Total	$	4,813,860	$	4,813,860	$	―	$	―
Liabilities
Interest rate swap	$	2,861,530	$	―	$	2,861,530	$	―
Total	$	2,861,530	$	―	$	2,861,530	$	―

The fair value of the money market funds and corn and ethanol derivative instruments are based on quoted market prices in an active market.  The fair value of the interest rate swap instruments are determined by using widely accepted valuation techniques including discounting cash flow analysis on the expected cash flows of each instrument. The analysis of the interest rate swap reflects the contractual terms of the derivatives, including the period to maturity and uses observable market-based inputs and uses the market standard methodology of netting the discounted future fixed cash receipts and the discounted expected variable cash payments. The variable cash payments are based on an expectation of future interest rates derived from observable market interest rate curves.

8. 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 a locomotive and rail cars. Rent expense for operating leases was $356,000, $27,000 and $11,000 for the years ending December 31, 2008, 2007 and 2006, respectively. Equipment under capital leases consists of office equipment and plant equipment.

Equipment under capital leases is as follows at:

As of December 31,	2008		2007
Equipment	$	216,745	$	216,745
Accumulated amortization		45,996		23,296
Net equipment under capital lease	$	170,749	$	193,449

F-16

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

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

As of December 31, 2008	Operating Leases		Capital Leases
2009	$	489,660	$	61,701
2010		489,660		46,634
2011		470,305		―
2012		416,400		―
2013		34,700		―
Total minimum lease commitments	$	1,900,725		108,335
Less amount representing interest				6,855
Present value of minimum lease commitments included in preceding long-term liabilities			$	101,480

9. MEMBERS’ EQUITY

The Company has one class of membership units outstanding (Class A) with each unit representing a pro rata ownership interest in the Company’s capital, profits, losses and distributions.  During 2008, 15,000 units vested, and were issued, under an employee equity based compensation agreement.  These units were issued from treasury units repurchased during 2007.  Treasury units purchased are accounted for using the cost method.  The equity-based compensation plan is described in more detail in Note 10.  As of December 31, 2008 and 2007 there 40,188,973 and 40,173,973 units issued and outstanding, respectively.

10. EQUITY-BASED COMPENSATION

2006 Equity-Based Incentive Plan

During 2006, the Company implemented an equity-based incentive plan (the “Plan”) which provides for the issuance of restricted Class A Membership Units to the Company’s key management personnel, for the purpose of compensating services rendered. These units have vesting terms established by the Company at the time of each grant. Vesting terms of outstanding awards begin after one to three years of service and are fully vested after ten years of service which is the contractual term of the awards. During 2007, the Company exercised the option to repurchase 200,000 units in association with this Plan.  The units will be held in treasury until the vesting requirements of the Plan have been met.  For the years ended December 31, 2008 and 2007, equity based compensation expense was approximately $22,000 and $20,000, respectively.  As of December 31, 2008, the total equity-based compensation expense related to nonvested awards not yet recognized was $135,000, which is expected to be recognized over a weighted average period of 7.5 years.

11. GRANTS

In 2006, the Company 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.  In order to receive the proceeds, the Company was required to build a 50 MMGY ethanol plant located in North Dakota that utilizes clean lignite coal technologies in the production of ethanol.  The Company 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, the Company 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 the Company is using as a percentage of primary fuel.  The Company received $275,000 from this grant in 2006.  During the first quarter of 2007, the Company experienced issues with the delivery and quality of lignite coal under the lignite supply agreement as well as combustion issues with the coal combustor.  The Company 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, the Company entered into short term delivery for powder river basin (“PRB”) coal as an alternative to lignite coal.  During December 2007, The Company extended its PRB coal agreement for two additional years as the Company continues to try to resolve the issues experienced while running the Plant on lignite coal.  Due to the temporary nature of the Company’s 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.  The Company intends to use lignite coal in the future if delivery, pricing, quality and performance issues can be resolved favorably.  Because the Company has been temporarily using PRB coal, it made a formal request to extend the Final Report deadline from June 30, 2007 to August 31, 2007.  The Company received the extension but has not yet returned to using lignite coal nor filed the Final Report.  In place of the Final Report, the Company filed a memo with the Commission updating them on the status of using lignite coal at its Plant for 2007.  This included supplying information on what percentage lignite coal was of the Company’s total coal usage (on a BTU basis) for 2007 and 2008.  For 2007 and 2008, the Company did not meet the minimum lignite usage specified in the grant contract.  Based on that information, the Company expects the Commission to notify it that the Company will have to repay the grant at an accelerated rate of $35,000 per year for every year the Company does not meet the specified percentage of lignite use as outlined in the grant.  The Company has remained in contact with the Commission about the current state of the Plant as well as future intentions to run on lignite coal.

F-17

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

The Company has 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. The Company is eligible to receive up to approximately $270,000 over ten years. The Company received and earned approximately $73,000 and $0 for the fiscal years ended December 31, 2008 and 2007, respectively.

In additional to the Job Services North Dakota training program, the Company entered into a contract on October 2, 2006 with Job Service North Dakota for the Workforce 20/20 program. The program assists North Dakota employers in training and upgrading workers’ skills. Under this program, the Company received and earned $27,750 in 2007 and $0 in 2008.

12. COMMITMENTS AND CONTINGENCIES

Design Build Contract

The Company signed a Design-Build Agreement with Fagen, Inc. (“Fagen”) in September 2005 to design and build the ethanol plant at a total contract price of approximately $77 million.  The total cost of the project, including the construction of the ethanol plant and start-up expenses was approximately $99 million at December 31, 2007.  The Company has remaining payments under this Design-Build Agreement of approximately $3.9 million.  This payment has been withheld pending satisfactory resolution of a punch list of items including a major issue with the coal combustor experienced during start up.  The Plant was originally designed to be able to run on lignite coal.  During the first four months of operation, however, the Plant experienced numerous shut downs related to running on lignite coal.  In April 2007, the Company switched to using powder river basin coal as its fuel source and has not experienced a single shut down related to coal quality.  The Company continues to work with Fagen to find a solution to these issues. An amount approximately equal to the final payment of $3.9 million has been set aside in a separate money market account. Any amounts remaining in this account after satisfactory resolution of this issue could be used to pay down the Company’s long-term debt, make necessary upgrades to its plant or be used for operations pending bank approval.

Consulting Contracts

In December 2003, the Company entered into a Development Services Agreement (the “DSA”) and a Management Agreement (the “MA”) with Greenway Consulting.  Under the terms of the DSA, Greenway Consulting provided project development, construction management and initial plant operations through start up.  The DSA also called for Greenway Consulting to be reimbursed for salary and benefit expenses of the General Manager and Plant Manager retroactive to the date six months prior to successful commissioning of the plant.  The Company has paid Greenway Consulting $2,075,000 for services rendered under the DSA and reimbursed Greenway Consulting $135,000 for salary and benefit expenses.  The Company still owes $152,500 to Greenway for services rendered under the DSA.  Payment is being withheld pending satisfactory resolution to a punch list of items to be completed by Fagen including problems related to the coal combustor.  The DSA expired upon successful commissioning of the plant which occurred on January 1, 2007 at which time the MA went into effect.

Under the terms of the MA, Greenway provides management of day to day plant operations. For these services the Company will pay 4% of the Company’s pre-tax net income plus $200,000 per year once the Plant is in reasonable compliance with the engineer’s performance standard.  In addition, the Company will reimburse Greenway Consulting for the salary and benefits of the General Manager and Plant Manager.   The agreement has a five year term which expires December 31, 2011 unless either party terminates this agreement upon a default of the other after thirty days written notice.   As of January 1, 2009, the Company began withholding payment of amounts owed to Greenway under the MA until resolution to certain contractual items is resolved.  For the years ended December 31, 2008 and 2007, the Company had expensed approximately $534,000 and $552,000, respectively for management services under the MA and has also expensed approximately $288,000 and $326,000, respectively, for reimbursement of salary and benefits.

In February 2006, the Company entered into a Risk Management Agreement for grain procurement, pricing, hedging and assistance in risk management as it pertains to ethanol and co-products with John Stewart & Associates (“JSA”). JSA will provide services in connection with grain hedging, pricing and purchasing. The Company will pay $2,500 per month for these services beginning no sooner than ninety days preceding plant startup. In addition, JSA will serve as clearing broker for the Company and charge a fee of $15.00 per contract plus clearing and exchange fees.  As of December 31, 2008, there were no amounts outstanding.

Utility Agreements

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

In March 2006, the Company entered into a ten year contract with Southwest Water Authority to purchase raw water. The contract, which was amended in 2007, includes a renewal option for successive periods not to exceed ten years. The actual rate for raw water was $2.49 per one thousand gallons for the year ended December 31, 2008.  The base rate may be adjusted annually by the State Water Commission.

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

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Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

Marketing Agreements

The Company entered into a marketing agreement on March 10, 2008 with CHS for the purpose of marketing and selling its DDGS.  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, the Company had a marketing agreement with Commodity Specialists Company (“CSC”) which 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, the Company pays CHS a fee for marketing its DDGS.  The fee is 2% of the selling price of the DDGS subject to a minimum of $1.50 per ton and a maximum of $2.15 per ton.  Through the marketing of CHS and its relationships with local farmers, the Company is not dependent upon one or a limited number of customers for its DDGS sales.

The Company entered into a new marketing agreement on January 1, 2008 with RPMG for the purposes of marketing and distributing all of the ethanol produced at the Plant (the “New Agreement”).  Prior to January 1, 2008 the Company had a marketing agreement in place with Renewable Products Marketing Group LLC.  Effective October 1, 2007, that contract was 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, the Company also purchased an ownership interest in RPMG.  Currently, the Company owns 8.33% of the outstanding capital stock of RPMG and anticipates that its ownership interest will be reduced if other ethanol plants that utilize RPMG’s marketing services become owners of RPMG.  The Company’s ownership interest in RPMG entitles it to a seat on its board of directors which is filled by its Chief Executive Officer (“CEO”).  The New Agreement will be in effect as long as the Company continues to be a member in RPMG.  The Company currently pays 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 the Company’s ownership buy-in is complete, which it expects to occur during 2009.

Coal Purchase Contract

The Company entered into a contract in March 2004 with General Industries, Inc. d/b/a Center Coal Company (“Center Coal”) for the purchase of lignite coal. The term of the contract was for ten years from the commencement date agreed upon by the parties.  During the startup period of January – April 2007, the Plant experienced a number of shut-downs as a result of issues related to lignite coal quality and delivery, as specified in the coal purchase agreement, along with the performance of the Plant’s coal combustor while running on lignite coal.  As a result of these issues, the Company terminated its lignite coal purchase and delivery contract with Center Coal and switched to PRB coal as an alternative to lignite coal. Since making the change, the Plant has not experienced a single shut-down due to coal quality.  The Company entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2009.  Under the terms of the agreement, the price of coal is set at $14.32 per ton for 2008 and $14.75 per ton for 2009.  The Company has withheld $3.9 million from the general contractor pending resolution of this issue with the coal combustor.  While PRB coal is more expensive than lignite coal, the Company believes running on PRB coal may actually be the same cost or slightly lower cost than running on lignite coal when the Company factors in the additional operating costs associated with running on lignite coal.  As a long-term solution, the Company is working with its contractors to find ways to modify the coal combustor so that the Plant can continue using lignite coal. If the Company cannot modify the coal combustor to use lignite coal, it 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 the Company needs will always be delivered as the Company needs it, that the Company will receive the proper size or quality of coal or that the Plant’s coal combustor will always work properly with lignite coal. Any disruption could either force the Company to reduce its operations or shut down the Plant, both of which would reduce the Company’s revenues.

Coal Management Contract

During 2008, the Company entered in to a contract with M-BAR-D LLC (“MBD”) for the unloading of coal at the Company’s coal unloading facility along with transport of the coal from the stockpile to the storage silos at the Plant.  The contract runs for 2.5 years and is automatically renewed for two year terms unless terminated in accord with the terms of the contract.  Under the terms of the agreement, the Company pays MBD $2.65 per ton for unloading the coal and $1.30 per ton for transporting the coal.

Chemical Consignment Purchase Contracts

During November 2006, the Company entered into two consignment purchases for bulk chemicals purchased through Genecor International Inc and Univar USA. Genecor will provide the following enzymes: Alpha-Amylase, Glucoamylease and Protease. The Univar agreement states that it will provide the following bulk chemicals: Caustic Soda, Sulfuric Acid, Anhydrous Ammonia and Sodium Bicarbonate. All Univar chemicals are purchased at market price for a five year term.  The Genecor agreement was renewed by the Company on July 1, 2008 for a one year term.

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Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

Natural Gasoline Contract

The Company has entered into various contracts with Quadra Energy Trading Inc. for the purchase of natural gasoline. The term of the most recent contract is January 2009 through April 2009.  The price is based off the average Conway natural gas price plus $0.35.

Leases

As part of entering into the new distillers grain marketing agreement described above, the Company entered into an assignment and assumption agreement with CSC in April 2008 to assume a rail car lease that CSC entered into with Trinity Industries Leasing Company.  The rail cars are used for the transport of DDGs.  Five quadruple covered hopper cars are leased at a rate of $691 per car, per month through November 5, 2011.  Fifty quadruple covered hopper cars are leased at a rate of $694 per car, per month through January 31, 2013.

The Company entered into an operating lease in July 2006 for the lease of a locomotive. The term of the contract is for a period of five years commencing upon delivery. The monthly rental amount is $2,650.

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

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

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

Firm Purchase Commitments for Corn

To ensure an adequate supply of corn to operate the Plant, the Company enters into contracts to purchase corn from local farmers and elevators.  At December 31, 2008, the Company had various fixed and basis contracts for approximately 4.1 million bushels of corn.  Of the 4.1 million bushels under contract, approximately 1.7 million bushels had a fixed price as of December 31, 2008.  We anticipate taking delivery of the corn under fixed price contracts under the following time frame: approximately 65% in January 2009 and approximately 35% spread throughout the rest of 2009, respectively.  Using the stated contract price for the fixed contracts and using market prices, as of December 31, 2008, to price the basis contracts the Company had commitments of approximately $18.9 million related to all 4.1 million bushels under contract.

13.  DEFINED BENEFIT CONTRIBUTION PLAN 

The Company established a simple IRA retirement plan for its employees during 2006. The Company matches employee contributions to the plan up to 3% of employee’s gross income. The amount contributed by the Company is vested 100% as soon as the contribution is made on behalf of the employee. The Company contributed approximately $56,000 and $59,000 for fiscal years ended December 31, 2008 and 2007, respectively.

14. RELATED PARTY TRANSACTIONS

The Company has balances and transactions in the normal course of business with various related parties for the purchase of corn, sale of DDGs and sale of ethanol.  The related parties include unit holders, members of the board of governors of the Company, Greenway and RPMG.  RPMG has been considered a related party since January 1, 2008 when the Company became a partial owner in RPMG.  As such, the amounts below as of December 31, 2007 have been restated to include transactions with RPMG.  The amounts previously reported, excluding RPMG, as of December 31, 2007 for accounts receivable and accounts payable were $293,468 and $1,471,479, respectively.  Revenue and cost of goods sold, as previously reported, for year ending December 31, 2007, were $2,323,263 and $2,673,605, respectively.  The Company also has a note payable to Greenway, and pays Greenway for plant management and other consulting fees (recorded in general and administrative expense).  The Chief Manager of Greenway is a member of the Company.  Significant related party activity affecting consolidated financial statements are as follows:

As of December 31,	2008		2007
Balance Sheet
Accounts receivable	$	2,198,277	$	2,757,476
Accounts payable		788,149		2,088,561
Notes payable		1,525,000		1,525,000
Statement of Operations
Revenues	$	117,379,764	$	94,411,004
Cost of goods sold		2,712,392		3,166,836
General and administrative expenses		1,087,552		878,021
Inventory Purchases	$	9,669,953	$	6,476,508

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Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

15. INCOME TAXES

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

As of December 31	2008			2007
Financial Statement Basis of Assets	$	94,751,401		$	108,524,254
Organization and start-up costs		5,141,445			5,668,245
Inventory and compensation		34,458			195,235
Book to tax depreciation		(19,293,573	)		(5,543,566	)
Book to tax derivative difference		(2,371,800	)		(262,715	)
Income Tax Basis of Assets	$	78,261,931		$	108,581,453
Financial Statement Basis of Liabilities	$	61,192,396		$	69,620,771
Loss on firm purchase commitment		1,426,800			―
Interest rate swap		(2,861,529	)		(933,256	)
Income Tax Basis of Liabilities	$	59,757,667		$	68,687,515

16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarter results are as follows:

Statement of Operations For the quarters ended,	March 2008		June 2008			September 2008			December 2008
Revenues	$	33,420,005	$	35,692,315		$	36,047,461		$	26,743,733
Cost of goods sold		27,667,222		30,460,525			38,644,318			34,253,173
Gross profit		5,752,783		5,231,790			(2,596,857	)		(7,509,440	)
General and administrative expenses		746,596		919,333			666,866			524,296
Operting income (loss)		5,006,187		4,312,457			(3,263,723	)		(8,033,736	)
Interest expense		2,439,805		(62,661	)		1,116,343			2,519,812
Other income (expense)		169,817		688,926			835,179			931,620
Net income (loss)	$	2,736,199	$	5,064,044		$	(3,544,887	)	$	(9,621,928	)
Weighted average units - basic		40,173,973		40,173,973			40,187,995			40,188,973
Weighted average units - fully diluted		40,223,973		40,228,973			40,187,995			40,188,973
Net income (loss) per unit - basic	$	0.07	$	0.13		$	(0.09	)	$	(0.24	)
Net income (loss) per unit - fully diluted	$	0.07	$	0.13		$	(0.09	)	$	(0.24	)

For the Quarters ended,	March 2007			June 2007		September 2007		December 2007
Revenues	$	18,934,975		$	30,247,829	$	27,329,379	$	25,373,786
Cost of goods sold		15,118,165			25,877,011		24,703,796		21,314,236
Gross profit		3,816,810			4,370,818		2,625,583		4,059,550
General and administrative expenses		847,796			881,109		568,223		916,874
Operting income (loss)		2,969,014			3,489,709		2,057,360		3,142,676
Interest Expense		1,149,528			969,088		2,087,460		2,062,632
Other income (expense)		(46,178	)		82,059		262,979		468,417
Net income	$	1,773,308		$	2,602,680	$	232,879	$	1,548,461
Weighted average units - basic		40,373,973			40,373,973		40,373,973		40,373,973
Weighted average units - fully diluted		40,403,973			40,408,973		40,413,973		40,418,973
Net income (loss) per unit - basic	$	0.04		$	0.06	$	0.01	$	0.04
Net income (loss) per unit - fully diluted	$	0.04		$	0.06	$	0.01	$	0.04

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

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Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2008, 2007 and 2006

17. SUBSEQUENT EVENTS

·   In an effort to diversify its revenue stream, the Company entered into an agreement in March 2008 to operate third party corn oil extraction equipment that will be added to its facility.  The agreement has a term of 10 years commencing from the date when the equipment installation is complete.  As of March 15, 2009, corn oil extraction equipment had not yet been installed at the Company’s facility.  The third party that the Company contracted with ran into financing issues.  Late in 2008 they received approval for their financing package contingent on certain conditions being met.  As part of the financing arrangement, the terms of the original contract entered in to in March 2008 were changed significantly.  The Company is currently in negotiations with the third party related to several of the terms that changed.  We currently do not have a time frame for when the corn oil extraction equipment may be installed at our facility.

·   We have been notified by FNBO that we were in violation of certain of the covenants in our loan agreements at December 31, 2008 and that we were granted a waiver of these covenant violations.  These include the covenants requiring a minimum working capital balance, minimum net worth and a minimum fixed charge coverage ratio.  See Note 3 for further discussion.

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