RED TRAIL ENERGY, LLC (Form: 10-KT, Received: 12/13/2011 17:11:35)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



o	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

x	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

	For the transition period from January 1, 2011 to September 30, 2011

	COMMISSION FILE NUMBER 000-52033

RED TRAIL ENERGY, LLC

(Exact name of registrant as specified in its charter)



North Dakota				76-0742311
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)

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

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

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: Class A Membership Units

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

o Yes x No

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

o Yes x No

Indicate by check mark 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.

x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes o No

Indicate by check mark if disclosure 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

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



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

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

o Yes x No

The aggregate market value of the membership units held by non-affiliates of the registrant as of June 30, 2011 was $34,080,812. There is no established public trading market for our membership units. The aggregate market value was computed by reference to the most recent offering price of our Class A units which was $1 per unit.

As of December 13, 2011 the Company has 40,213,973 Class A Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The registrant has incorporated by reference into Part III of this Annual Report on Form 10-K portions of its definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year covered by this Annual Report.

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INDEX



	Page Number
PART I	4
Item 1. Business	5
Item IA. Risk Factors	11
Item 2. Properties	15
Item 3. Legal Proceedings	15
Item 4. Removed and Reserved	15
PART II	15
Item 5. Market for Registrant's Common Equity, Related Member Matters and Issuer Purchases of Equity Securities	15
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	28
Item 8. Financial Statements and Supplementary Data	30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	52
Item 9A. Controls and Procedures	52
Item 9B. Other Information	53
PART III	53
Item 10. Directors, Executive Officers and Corporate Governance	53
Item 11. Executive Compensation	53
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Member Matters	53
Item 13. Certain Relationships and Related Transactions, and Director Independence	53
Item 14. Principal Accounting Fees and Services	53
PART IV	53
Item 15. Exhibits, Financial Statement Schedules	53
SIGNATURES	58

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains historical information, as well as forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance, or our expected future operations and actions. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,” “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions. These forward-looking statements are only our predictions based on current information and involve numerous assumptions, risks and uncertainties. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the reasons described in this report. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:



	Ÿ	Fluctuations in the price and market for ethanol and distillers grains;
	Ÿ	Availability and costs of products and raw materials, particularly corn and coal;
	Ÿ	Changes in or lack of availability of credit;
	Ÿ	Changes in the environmental regulations that apply to our plant operations and our ability to comply with such regulations;
	Ÿ	Ethanol supply exceeding demand and corresponding ethanol price reductions impacting our ability to operate profitably and maintain a positive spread between the selling price of our products and our raw material costs;
	Ÿ	Our ability to generate and maintain sufficient liquidity to fund our operations, meet debt service requirements and necessary capital expenditures;
	Ÿ	Our ability to continue to meet our loan covenants;
	Ÿ	Limitations and restrictions contained in the instruments and agreements governing our indebtedness;
	Ÿ	Results of our hedging transactions and other risk management strategies;
	Ÿ	Changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices that currently benefit the ethanol industry including:
		Ÿ national, state or local energy policy - examples include legislation already passed such as the California low-carbon fuel standard as well as potential legislation in the form of carbon cap and trade;
		Ÿ federal and state ethanol tax incentives;
		Ÿ legislation mandating the use of ethanol or other oxygenate additives;
		Ÿ environmental laws and regulations that apply to our plant operations and their enforcement; or
		Ÿ tariffs on foreign ethanol.
	Ÿ	Changes and advances in ethanol production technology; and
	Ÿ	Competition from alternative fuels and alternative fuel additives.

Our actual results or actions could and likely will differ materially from those anticipated in the forward-looking statements for many reasons, including the reasons described in this report. We are not under any duty to update the forward-looking statements contained in this report. We cannot guarantee future results, levels of activity, performance or achievements. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. You should read this report and the documents that we reference in this report and have filed as exhibits completely and with the understanding that our actual future results may be materially different from what we currently expect. We qualify all of our forward-looking statements by these cautionary statements.

AVAILABLE INFORMATION

Information about us is also available at our website at www.redtrailenergyllc.com , under “SEC Compliance,” which includes links to reports we have filed with the Securities and Exchange Commission. The contents of our website are not incorporated by reference in this Annual Report on Form 10-K.

PART I

Change in Fiscal Year End

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financial information for the nine-month transition period from January 1, 2011 to September 30, 2011, or Transition Period. References in this Transition Report on Form 10-K to fiscal year 2010 or fiscal 2010 refer to the period of January 1, 2010 through December 31, 2010 and references to fiscal year 2009 or fiscal 2009 referred to the period of January 1, 2009 through December 31, 2009. Subsequent to this Transition Report on Form 10-K, our reports on Form 10-K will cover the fiscal year from October 1 to September 30 with historical periods remaining unchanged.

ITEM 1. BUSINESS

Business Development

Red Trail Energy, LLC was formed as a North Dakota limited liability company in July of 2003, for the purpose of constructing, owning and operating a fuel-grade ethanol plant (the "Plant") near Richardton, North Dakota in western North Dakota. References to “we,” “us,” “our” and the “Company” refer to Red Trail Energy, LLC. Since January 2007, we have been engaged in the production of ethanol and distillers grains at the plant.

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 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. In November 2010, the Company executed a Mediated Settlement Agreement (the Agreement) with Fagen whereby the terms of the Agreement become enforceable upon the Company's ability to pass a Required Emissions Test (the Test) as defined in the Agreement. The Company did not pass the Test in the nine month period ended September 30, 2011 and is currently working towards meeting the terms of the Test during the first or second quarter of the Company's 2012 fiscal year. Additionally, there will be certain payments to third parties and releases received by the Company from third parties once the Test is achieved. At September 30, 2011 and December 31, 2010, an amount equal to the $3.9 million withheld from Fagen has been applied towards the Company's long-term debt and has been restricted by the Company's senior lender until such time that the financial terms of the Agreement become effective.

On June 1, 2011, the Company executed a Ninth Amendment of Construction Loan Agreement with its senior lender to extend the maturity date of the Company's $7,000,000 revolving loan from June 1, 2011 to April 16, 2012, and to modify certain covenants within the Construction Loan Agreement. The modified covenants included the annual capital expenditure threshold which was increased from $500,000 to $1,600,000. Also modified was the Working Capital covenant which was modified to reflect the impact of the Company's senior debt maturing on April 16, 2012 and therefore being 100% current. The final covenant modified was the Net Worth covenant which was modified to reflect a calculation that is consistent with the financial terms of the Mediated Settlement Agreement entered into in November 2010 between the Company and the original plant design/build contractor.

The Company's senior debt has a maturity date of April 16, 2012 and is therefore classified as fully current in the liability section of the Company's balance sheet as of September 30, 2011. The Company plans to refinance this debt and is currently negotiating the refinance terms with its senior lender. The Company's senior lender has indicated they do not foresee any problems in refinancing this debt and the Company anticipates to receive a commitment letter with refinance terms from its senior lender in the second quarter of the Company's 2012 fiscal year.

Financial Information

Please refer to “ ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” for information about our revenue, profit and loss measurements and total assets and liabilities and “ ITEM 8. Financial Statements and Supplementary Data ” for our financial statements and supplementary data.

Principal Products

The principal products we produce are ethanol and distillers grains.

Ethanol

Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains, which 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. Ethanol produced in the United States is primarily used for blending with unleaded gasoline and other fuel products. The principal purchasers of ethanol are generally wholesale gasoline marketers or blenders. The principal markets for our ethanol are petroleum terminals in the continental United States.

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Approximately 84% of our total revenue was derived from the sale of ethanol during our transition period ended September 30, 2011. Ethanol sales accounted for approximately 84% and 83% of our total revenue for our fiscal years ended December 31, 2010 and 2009, respectively.

Distillers Grains

The principal co-product of the ethanol production process is distillers grains, a high protein 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. We produce two forms of distillers grains: Distillers Dried Grains with Solubles (“DDGS”) and Modified Distillers Grains with Solubles (“MDGS”). MDGS is processed corn mash that has been dried to approximately 50% moisture. MDGS has a shelf life of approximately seven days and is often sold to nearby markets. DDGS is processed corn mash that has been dried to approximately 10% moisture. It has a longer shelf life and may be sold and shipped to any market regardless of its vicinity to our ethanol plant.

Approximately 16% of our total revenue was derived from the sale of distillers grains during our transition period ended September 30, 2011. Distillers grains sales accounted for approximately 16% and 17% of our total revenue for our fiscal years ended December 31, 2010 and 2009, respectively.

Principal Product Markets

As described below in “ Distribution Methods ,” we market and distribute all of our ethanol and all of our dried distillers grains through professional third party marketers. Our ethanol and dried distillers grains marketers make all decisions with regard to where our products are marketed. Our ethanol and distillers grains are primarily sold in the domestic market; however, as domestic production of ethanol and distillers grains continue to expand, we anticipate increased international sales of our products. Currently, the United States ethanol industry exports a significant amount of distillers grains to Mexico, Canada and China. During our transition period ended September 30, 2011, the ethanol industry experienced increased ethanol exports to Europe. These ethanol exports benefited ethanol prices in the United States. We anticipate that ethanol exports will remain steady during our 2012 fiscal year.

We expect our ethanol and distillers grains marketers to explore all markets for our products, including export markets. However, due to high transportation costs, and the fact that we are not located near a major international shipping port, we expect a majority of our products to continue to be marketed and sold domestically.

Distribution Methods

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 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 also have a marketing agreement with CHS, Inc. (“CHS”) for our DDGS. We market and sell our MDGS internally.

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 one billion gallons of ethanol on an annual basis. Currently we own 7.14% of the outstanding capital stock of RPMG. Our ownership interest will fluctuate as other ethanol plants that utilize RPMG's marketing services may become owners of RPMG or decide to change marketers. Our ownership interest in RPMG entitles us to a seat on its board of directors which is filled by Gerald Bachmeier, our Chief Executive Officer (“CEO”). The marketing agreement will be in effect as long as we continue to be a member in RPMG.

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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 each term unless otherwise terminated in accordance with the terms of the marketing agreement.

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

Sources and Availability of Raw Materials

Corn

Our plant currently uses approximately 19 million bushels of corn per year, or approximately 52,000 bushels per day, as the feedstock for its dry milling process. Our commodity manager is responsible for purchasing corn for our operations, scheduling corn deliveries and establishing hedging positions to protect the price we pay for corn.

During 2011, we were able to secure sufficient grain to operate the plant and do not anticipate any problems securing enough corn during 2012. Almost all of our corn is supplied from farmers and local elevators in North Dakota and South Dakota. While we do not anticipate encountering problems sourcing corn, a shortage of corn could develop, particularly if there were an extended drought or other production problem. Poor weather can be a major factor in increasing corn prices. If the United States were to endure an entire growing season with poor weather conditions, it could result in a prolonged period of higher than normal corn prices.

Corn prices depend on several other factors as well, including world supply and demand and the price of other commodities. United States production of corn can be volatile as a result of a number of factors, including weather, current and anticipated stocks, domestic and export prices and supports and the government's current and anticipated agricultural policy. The price of corn was volatile during our transition period ended September 30, 2011 and we anticipate that it will continue to be volatile in the future. We anticipate that increases in the price of corn, which are not offset by corresponding increases in the prices we receive from sale of our products, will have a negative impact on our financial performance.

Coal

Coal is also an important input to our manufacturing process. During our transition period ended September 30, 2011, we used approximately 63,000 tons of coal. Our plant was originally designed to run on lignite coal but problems running on lignite during start up caused us to change to sub-bituminous Powder River Basin (“PRB”) coal.

We purchase the coal needed to power our ethanol plant from a supplier under a contract which specifies quantity and price. This arrangement helps us to mitigate price volatility in the coal market. The contract with our coal supplier expires in December 2011 and we anticipate entering into a new contract upon expiration of the current contract. We do not anticipate any problems negotiating a renewal of this contract. We believe we could obtain alternative sources of PRB 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.

Electricity

The production of ethanol is an 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. The term of the contract is up for renewal in August 2013.

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

Water

To meet the plant's water requirements, 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. The plant anticipates receiving adequate water supplies during 2012.

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In January 2011, we entered into a lease agreement with U.S. Water Services for new water filtration equipment. The required lease payments will be paid over a two year period and will total $494,350. It is estimated that the total cost of the water filtration improvements, including the leased equipment, will be approximately $700,000.

Patents, Trademarks, Licenses, Franchises and Concessions

We do not currently hold any patents, trademarks, franchises or concessions. We were granted a perpetual and royalty free license by ICM to use certain ethanol production technology necessary to operate our ethanol plant. The cost of the license granted by ICM was included in the amount we paid to Fagen to design and built our ethanol plant and expansion.

Seasonality Sales

We experience some seasonality of demand for our ethanol and distillers grains. Since ethanol is predominantly blended with gasoline for use in automobiles, ethanol demand tends to shift in relation to gasoline demand. As a result, we experience some seasonality of demand for ethanol in the summer months related to increased driving and, as a result, increased gasoline demand. In addition, we experience some increased ethanol demand during holiday seasons related to increased gasoline demand. We also experience decreased distillers grains demand during the summer months due to natural depletion in the size of cattle feed lots.

Working Capital

We primarily use our working capital for purchases of raw materials necessary to operate the ethanol plant and for capital expenditures to maintain and upgrade the ethanol plant. Our primary sources of working capital are income from our operations as well as our revolving lines of credit with our primary lender First National Bank of Omaha (“FNBO”). During our transition period ended September 30, 2011 we used a portion of our working capital for two major capital projects, a flue gas recirculation project and a water treatment project. The flue gas recirculation project was placed in service in May 2011 and allows the plant to introduce low oxygen air into the combustor allowing greater control of the furnace bed and vapor space temperature resulting in reduced thermal NOx conversion, reduced ID & FD fan load, and allows for the implementation of an alternative fuel burning system. The water treatment project consists of additional water treatment equipment which is necessary due to increasing levels of suspended solids through the plant's raw water intake and is expected to be operational in the first quarter of fiscal 2012. Management believes that our current sources of working capital are sufficient to sustain our operations, provided the Company's senior lender refinances the outstanding debt in fiscal 2012.

Dependence on One or a Few Major Customers

As discussed above, we rely on RPMG and CHS for the sale and distribution of all of our ethanol and dry distillers grains, respectively. Accordingly, we are highly dependent on RPMG and CHS for the successful marketing of our products. We anticipate that we would be able to secure alternate marketers should RPMG or CHS fail, however, a loss of our marketer could significantly harm our financial performance.

Competition

We are in direct competition with numerous ethanol producers, many of whom have greater resources than we do. While management believes we are a low cost producer of ethanol, larger ethanol producers may be able to take advantages of economies of scale due to their larger size and increased bargaining power with both customers and raw material suppliers. Following the significant growth in the ethanol industry during 2005 and 2006, the ethanol industry has grown at a much slower pace. As of November 16, 2011, the Renewable Fuels Association estimates that there are 209 ethanol production facilities in the United States with capacity to produce approximately 14.7 billion gallons of ethanol annually. The RFA also estimates that approximately 3.6% of the ethanol production capacity in the United States is currently idled. The ethanol industry is continuing to experience a consolidation where a few larger ethanol producers are increasing their production capacities and are controlling a larger portion of United States ethanol production. The largest ethanol producers include Archer Daniels Midland, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, each of which are capable of producing significantly more ethanol than we produce.

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

U.S. FUEL ETHANOL PRODUCTION CAPACITY BY TOP PRODUCERS

Producers of Approximately 600

million gallons per year (MMgy) or more



Company	Current Capacity (MMgy)	Under Construction/ Expansions (MMgy)
Archer Daniels Midland	1,750.0	—
POET Biorefining	1,629.0	—
Valero Renewable Fuels	1,130.0	—
Green Plains Renewable Energy	740.0	—

Updated: November 16, 2011.

Ethanol is a commodity product where competition in the industry is predominantly based on price. Larger ethanol producers may be able to realize economies of scale in their operations that we are unable to realize. While we believe that we are a low cost producer of ethanol, increased competition in the ethanol industry may make it more difficult for us to operate the ethanol plant profitably.

Research and Development

We are continually working to develop new methods of operating the ethanol plant more efficiently. We continue to conduct research and development activities in order to realize these efficiency improvements.

Governmental Regulation and Federal Ethanol Supports

Federal Ethanol Supports

The ethanol industry is dependent on several economic incentives to produce ethanol, including federal tax incentives and ethanol use mandates. One significant federal ethanol support is the Federal Renewable Fuels Standard (the “RFS”). The RFS requires that in each year, a certain amount of renewable fuels must be used in the United States. The RFS is a national program that does not require that any renewable fuels be used in any particular area or state, allowing refiners to use renewable fuel blends in those areas where it is most cost-effective. The RFS requirement increases incrementally each year until the United States is required to use 36 billion gallons of renewable fuels by 2022. Starting in 2009, the RFS required that a portion of the RFS must be met by certain “advanced” renewable fuels. These advanced renewable fuels include ethanol that is not made from corn, such as cellulosic ethanol and biomass based biodiesel. The use of these advanced renewable fuels increases each year as a percentage of the total renewable fuels required to be used in the United States.

The RFS for 2011 was approximately 14 billion gallons, of which corn based ethanol could be used to satisfy approximately 12 billion gallons. The RFS for 2012 is approximately 15.2 billion gallons, of which corn based ethanol can be used to satisfy approximately 13.2 billion gallons. Current ethanol production capacity exceeds the 2012 RFS requirement which can be satisfied by corn based ethanol.

In February 2010, the EPA issued new regulations governing the RFS. These new regulations have been called RFS2. The most controversial part of RFS2 involves what is commonly referred to as the lifecycle analysis of green house gas emissions. Specifically, the EPA adopted rules to determine which renewable fuels provided sufficient reductions in green house gases, compared to conventional gasoline, to qualify under the RFS program. RFS2 establishes a tiered approach, where regular renewable fuels are required to accomplish a 20% green house gas reduction compared to gasoline, advanced biofuels and biomass-based biodiesel must accomplish a 50% reduction in green house gases, and cellulosic biofuels must accomplish a 60% reduction in green house gases. Any fuels that fail to meet this standard cannot be used by fuel blenders to satisfy their obligations under the RFS program. The scientific method of calculating these green house gas reductions has been a contentious issue. Many in the ethanol industry were concerned that corn based ethanol would not meet the 20% green house gas reduction requirement based on certain parts of the environmental impact model that many in the ethanol industry believed was scientifically suspect. Our ethanol plant was grandfathered into the RFS due to the fact that it was constructed prior to the grandfathering date of the lifecycle green house gas requirement and is not required to prove compliance with the lifecycle green house gas reductions. In addition to the lifecycle green house gas reductions, many in the ethanol industry are concerned that certain provisions of RFS2 as adopted

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may disproportionately benefit ethanol produced from sugarcane. This could make sugarcane based ethanol, which is primarily produced in Brazil, more competitive in the United States ethanol market. If this were to occur, it could reduce demand for the ethanol that we produce.

Many in the ethanol industry believe that it will be difficult to meet the RFS requirement in future years without an increase in the percentage of ethanol that can be blended with gasoline for use in standard (non-flex fuel) vehicles. Most ethanol that is used in the United States is sold in a blend called E10. E10 is a blend of 10% ethanol and 90% gasoline. E10 is approved for use in all standard vehicles. Estimates indicate that gasoline demand in the United States is approximately 135 billion gallons per year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.5 billion gallons per year. This is commonly referred to as the “blend wall,” which represents a theoretical limit where more ethanol cannot be blended into the national gasoline pool. This is a theoretical limit because it is believed that it would not be possible to blend ethanol into every gallon of gasoline that is being used in the United States and it discounts the possibility of additional ethanol used in higher percentage blends such as E85 used in flex fuel vehicles. The RFS requires that 36 billion gallons of renewable fuels must be used each year by 2022, which equates to approximately 27% renewable fuels used per gallon of gasoline sold. In order to meet the RFS mandate and expand demand for ethanol, management believes higher percentage blends of ethanol must be utilized in standard vehicles.

In addition to the RFS, the ethanol industry depends on the Volumetric Ethanol Excise Tax Credit (“VEETC”). VEETC provides a volumetric ethanol excise tax credit of 45 cents per gallon of ethanol blended with gasoline. VEETC is currently set to expire on December 31, 2011 and is not expected to be extended past that date. If this tax credit is not extended, it likely would have a negative impact on the price of ethanol and demand for ethanol in the market due to reduced discretionary blending of ethanol. Discretionary blending is when gasoline blenders use ethanol to reduce the cost of blended gasoline. However, due to the RFS, we anticipate that demand for ethanol will continue to mirror the RFS requirement, even if the VEETC is not renewed past 2011. If the RFS is reduced or eliminated, the decrease in demand for ethanol related to the elimination of VEETC may be more substantial.

The USDA has announced that it will provide financial assistance to help implement more “blender pumps” in the United States in order to increase demand for ethanol and to help offset the cost of introducing mid-level ethanol blends into the United States retail gasoline market. A blender pump is a gasoline pump that can dispense a variety of different ethanol/gasoline blends. Blender pumps typically can dispense E10, E20, E30, E40, E50 and E85. These blender pumps accomplish these different ethanol/gasoline blends by internally mixing ethanol and gasoline which are held in separate tanks at the retail gas stations. Many in the ethanol industry believe that increased use of blender pumps will increase demand for ethanol by allowing gasoline retailers to provide various mid-level ethanol blends in a cost effective manner and allowing consumers with flex-fuel vehicles to purchase more ethanol through these mid-level blends. However, blender pumps cost approximately $25,000 each, so it may take time before they become widely available in the retail gasoline market.

Effect of Governmental Regulation

The government's regulation of the environment changes constantly. 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, expand and operate the plant. 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. Plant operations are governed by the Occupational Safety and Health Administration (“OSHA”). OSHA regulations may change such that the costs of operating the plant may increase. Any of these regulatory factors may result in higher costs or other adverse conditions effecting our operations, cash flows and financial performance.

We have obtained all of the necessary permits to operate the plant. During the transition period ended September 30, 2011, we incurred costs and expenses of approximately $1,215,000 complying with environmental laws, including the cost of obtaining permits. 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 in complying with such regulations.

United States ethanol production is currently benefited by a 54 cent per gallon tariff imposed on ethanol imported into the United States. The 54 cent per gallon tariff is currently set to expire on December 31, 2011 and is not expected to be extended past that date. If this tariff is eliminated, it could lead to the importation of ethanol produced in other countries, especially in areas of the United States that are easily accessible by international shipping ports. Currently, very little ethanol is imported to the United States from other countries.

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Employees

As of September 30, 2011 , we had 46 full-time employees. 39 of our employees are primarily involved in Plant operations and the other seven are primarily involved in management and administration.

Financial Information about Geographic Areas

All of our operations are domiciled in the United States. All of the products sold to our customers for the transition period of 2011, and fiscal years 2010 and 2009 were produced in the United States and all of our long-lived assets are domiciled in the United States. We have engaged third-party professional marketers who decide where our products are marketed and we have no control over the marketing decisions made by our marketer. Our marketers may decide to sell our products in countries other than the United States. Currently, a significant amount of distillers grains are exported to Mexico, Canada and China and the United States ethanol industry has recently experienced increased exports of ethanol to Europe. However, we anticipate that our products will still primarily be marketed and sold in the United States.

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

Increases in the price of corn or coal would reduce our profitability. Our results of operations and financial condition are significantly affected by the cost and supply of corn and coal. Changes in the price and supply of corn and coal are subject to and determined by market forces over which we have no control including weather and general economic factors.

Ethanol production requires substantial amounts of corn. Generally, higher corn prices may produce lower profit margins and, therefore, negatively affect our financial performance. Corn prices can be volatile and can increase significantly in a short period of time. If a period of high corn prices were to be sustained for some time, such pricing may reduce our ability to operate profitably because of the higher cost of operating our plant. We may not 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 negatively affected.

The prices for and availability of coal are subject to market conditions. These market conditions often are affected by factors beyond our control. Significant disruptions in the supply of coal could impair our ability to manufacture ethanol and distillers grains for our customers. Furthermore, increases in our coal costs relative to coal and natural gas costs paid by competitors may adversely affect our results of operations and financial condition. If we were to experience relatively higher corn and coal costs compared to the selling prices of our products for an extended period of time, we may not be able to profitably operate the ethanol plant.

Declines in the price of ethanol or distillers grains would significantly reduce our revenues. The sales prices of ethanol and distillers 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. We are dependent on a favorable spread between the price we receive for our ethanol and distillers grains and the price we pay for corn and coal. Any lowering of ethanol and distillers grains prices, especially if it is associated with increases in corn and coal prices, may affect our ability to operate profitably. We anticipate the price of ethanol and distillers grains to continue to be volatile in our 2012 fiscal year as a result of the net effect of changes in the price of gasoline and corn prices and increased ethanol supply offset by increased ethanol demand. Declines in the prices we receive for our ethanol and distillers grains will lead to decreased revenues and may result in our inability to operate the ethanol plant profitably for an extended period of time which could decrease the value of our units.

We may violate the terms of our credit agreements and financial covenants which could result in our lender demanding immediate repayment of our loans. We have a significant credit facility with FNBO. Our credit agreements with FNBO include various financial loan covenants. We are currently in compliance with all of our financial loan covenants. Current management projections indicate that we will be in compliance with our loan covenants for at least the next 12 months. However, unforeseen circumstances may develop which could result in us violating our loan covenants. If we violate the terms of our credit agreement, including our financial loan covenants, FNBO could deem us to be in default of our loans and require us to immediately repay

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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, we may fail which could decrease or eliminate the value of our units.

The ethanol industry is changing rapidly which can result in unexpected developments that could negatively impact our operations and the value of our units. The ethanol industry has grown significantly in the last decade. According to the Renewable Fuels Association, the ethanol industry has grown from approximately 1.5 billion gallons of production per year in 1999 to approximately 14.7 billion gallons in 2011. This rapid growth has resulted in significant shifts in supply and demand of ethanol over a very short period of time. As a result, past performance by the ethanol plant or the ethanol industry generally might not be indicative of future performance. We may experience a rapid shift in the economic conditions in the ethanol industry which may make it difficult to operate the ethanol plant profitably. If changes occur in the ethanol industry that make it difficult for us to operate the ethanol plant profitably, it could result in a reduction in the value of our units.

We engage in hedging transactions which involve risks that could 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 in the ethanol production process. We seek to minimize the risks from fluctuations in the prices of corn and ethanol through the use of hedging instruments. The effectiveness of our hedging strategies is dependent on the price of corn and ethanol and our ability to sell sufficient products to use all of the corn for which we have futures contracts. Our hedging activities may not 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 hedging transactions in the future and our operations and financial conditions may be adversely affected during periods in which corn prices increase. Utilizing cash for margin calls has an impact on the cash we have available for our operations which could result in liquidity problems during times when corn prices fall significantly.

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. However, it is likely that commodity cash prices will have the greatest impact on the derivative instruments with delivery dates nearest the current cash price. We may incur such costs and they may be significant which could impact our ability to profitably operate the plant and may reduce the value of our units.

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

We depend on our management and key employees, and the loss of these relationships could negatively impact our ability to operate profitably. We are highly dependent on our management team to operate our ethanol plant. We may not be able to replace these individuals should they decide to cease their employment with us, or if they become unavailable for any other reason. While we seek to compensate our management and key employees in a manner that will encourage them to continue their employment with us, they may choose to seek other employment. Any loss of these executive officers and key employees may prevent us from operating the ethanol plant profitably and could decrease the value of our units.

Changes and advances in ethanol production technology could require us to incur costs to update our plant or could otherwise hinder our ability to compete in the ethanol industry or operate profitably. Advances and changes in the technology of ethanol production are expected to occur. Such advances and changes may make the ethanol production technology installed in our plant less desirable or obsolete. These advances could also allow our competitors to produce ethanol at a lower cost than we are able. 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. These third-party licenses may not be available or, once obtained, they may not continue to be available on commercially reasonable terms. These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income.

Risks Related to Ethanol Industry

Growth in the ethanol industry is dependent on growth in the fuel blending infrastructure to accommodate ethanol, which may be slow and could result in decreased ethanol demand. The ethanol industry depends on the fuel blending industry to blend the ethanol that is produced with gasoline so it may be sold to the end consumer. In many parts of the country, the blending infrastructure cannot accommodate ethanol, so no ethanol is used in those markets. Substantial investments are required to expand

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this blending infrastructure and the fuel blending industry may choose not to expand the blending infrastructure to accommodate ethanol. Should the ability to blend ethanol not expand at the same rate as increases in ethanol supply, it may decrease the demand for ethanol which may lead to a decrease in the selling price of ethanol, which could impact our ability to operate profitably.

We operate in an intensely competitive industry and compete with larger, better financed entities which could impact our ability to operate profitably. There is significant competition among ethanol producers. There are numerous producer-owned and privately-owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. We also face competition from outside of the United States. The largest ethanol producers include Archer Daniels Midland, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, all of which are each capable of producing significantly more ethanol than we produce. Further, many believe that there will be further consolidation occurring in the ethanol industry in the future which will likely lead to a few companies which control a significant portion of the United States ethanol production market. We may not be able to compete with these larger entities. These larger ethanol producers may be able to affect the ethanol market in ways that are not beneficial to us which could negatively impact our financial performance.

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, plug-in hybrids, and electric cars or clean burning gaseous fuels. Like ethanol, these emerging technologies offer an option to address 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 these alternative technologies continue to expand and gain broad acceptance and become 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.

Consumer resistance to the use of ethanol based on the belief that ethanol is expensive, adds to air pollution, harms engines and/or takes more energy to produce than it contributes may affect the demand for ethanol. Certain individuals believe that the 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 natural gas, than the amount of energy that is produced. These consumer beliefs could potentially be wide-spread and may be increasing as a result of recent efforts to increase the allowable percentage of ethanol that may be blended for use in vehicles. If consumers choose not to buy ethanol based on these beliefs, it would affect the demand for the ethanol we produce which could negatively affect our profitability and financial condition.

Demand for ethanol may not continue to grow unless ethanol can be blended into gasoline in higher percentage blends for standard vehicles. Currently, ethanol is primarily blended with gasoline for use in standard (non-flex fuel) vehicles to create a blend which is 10% ethanol and 90% gasoline. Estimates indicate that approximately 135 billion gallons of gasoline are sold in the United States each year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.5 billion gallons. This is commonly referred to as the “blend wall,” which represents a theoretical limit where more ethanol cannot be blended into the national gasoline pool. Many in the ethanol industry believe that the ethanol industry is approaching this blending wall. In order to expand demand for ethanol, higher percentage blends of ethanol must be utilized in standard vehicles. Such higher percentage blends of ethanol are a contentious issue. Automobile manufacturers and environmental groups have fought against higher percentage ethanol blends. Recently, the EPA approved the use of E15 for standard vehicles produced in the model year 2007 and later as well as a partial waiver for E15 for use in MY2001-2006 light-duty motor vehicles. The fact that E15 has not been approved for use in all vehicles and the anticipated labeling requirements may lead to gasoline retailers refusing to carry E15. Without an increase in the allowable percentage blends of ethanol that can be used in all vehicles, demand for ethanol may not continue to increase which could decrease the selling price of ethanol and could result in our inability to operate the ethanol plant profitably. This could reduce or eliminate the value of our units.

Technology advances in the commercialization of cellulosic ethanol may decrease demand for corn based ethanol which may negatively affect our profitability. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. The Energy Independence and Security Act of 2007 and the 2008 Farm Bill offer a strong incentive to develop commercial scale cellulosic ethanol. The RFS requires that 16 billion gallons per year of advanced bio-fuels must be consumed in the United States by 2022. Additionally, state and federal grants have been awarded to several companies who are seeking to develop commercial-scale cellulosic ethanol plants. We expect this will encourage innovation that may lead to commercially viable cellulosic ethanol plants

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in the near future. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue and our financial condition will be negatively impacted.

New plants under construction or decreases in ethanol demand may result in excess production capacity in our industry . The supply of domestically produced ethanol is at an all-time high. According to the Renewable Fuels Association, as of November 16, 2011 there are 209 ethanol plants in the United States with capacity to produce approximately 14.7 billion gallons of ethanol per year. In addition, there are approximately 8 new ethanol plants under construction or expanding which together are estimated to increase ethanol production capacity by 271 million gallons per year. Excess ethanol production capacity may have an adverse impact on our results of operations, cash flows and general financial condition. According to the Renewable Fuels Association, approximately 3.6% of the ethanol production capacity in the United States was idled as of November 16, 2011, the most recent available data. During the early part of 2009 when the ethanol industry was experiencing unfavorable operating conditions, as much as 20% of the ethanol production in the United States may have been idled. Further, ethanol demand may not increase past approximately 13 billion gallons of ethanol due to the blending wall unless higher percentage blends of ethanol are approved by the EPA for use in standard (non-flex fuel) vehicles. If ethanol demand does not grow at the same pace as increases in supply, we expect the selling price of ethanol to decline. If excess capacity in the ethanol industry continues to occur, the market price of ethanol may decline to a level that is inadequate to generate sufficient cash flow to cover our costs. This could negatively affect our profitability.

Decreasing gasoline prices may negatively impact the selling price of ethanol which could reduce our ability to operate profitably . The price of ethanol tends to change partially in relation to the price of gasoline. Decreases in the price of ethanol reduce our revenue. Our profitability depends on a favorable spread between our corn and coal costs and the price we receive for our ethanol. If ethanol prices fall during times when corn and/or coal prices are high, we may not be able to operate our ethanol plant profitably.

Risks Related to Regulation and Governmental Action

Government incentives for ethanol production, including federal tax incentives, may be eliminated in the future, which could hinder our ability to operate at a profit . The ethanol industry is assisted by various federal ethanol production and tax incentives, including the Renewable Fuels Standard (RFS). The RFS helps support a market for ethanol that might disappear without this incentive; as such, waiver of RFS minimum levels of renewable fuels required in gasoline could negatively impact our results of operations.

In addition, the elimination or reduction of tax incentives to the ethanol industry, such as the VEETC available to gasoline refiners and blenders, could also reduce the market demand for ethanol, which could reduce ethanol prices and our revenue. If the federal tax incentives are eliminated or sharply curtailed, we believe that decreased ethanol demand will result, which could negatively impact our ability to operate profitably.

Also, elimination of the tariffs that protect the United States ethanol industry could lead to the importation of ethanol produced in other countries, especially in areas of the United States that are easily accessible by international shipping ports. The tariff that protects the United States ethanol industry expires at the end of 2011 which could lead to increased ethanol supplies and decreased ethanol prices.

Changes in environmental regulations or violations of these 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. In the future, we may 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 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.

Carbon dioxide may be regulated in the future by the EPA as an air pollutant requiring us to obtain additional permits and install additional environmental mitigation equipment, which could adversely affect our financial performance . In 2007, the Supreme Court decided a case in which it ruled that carbon dioxide is an air pollutant under the Clean Air Act for purposes of motor vehicle emissions. The Supreme Court directed the EPA to regulate carbon dioxide from vehicle emissions as a pollutant under the Clean Air Act. Similar lawsuits have been filed to require the EPA to regulate carbon dioxide emissions from stationary

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sources such as our ethanol plant under the Clean Air Act. Our Plant produces a significant amount of carbon dioxide that we currently vent into the atmosphere. While there are currently no regulations applicable to us concerning carbon dioxide, if the EPA or the State of North Dakota were to regulate carbon dioxide emissions by plants such as ours, we may have to apply for additional permits or we may be required to install carbon dioxide mitigation equipment or take other as yet unknown steps to comply with these potential regulations. Compliance with any future regulation of carbon dioxide, if it occurs, could be costly and may prevent us from operating the ethanol plant profitably which could decrease or eliminate the value of our units.

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.

The site also contains improvements such as rail tracks and a rail spur, landscaping, drainage systems and paved access roads. Our Plant was placed in service in January 2007 and is in excellent condition and is capable of functioning at 100 percent of its 50 million gallon name-plate production capacity.

All of our tangible and intangible property, real and personal, serves as the collateral for our senior credit facility with FNBO. Our senior credit facility is discussed in more detail under “ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS - Liquidity and Capital Resources.”

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.

ITEM 4. (REMOVED AND RESERVED)

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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. Please see the table below for information on the prices of units transferred in transactions completed via the QMS. 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. As a limited liability company, we are required to restrict the transfers of our membership units in order to preserve our partnership tax status. Our membership units may not be traded on any established securities market or readily trade on a secondary market (or the substantial equivalent thereof). All transfers are subject to a determination that the transfer will not cause the Company to be deemed a publicly traded partnership.

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.

As of September 30, 2011, there were 933 holders of record of our Class A units.

The following table contains historical information by quarter for the past two years regarding the actual unit transactions that were completed by our unit-holders during the periods specified. Trading was suspended from May 21, 2010 through December 31, 2010. The information was compiled by reviewing the completed unit transfers that occurred on the QMS bulletin board or through private transfers during the quarters indicated.

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Quarter	Low Price		High Price		Average Price		# of Units Traded
2010 1 ^st	$	—	$	—	$	—	—
2010 2 ^nd	$	0.50	$	0.50	$	0.50	10,000
2010 3 ^rd	$	—	$	—	$	—	—
2010 4 ^th	$	—	$	—	$	—	—
2011 1 ^st	$	0.50	$	0.50	$	0.50	10,000
2011 2 ^nd	$	0.62	$	0.65	$	0.65	74,000
2011 3 ^rd	$	—	$	—	$	—	—

As a limited liability company, we are required to restrict the transfers of our membership units in order to preserve our partnership tax status. Our membership units may not be traded on any established securities market or readily traded on a secondary market (or the substantial equivalent thereof). All transfers are subject to a determination that the transfer will not cause us to be deemed a publicly traded partnership.

DISTRIBUTIONS

We did not make any distributions to our members for the transition period ended September 30, 2011 , or the fiscal years ended December 31, 2010 or 2009. 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.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected financial and operating data as of the dates and for the periods indicated. The selected balance sheet financial data as of December 31, 2009, 2008 and 2007 and the selected income statement data and other financial data for the years ended December 31, 2008 and 2007 have been derived from our audited financial statements that are not included in this Form 10-K. The selected balance sheet financial data as of September 30, 2011 and December 31, 2010 and the selected statement of operations data and other financial data for the transition period ended September 30, 2011 and each of the two years in the two year period ended December 31, 2010 have been derived from the audited Financial Statements included elsewhere in this Form 10-K. You should read the following table in conjunction with “ Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations ” and the financial statements and the accompanying notes included elsewhere in this Form 10-K. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following financial data.

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		Nine-Month Transition Period Ended		Fiscal Year Ended December 31
Statement of Operations Data:		September 30, 2011		2010			2009			2008			2007
Revenues	$	112,290,222	$	109,895,184		$	93,836,661		$	131,903,514		$	101,885,969

Cost of Goods Sold		108,137,084		95,946,218			87,850,869			131,025,238			87,013,208

Gross Profit		4,153,138		13,948,966			5,985,792			878,276			14,872,761

General and Administrative		1,972,679		3,116,212			2,812,891			2,857,091			3,214,002

Operating Income (Loss)		2,180,459		10,832,754			3,172,901			(1,978,815	)		11,658,759

Other Income (Expense)		1,671,836		(1,803,982	)		(2,812,241	)		(3,387,757	)		(5,501,431	)

Net Income (Loss)	$	3,852,295	$	9,028,772		$	360,660		$	(5,366,572	)	$	6,157,328

Weighted Average Units Outstanding - Basic		40,193,973		40,193,973			40,191,494			40,176,974			40,371,238

Weighted Average Units Outstanding - Diluted		40,213,973		40,193,973			40,191,494			40,176,974			40,371,238

Net Income (Loss) Per Unit - Basic and Diluted	$	0.10	$	0.22		$	0.01		$	(0.13	)	$	0.15



		Nine-Month Transition Period Ended			Fiscal Year Ended December 31
Balance Sheet Data:		September 30, 2011			2010			2009			2008			2007
Current Assets	$	24,318,071		$	22,292,500		$	25,384,612		$	16,423,730		$	8,231,709

Net Property and Equipment		63,363,997			66,544,644			71,415,582			78,010,042			81,942,542

Total Assets		89,197,878			89,924,953			97,677,401			95,802,453			108,524,254

Current Liabilities		42,060,094			20,451,155			18,634,421			61,968,448			16,807,461

Long-Term Liabilities		361,353			26,569,662			45,167,616			275,000			52,813,310

Members' Equity		46,776,431			42,904,136			33,875,364			33,559,005			38,903,483

Book Value Per Unit		$	1.17		$	1.07		$	0.84		$	0.84		$	0.96

* See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for further discussion of our financial results.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This report contains forward-looking statements that involve future events, our future performance and our expected future operations and actions. In some cases you can identify forward-looking statements by the use of words such as “may,” “will,” “should,” “anticipate,” “believe,” “expect,” “plan,” “future,” “intend,” “could,” “estimate,” “predict,” “hope,” “potential,” “continue,” or the negative of these terms or other similar expressions. These forward-looking statements are only our predictions and involve numerous assumptions, risks and uncertainties. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the reasons described in this report. We are not under any duty to update the forward-looking statements contained in this report. We cannot guarantee future results, levels of activity, performance or achievements. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. You should read this report and the documents that we reference in this report and have filed as exhibits, completely and with the understanding that our actual future results may be materially different from what we currently expect. We qualify all of our forward-looking statements by these cautionary statements.

Change in Fiscal Year End

On January 1, 2011, our board of governors approved the change in our fiscal year end from December 31 to September 30, effective January 1, 2011. As a result of this change, this Annual Report on Form 10-K is a transition report and includes financial information for the nine-month transition period from January 1, 2011 to September 30, 2011, or transition period. References in this Transition Report on Form 10-K to fiscal year 2010 or fiscal 2010 refer to the period of January 1, 2010 through December 31, 2010 and references to fiscal year 2009 or fiscal 2009 refer to the period of January 1, 2009 through December 31, 2009. Subsequent to this Transition Report on Form 10-K, our reports on Form 10-K will cover the fiscal year from October 1 to September 30 with historical periods remaining unchanged.

Overview

Red Trail Energy, LLC, a North Dakota limited liability company (the “Company,” “Red Trail,” or “we,” “our,” or “us”), owns and operates a 50 million gallon annual name-plate production ethanol plant near Richardton, North Dakota (the “Plant”). Our revenues are derived from the sale and distribution of our ethanol and distillers grains primarily in the continental United States. Corn is our largest cost component and our profitability is highly dependent on the spread between the price of corn and the price of ethanol.

Results of Operations

Comparison of the Nine Month Transition Period Ended September 30, 2011 and Fiscal Year Ended December 31, 2010

The following table shows the results of our operations and the approximate percentage of revenues, costs of sales, operating expenses and other items to total revenues in our statements of operations for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010 :



	Transition Period Ended September 30, 2011			Fiscal Year Ended December 31, 2010
Statement of Operations Data	Amount		%	Amount			%
Revenues	$	112,290,222	100.00	$	109,895,184		100.00
Cost of Goods Sold	108,137,084		96.30	95,946,218			87.31
Gross Profit	4,153,138		3.70	13,948,966			12.69
General and Administrative Expenses	1,972,679		1.76	3,116,212			2.84
Operating Income	2,180,459		1.94	10,832,754			9.86
Other Income (Expense)	1,671,836		1.49	(1,803,982		)	(1.64	)
Net Income	$	3,852,295	3.43	$	9,028,772		8.22

The following table shows additional data regarding production and price levels for our primary inputs and products for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010 :

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	Nine Month Transition Period Ended September 30, 2011		Fiscal Year Ended December 31, 2010
Production:
Ethanol sold (gallons)	37,327,103		52,172,843
Dried distillers grains sold (tons)	81,046		133,620
Modified distillers grains sold (tons)	40,329		54,706
Revenues:
Ethanol average price/gallon (net of hedging)	$	2.52	$	1.73
Dried distillers grains price/ton	$	176.72	$	107.63
Modified distillers grains price/ton	$	91.46	$	58.42
Primary Input:
Corn ground (bushels)	13,285,113		18,956,725
Costs of Primary Input:
Corn avg price/bushel (net of hedging)	$	6.76	$	3.81
Other Costs (per gallon of ethanol sold):
Chemical and additive costs	$	0.093	$	0.083
Denaturant cost	$	0.053	$	0.044
Electricity cost	$	0.047	$	0.045
Direct Labor cost	$	0.048	$	0.039

Revenue

In the transition period ended September 30, 2011 ethanol sales comprised approximately 84.0% of our revenues and distillers grains sales comprised approximately 16.0% of our revenues. For the fiscal year ended December 31, 2010 , ethanol sales comprised approximately 83% of our revenues and distillers grains sales comprised approximately 17% of our revenue. Our ethanol revenues were higher as a percentage of our revenues for our transition period ended September 30, 2011 compared to the fiscal year ended December 31, 2010 primarily as a result of an increase in the sales price of our ethanol.

The average ethanol sales price we received for the transition period ended September 30, 2011 was approximately 46% higher than our average ethanol sales price for the fiscal year ended December 31, 2010 . Management anticipates that ethanol prices will continue to be subject to influences from the prices of oil and gasoline along with the uncertainties surrounding commodity markets generally and certain federal legislation regarding ethanol blending and usage in the United States.

The price we received for our dried distillers grains increased by approximately 64% during the transition period ended September 30, 2011 compared to the fiscal year ended December 31, 2010 . The price of dried distillers grains changes in proportion to the price of corn, which has increased in the transition period ended September 30, 2011 . Accordingly, we anticipate that the market price of distillers grains will continue to be volatile as a result of changes in the price of corn and competing animal feed substitutes such as soybean meal.

Cost of Goods Sold

Our cost of goods sold as a percentage of revenues were approximately 96% for the transition period ended September 30, 2011 compared to approximately 87% for the same period of 2010 . Our cost of goods sold increased by approximately 13% in the transition period ended September 30, 2011 , compared to the fiscal year ended ended December 31, 2010 . This increase in the cost of goods sold is primarily a result of an increase in the cost of corn processed at our facility. The increase in our revenues is due primarily to an increase in the price we received for our ethanol.

General and Administrative Expenses

Our general and administrative expenses as a percentage of revenues were lower for the transition period ended September 30, 2011 than they were for the fiscal year ended December 31, 2010 . These percentages were approximately 1.8% and approximately 2.8% for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010 , respectively. We experienced a decrease in actual general and administrative expenses of approximately $1,144,000 for the transition period ended ended September 30, 2011 as compared to the fiscal year ended 2010 . This decrease was primarily due to comparing a nine-month reporting period to a twelve-month reporting period. Our efforts to optimize efficiencies and maximize production

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may result in a decrease in our general and administrative expenses on a per gallon basis. We expect our operating expenses to remain steady into our 2012 fiscal year.

Operating Income

Our income from operations for the transition period ended September 30, 2011 was approximately 1.9% of our revenues compared to income of approximately 9.9% of our revenues for the fiscal year ended December 31, 2010 . This decrease in our profitability is primarily due to our cost of goods sold as a percentage of revenues being higher for the transition period ended September 30, 2011 compared to the fiscal year ended December 31, 2010 . During the same period we experienced a $2.82 per bushel increase in our cost of corn (net of hedging).

Other Income/Expense

Other income for the transition period ended September 30, 2011 , was approximately 1.5% of our revenue and totaled $1,671,836 . Other expense for the fiscal year ended December 31, 2010 totaled $1,803,982 and was approximately (1.6)% of our revenues. The increase in other income is primarily due to recognition of the alternative fuel tax credit of approximately $3,200,000 which we were not eligible to receive in 2010. The decrease in other expense is primarily due to a decrease in interest expense of approximately $1,600,000 due to principal reductions of our outstanding long-term debt.

Changes in Financial Condition at September 30, 2011 and the Fiscal Year Ended December 31, 2010

Current Assets . Our accounts receivable were higher at September 30, 2011 compared to December 31, 2010 due to the majority of our receivables being sales of ethanol which was at a higher price per gallon in 2011 compared to 2010 . We also recorded a receivable of approximately $1,500,000 related to the refundable alternative fuel burning tax credit in 2011 which we were not eligible for in 2010. The value of our inventory was higher at September 30, 2011 compared to December 31, 2010 primarily because corn and ethanol prices were higher at September 30, 2011 . Our inventory is valued at the lesser of our cost associated with the our inventory or the market value of our inventory. When corn and ethanol prices increase, it results in a larger value being attributed to our inventory, even if the amount of ethanol and corn that we are holding in inventory is comparable. The amount we had in our restricted commodity derivatives margin account was lower at September 30, 2011 compared to December 31, 2010 because we held a lower number of positions. Our prepaid expenses were higher at September 30, 2011 compared to December 31, 2010 primarily due to the timing of an advance payment for services rendered during our fall shutdown in October.

Property, Plant and Equipment . The gross value of our property, plant and equipment was higher at September 30, 2011 compared to December 31, 2010 primarily due to placing our alternative fuel burning capital project in service May 2011. The net value of our property and equipment was lower at September 30, 2011 compared to December 31, 2010 primarily as a result of increases in our accumulated depreciation. The increase in our construction in progress at September 30, 2011 compared to December 31, 2010 was primarily due expenditures related to a water treatment capital project.

Other Assets . Our other assets were higher at September 30, 2011 compared to December 31, 2010 due to patronage equity of approximately $77,000 we received during the transition period ended September 30, 2011 .

Current Liabilities . Our current liabilities were significantly higher at September 30, 2011 compared to December 31, 2010 , primarily due to the outstanding balance of our primary bank debt with First National Bank of Omaha (the "Bank") being classified as a current liability due to its maturity in April 2012. Loss on firm purchase commitments is also higher at September 30, 2011 compared to December 31, 2010 due to certain contract prices entered into being higher than market prices as of September 30, 2011 .

Long-term Liabilities . Our long-term liabilities were significantly lower at September 30, 2011 compared to December 31, 2010 , primarily due to our primary bank debt with the Bank being classified as a current liability as of September 30, 2011 .

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Comparison of Fiscal Years Ended December 31, 2010 and 2009

The following table shows the results of our operations and the approximate percentage of revenues, costs of sales, operating expenses and other items to total revenues in our statements of operations for the fiscal years ended December 31, 2010 and fiscal year ended December 31, 2009:



	2010					2009
Statement of Operations Data	Amount			%		Amount			%
Revenues	$	109,895,184		100.00		$	93,836,661		100.00
Cost of Goods Sold	95,946,218			87.31		87,850,869			93.62
Gross Profit	13,948,966			12.69		5,985,792			6.38
General and Administrative Expenses	3,116,212			2.84		2,812,891			3.00
Operating Income	10,832,754			9.86		3,172,901			3.38
Other Expense	(1,803,982		)	(1.64	)	(2,812,241		)	(3.00	)
Net Income	$	9,028,772		8.22		$	360,660		0.38

Revenue

We experienced a significant increase in our total revenue for our 2010 fiscal year compared to our 2009 fiscal year. Management attributes this increase primarily to significant increases we experienced in the average prices we received for our ethanol and distillers grains during fiscal year 2010 compared to fiscal year 2009. We also experienced an increase in the total amount of ethanol and distillers grains we sold during our 2010 fiscal year compared to our 2009 fiscal year. For our 2010 fiscal year, ethanol sales comprised approximately 84% of our total revenue and distillers grains comprised approximately 16% of our total revenue. For our 2009 fiscal year, ethanol sales comprised approximately 83% of our total revenue and distillers grains comprised approximately 17% of our total revenue.

Ethanol

Our ethanol revenue for our 2010 fiscal year was approximately 14% more than during our 2009 fiscal year. The total gallons of ethanol sold during our 2010 fiscal year was approximately 5% more than during our 2009 fiscal year. Management attributes this increase in ethanol sales with the fact that we operated the plant at a higher run rate and produced more ethanol for sale. In addition to the increased volume of ethanol sales, increased ethanol prices also contributed to this increase in revenue. The increase in the average price, net of hedging, per gallon of ethanol sold during 2010 as compared to 2009 was approximately 13%. Management attributes this increase in the average price of ethanol to higher corn and gasoline prices as well as increased ethanol exports during our 2010 fiscal year.

Distillers Grains

We produce distillers grains for sale primarily in two forms, distillers dried grains with solubles (DDGS) and modified distillers grains with solubles (MDGS). As compared to fiscal 2009, we experienced a shift in the mix of distillers grains we sold in the form of DDGS versus MDGS. During our 2010 fiscal year, we sold approximately 71% of our total distillers grains in the form of DDGS and approximately 29% of our total distillers grains in the form of MDGS. During our 2009 fiscal year, we sold approximately 56% of our total distillers grains in the form of DDGS and approximately 44% of our total distillers grains in the form of MDGS. Management attributes this shift in the mix of our distillers grains sales with an increase in export demand for dried distillers grains during our 2010 fiscal year compared to our 2009 fiscal year. As more of our distillers grains are shipped outside of our local market, we sell more of our distillers grains in the dried form since it is less expensive to ship DDGS and the shelf life of DDGS is much longer than MDGS. Market factors dictate whether we sell more DDGS versus MDGS.

We sold approximately 26% more tons of DDGS during our 2010 fiscal year compared to our 2009 fiscal year. Management attributes this increase in DDGS sales with increased production of ethanol during the 2010 fiscal year and an increase in the demand for DDGS compared to our 2009 fiscal year. Offsetting the increase in DDGS sales was a decrease of approximately 2% in the average price we received per ton of DDGS sold during our 2010 fiscal year compared to our 2009 fiscal year.

As a result of the increased export demand for distillers grains discussed above, we sold approximately 33% fewer tons of MDGS during our 2010 fiscal year compared to our 2009 fiscal year. Despite the decrease in MDGS sold, the average price we received per ton of MDGS sold increased by approximately 9% during our 2010 fiscal year compared to our 2009 fiscal year.

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Cost of Goods Sold

Our two primary costs of producing ethanol and distillers grains are corn and coal costs. We experienced an increase of approximately 9% in our cost of goods sold for our 2010 fiscal year compared to our 2009 fiscal year.

Corn Costs

Our largest cost associated with the production of ethanol and distillers grains is our cost of corn. The total amount we paid for corn, net of hedging, during our 2010 fiscal year was approximately 7% higher than the amount we paid during our 2009 fiscal year. The total bushels of corn that we purchased during our 2010 fiscal year was approximately 5% greater compared to our 2009 fiscal year. This increase in corn purchases was due to our increased ethanol and distillers grains production during our 2010 fiscal year compared to our 2009 fiscal year.

Realized and unrealized losses related to our corn derivative instruments resulted in an increase of approximately $1,826,000 in our cost of goods sold for our 2010 fiscal year compared to an increase of approximately $475,000 in our cost of goods sold for our 2009 fiscal year. We recognize the gains or losses that result from the changes in the value of our derivative instruments related to corn in cost of goods sold as the changes occur. As corn prices fluctuate, the value of our derivative instruments are impacted, which affects our financial performance. We anticipate continued volatility in our cost of goods sold due to the timing of the changes in value of the derivative instruments relative to the cost and use of the commodity being hedged.

Coal Costs

Our total cost of goods sold attributed to coal increased by approximately 3% during our 2010 fiscal year compared to our 2009 fiscal year, primarily due to an 11% increase in the amount of coal used. This increase in coal consumption was due to our increased production of ethanol and our increase in production of distillers grains in the dried form compared to the modified form during our 2010 fiscal year. As we produce more DDGS, our coal consumption increases because we use coal to fire our distillers grains dryers. Our increase in coal consumption was partially offset by a 7% decrease in our average per ton cost of coal during our 2010 fiscal year compared to our 2009 fiscal year. Management attributes this decrease in our per ton cost of coal with lower market coal prices due to increased coal supplies and relatively stable coal demand.

General and Administrative Expenses

Our general and administrative expenses increased by approximately 9% for our 2010 fiscal year compared to our 2009 fiscal year. Management attributes this increase in general and administrative expenses to increased legal fees associated with the mediation proceedings with our design builder. We also incurred an increase in our real estate taxes as our tax exemption was phased out during our 2010 fiscal year.

Other Expense

We had net other expense during our 2010 fiscal year of approximately $1,800,000 compared to net other expense of approximately $2,800,000 during our 2009 fiscal year. We had less interest income during our 2010 fiscal year compared to our 2009 fiscal year due to having less cash on hand during the 2010 period. Our interest expense decreased significantly during our 2010 fiscal year compared to our 2009 fiscal year due to our continuing retirement of our long-term debt during our 2010 fiscal year that resulted in a lower interest rate that accrues on our credit facilities. Additionally, we experienced a net of approximately $700,000 interest expense from our swap agreements for the year ended December 31, 2010 as compared to approximately $500,000 in 2009. Our net other expense was partially offset by other income of approximately $983,000 we received in January 2010 from a business interruption insurance claim related to an unplanned outage at our plant during October 2009.

Changes in Financial Condition for Fiscal Years Ended December 31, 2010 and 2009

Assets

Our accounts receivable was higher at December 31, 2010 compared to December 31, 2009 due to a combination of higher ethanol prices at December 31, 2010 compared to December 31, 2009 and timing differences related to the amount of gallons of ethanol for which we were waiting for payment. We had less cash on hand during our 2010 fiscal year compared to our 2009 fiscal year due to having used cash to pay down a significant portion of our long-term debt during our 2010 fiscal year.

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Our net property, plant and equipment was lower at December 31, 2010 compared to December 31, 2009 due to our continued depreciation of assets which increased accumulated depreciation. We had construction in progress of approximately $442,000 at December 31, 2010, all of which relates to a flue gas recirculation project. This project will allow the plant to introduce low oxygen air into the combustor allowing greater control of the furnace bed and vapor space temperature resulting in reduced thermal NOx conversion, reduced ID & FD fan load, and will allow for the implementation of a syrup injection system.

Our other assets were higher at December 31, 2010 compared to December 31, 2009, primarily due to increases in the patronage equity in CHS and Roughrider Electric. Our patronage equity increased by approximately $250,000 during our 2010 fiscal year.

Liabilities

The current portion of our long-term debt was approximately $2,425,000 higher at December 31, 2010 compared to December 31, 2009. The higher amount we are scheduled to pay during our 2011 fiscal year is a result of our previously established payment schedule for our term loans with FNBO. The scheduled maturity date on these term notes is April 2012.

Our accounts payable was higher at December 31, 2010 compared to December 31, 2009 due primarily to higher corn prices that increased the amount that was due to our corn suppliers at December 31, 2010. Our liability associated with our ethanol derivative instruments was zero at December 31, 2010 compared to approximately $800,000 at December 31, 2009 as there were no ethanol derivative contracts outstanding at December 31, 2010.

Our liability associated with our long-term debt was significantly lower at December 31, 2010 compared to December 31, 2009 due to loan balances of approximately $12,000,000 being paid off in 2010 in addition to our continuing debt service payments.

Application of 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.

Inventory Valuation

The Company values inventory at the lower of cost or market. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. These valuations require the use of management's assumptions which do not reflect unanticipated events and circumstances that may occur. In our analysis, we consider future corn costs and ethanol prices, break-even points for our plant and our risk management strategies in place through our derivative instruments.

Patronage Equity

The Company receives, from certain vendors organized as cooperatives, patronage dividends, which are based on several criteria, including the vendor's overall profitability and the Company's purchases from the vendor. Patronage equity typically represents the Company's share of the vendor's undistributed current earnings which will be paid in either cash or equity interests to the Company at a future date. Because these patronage dividends are in return for the Company's current purchases, the Company records the value of these future payments using a discounting approach that incorporates interest and collection risk factors. Those patronage dividends to be paid in equity interests are recognized in the balance sheets at cost and analyzed for impairment at each period end.

Firm Purchase Commitments

The Company typically enters into fixed price contracts to purchase corn to ensure an adequate supply of corn to operate its plant. The Company will generally seek to use exchange traded futures, options or swaps as an offsetting position. The Company closely monitors the number of bushels hedged using this strategy to avoid an unacceptable level of margin exposure. Contract prices are analyzed by management at each period end and, if necessary, valued at the lower of cost or market in the balance sheets.

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Long Lived Assets

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Impairment testing for assets requires various estimates and assumptions, including an allocation of cash flows to those assets and, if required, an estimate of the fair value of those assets. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. These valuations require the use of management's assumptions, which do not reflect unanticipated events and circumstances that may occur.

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 property, plant and equipment. Amortization of equipment under capital leases is included in depreciation expense.

Derivative Instruments

The Company evaluates its contracts to determine whether the contracts are derivative instruments. Certain contracts that literally meet the definition of a derivative may be exempted from derivative accounting and treated as normal purchases or normal sales if documented as such. 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.

The Company enters into short-term cash, option and futures contracts as a means of securing corn for the ethanol plant and managing exposure to changes in commodity prices. All of the Company's derivatives are designated as non-hedge derivatives, with changes in fair value recognized in net income. Although the contracts are economic hedges of specified risks, they are not designated as and accounted for as hedging instruments.

As part of its trading activity, the Company uses futures and option contracts through regulated commodity exchanges to manage its risk related to pricing of inventories. To reduce that risk, the Company generally takes positions using cash and futures contracts and options.

Realized and unrealized gains and losses related to derivative contracts related to corn are included as a component of cost of goods sold and derivative contracts related to ethanol are included as a component of revenues in the accompanying financial statements. The fair values of contracts entered through commodity exchanges are presented on the accompanying balance sheet as derivative instruments.

Liquidity and Capital Resources

Based on financial forecasts performed by our management, we anticipate that we will have sufficient cash from our current credit facilities and cash from our operations to continue to operate the ethanol plant at capacity for the next 12 months. We do not anticipate seeking additional equity or debt financing in the next 12 months. However, should we experience unfavorable operating conditions in the future, we may have to secure additional debt or equity financing for working capital or other purposes.

Our primary sources of liquidity are cash on hand, cash generated from our operations and amounts that we can draw on our revolving lines of credit. As of September 30, 2011, we had approximately $4,700,000 in cash and approximately $6,250,000 available with a maturity date of April 2012. A $750,000 portion of our available revolving line of credit is restricted. We do not anticipate having insufficient sources of liquidity to continue to operate our ethanol plant and for anticipated capital expenditures related to maintaining our ethanol plant for the next twelve month period.

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The following table shows cash flows for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010:



	Nine-Month Transition Period Ended September 30, 2011			December 31, 2010
Net cash provided by (used in) operating activities	$	(835,836	)	$	13,086,271
Net cash used in investing activities	(797,378		)	(1,071,740		)
Net cash used for financing activities	(3,497,355		)	(15,425,056		)
Net decrease in cash	$	(5,130,569	)	$	(3,410,525	)

Cash and cash equivalents, end of period	$	4,672,997		$	9,803,566

Cash Flow from Operations

Cash used for operating activities was $ 835,836 for the transition period ended September 30, 2011 as compared to $ 13,086,271 cash provided by operating activities for the fiscal year ended December 31, 2010 . Our net income from operations for the transition period ended September 30, 2011 was $3,852,295 as compared to net income of $9,028,772 for the fiscal year ended December 31, 2010 . In addition to the change in net income, higher ethanol and corn prices both contributed to significantly higher accounts receivable and inventory balances as of September 30, 2011 .

Cash Flow From Investing Activities

We experienced a decrease in cash used in investing activities for the transition period ended September 30, 2011 compared to the fiscal year ended 2010 . Cash used in investing activities was $ 797,378 for the transition period ended September 30, 2011 as compared to $ 1,071,740 to the fiscal year ended 2010 . All of the cash used in investing activities in both 2011 and 2010 was for capital expenditures.

Cash Flow from Financing Activities

We had a decrease in cash used for financing activities for the transition period ended September 30, 2011 as compared to the fiscal year ended December 31, 2010. Cash used for financing activities was $ 3,497,355 for the transition period ended September 30, 2011 . This cash flow is payment on our long term debt.

Our liquidity, results of operations and financial performance will be impacted by many variables, including the market price for commodities such as, but not limited to corn, ethanol and other energy commodities, as well as the market price for any co-products generated by the facility and the cost of labor and other operating costs. Assuming future relative price levels for corn, ethanol and distillers grains remain consistent we expect operations to generate adequate cash flows to maintain operations.

The following table shows cash flows for the fiscal years ended December 31, 2010 and 2009:



	Year ended December 31,
	2010			2009
Net cash provided by operating activities	$	13,086,271		$	7,936,258
Net cash provided by (used in) investing activities	(1,071,740		)	532,170
Net cash provided by (used in) financing activities	(15,425,056		)	311,824

Cash Flow From Operations

Our net income increased significantly for our 2010 fiscal year compared to our 2009 fiscal year which increased the amount of cash provided by our operating activities during the 2010 period. This increase was primarily due to increased volumes, prices and margins of our products.

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Cash Flow From Investing Activities

We used more cash for capital expenditures during our 2010 fiscal year compared to our 2009 fiscal year. For our 2010 fiscal year, our primary capital expenditures consisted of $1,207,000 which includes approximately $765,000 of investments into plant equipment and approximately $442,000 of construction in progress. For our 2009 fiscal year, we had minimal capital expenditures. Our only cash provided by investing activities during our 2010 fiscal year was approximately $135,000 from the disposal of a trackmobile loader and a mower. During our 2009 fiscal year we had approximately $764,000 provided by a sales tax refund on certain fixed assets. This tax refund was partially offset by cash used to make an investment in RPMG during our 2009 fiscal year.

Cash Flow From Financing Activities

We used significantly more cash for our financing activities during our 2010 fiscal year compared to our 2009 fiscal year. Our financing activities provided cash for our operations during our 2009 fiscal year, primarily related to the additional long-term debt we obtained from our lender. During our 2010 fiscal year, we used approximately $15,425,000 of cash to pay down our long-term debt obligations.

Capital Expenditures

The Company currently has two capital projects in progress with approximately $540,000 incurred as of September 30, 2011 . One of these projects is improvements to the plant's water treatment system and the other is installation of new bin sweeps in the plant's corn silos. We anticipate the completion of both of these projects to occur in the first quarter of fiscal 2012. The estimated total cost of these two projects is $750,000 and we anticipate being able to fund the balance of these capital projects from our operating cash flows. During the transition period ended September 30, 2011 , the Company placed in service approximately $900,000 for capital projects with the majority of these costs related to the Company's alternative fuel burning capital project. The alternative fuel burning project was placed in service in early May 2011 and allows the Plant to burn alternative fuel along with its primary fuel source of coal, thereby reducing the Plant's coal usage. In October 2011, the Company entered into an agreement to purchase a corn oil extraction system with plans for the system to be installed and operational during the 2012 fiscal year. The total cost of this system is expected to be approximately $2.4 million dollars.

Capital Resources

Short-Term Debt Sources

The Company has a revolving line-of-credit of $7,000,000 available with a maturity date of April 2012. There were no amounts drawn on this line-of-credit as of September 30, 2011 .

Long-Term Debt Sources

Our primary debt instruments are with First National Bank of Omaha (the “Bank”) and have a scheduled maturity date of April 2012. These debt instruments include fixed and variable rate notes and the Company has had preliminary conversations with the Bank about refinancing this debt but has not entered into a refinancing arrangement as of December 13, 2011 .

The following table summarizes our long-term debt instruments with the Bank.



	Outstanding Balance (Millions)				Interest Rate						Range of Estimated
Term Note	September 30, 2011		December 31, 2010		September 30, 2011			December 31, 2010			Quarterly Principal Payment Amounts	Notes
Fixed Rate Note	$	18.3	$	21.3		6.00	%		6.00	%	$641,000 - $654,000	1, 2, 3
2007 Fixed Rate Note		6.8		7.9		6.00	%		6.00	%	$237,000 - $242,000	1, 2, 3
Long-Term Revolving Note		—		—		6.00	%		6.00	%		1, 2, 3, 4

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Notes

1 - The scheduled maturity date is April 2012. The Company plans to refinance this debt and is currently negotiating the refinance terms with its senior lender. The Company's senior lender has indicated they do not foresee any problems in refinancing this debt and the Company anticipates to receive a commitment letter with refinance terms from its senior lender in the second quarter of the Company's 2012 fiscal year.

2 - Range of estimated quarterly principal payments is based on principal balances and interest rates as of September 30, 2011 .

3 - Interest rate based on 4.0% over three-month LIBOR with a 6% minimum, reset quarterly.

4 - Funds withheld from the plant's design builder (approx $4,100,000) which were previously set aside in a money market account were applied to the Long-Term Revolving Note in March 2010 pursuant to the terms of the 7th Amendment to our loan agreement with Bank. Accordingly, those funds may ultimately be paid to the design builder depending upon the terms of any resolution of the dispute.

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.

Subordinated Debt

As part of our construction loan agreement, we entered into three separate subordinated debt agreements totaling $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 8% at September 30, 2011 and December 31, 2010). Per the terms of the Mediated Settlement Agreement (the Agreement) the Company entered into in November 2010 with two parties holding subordinated debt agreements with the Company, interest on $4,000,000 of the subordinated debt continues to accrue subsequent to the date of the Agreement but is only due and payable if we fail to pass the Qualified Emissions Test as defined in the Agreement. The Company anticipates the Qualified Emissions Testing period to take place in the current fiscal year. Interest on the remaining $1,525,000 of subordinated debt is due and payable on a quarterly basis with a principal maturity date of April 16, 2012. The balance outstanding on all subordinated debt was $5,525,000 as of September 30, 2011 and December 31, 2010.

Letters of Credit

We issued two letters of credit in 2009 in conjunction with the issuance of certain grain warehouse and distilled spirits bonds. The letters of credit were issued in the amount of $500,000 and $250,000, respectively. The letters of credit are subject to a 2.0% quarterly commitment fee. The letters of credit remain outstanding at September 30, 2011 .

Restrictive Covenants

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;


•	Maintaining adequate insurance;


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


•	Limiting our ability to make distributions to members.


•	Maintain a threshold of capital expenditures

As of September 30, 2011 we are in compliance with our loan covenants.

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Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of September 30, 2011:



Contractual Obligations:	Total		Less than 1 Yr		1-3 Years		3-5 Years		More than 5 Yrs
Long-term debt obligations *	$	32,701,380	$	32,701,380	$	—	$	—	$	—
Corn Purchases **	11,846,684		11,846,684		—		—		—
Construction payable ***	4,091,170		4,091,170		—		—		—
Water purchases	2,336,800		406,400		812,800		812,800		304,800
Contractual obligations	1,325,000		1,325,000		—		—		—
Operating lease obligations	934,684		557,259		347,720		29,705		—
Coal purchases	377,550		377,550		—		—		—
Capital leases	289,076		201,094		87,982		—		—
Management Agreement	53,774		53,774		—		—		—
Total	$	53,956,118	$	51,560,311	$	1,248,502	$	842,505	$	304,800

* - We used the rates fixed in the interest rate swap agreements (see “Interest Rate Swap Agreements” in Note 5 to our audited financial statements) for the Fixed Rate Note and December 2007 Fixed Rate Note, respectively which should account for possible net cash settlements on the interest rate swaps.

** - Amounts determined assuming prices, including freight costs, at which corn had been contracted for cash corn contracts and current market prices as of September 30, 2011 for basis contracts that had not yet been fixed.

*** - Includes approximately $3.9 million that is subject to the terms of a Mediated Settlement Agreement (the Agreement) entered into in November 2010 between the Company and the plant's Design Builder. The terms of the Agreement become enforceable upon the Company's ability to pass a Required Emissions Test as defined in the Agreement.

Industry Support

North Dakota Grant

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. We received $275,000 from this grant during 2006 with this amount currently shown in the long-term liability section of our Balance Sheet as Contracts Payable. Because we have not met the minimum lignite usage requirements specified in the grant for any year in which the plant has operated, we expect to have to repay the grant and are awaiting instructions from the Industrial Commission as to the terms of the repayment schedule. This repayment could begin at some point in 2011, but as of September 30, 2011 we have not received any instructions from the Industrial Commission.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the impact of market fluctuations associated with interest rates and commodity prices as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in U.S. Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. We use cash, futures and option contracts to hedge changes to the commodity prices of corn and 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 Generally Accepted Accounting Principles (“GAAP”).

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.

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

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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 are not designated as hedges for accounting purposes, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged. We 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. The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter and year to year due to the timing of the change in value of derivative instruments relative to the cost of the commodity being hedged. 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.

As of September 30, 2011 we had approximately 1,725,000 bushels of corn under fixed price contracts. Some of these contracts were priced above current market prices so an accrual for a loss on firm purchase commitments of $444,000 was recorded.

It is the current position of our ethanol marketing company, RPMG, 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.

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

Interest Rate Risk

We are exposed to market risk from changes in interest rates from holding revolving lines of credit and subordinated debt which bear variable interest rates. The interest rate on our senior debt has effectively been set at a fixed rate with the use of underlying interest rate swap agreements. As of September 30, 2011 , we did not have any amounts drawn on our revolving lines of credit that exposes us to interest rate risk. Our subordinated debt bears variable interest rates and we had $5,525,000 outstanding in variable rate subordinated debt as of September 30, 2011 . We anticipate that a hypothetical 1% change in the interest rate on our subordinated debt, from the rate in effect on September 30, 2011 , would cause an adverse change to our income in the amount of approximately $44,200.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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 September 30, 2011 and December 31, 2010, and the related statements of operations, changes in members' equity, and cash flows for the nine months ended September 30, 2011 and each twelve-month period ended December 31, 2010 and 2009. 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 September 30, 2011 and December 31, 2010, and the results of their operations and their cash flows for the nine months ended September 30, 2011 and each twelve-month period ended December 31, 2010 and 2009 in conformity with U.S. generally accepted accounting principles.

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

Minneapolis, Minnesota

December 13, 2011

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RED TRAIL ENERGY, LLC

Balance Sheets



ASSETS	September 30, 2011		December 31, 2010

Current Assets
Cash and equivalents	$	4,672,997	$	9,803,566
Restricted cash	—		1,328,359
Accounts receivable, primarily related party	6,304,409		4,498,101
Other receivables	1,520,697		134,199
Commodities derivative instruments, at fair value	—		49,262
Inventory	11,659,863		6,396,524
Prepaid expenses	160,105		82,489
Total current assets	24,318,071		22,292,500

Property, Plant and Equipment
Land	351,280		351,280
Land improvements	3,984,703		3,984,703
Buildings	5,317,814		5,317,283
Plant and equipment	80,731,194		79,671,534
Construction in progress	649,325		441,897
	91,034,316		89,766,697
Less accumulated depreciation	27,670,319		23,222,053
Net property, plant and equipment	63,363,997		66,544,644

Other Assets
Investment in RPMG	605,000		605,000
Patronage equity	725,660		442,809
Deposits	185,150		40,000
Total other assets	1,515,810		1,087,809

Total Assets	$	89,197,878	$	89,924,953

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

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RED TRAIL ENERGY, LLC

Balance Sheets



LIABILITIES AND MEMBERS' EQUITY	September 30, 2011		December 31, 2010

Current Liabilities
Accounts payable	$	7,225,527	$	8,026,184
Accrued expenses	2,710,116		2,318,741
Commodities derivative instruments, at fair value	21,062		—
Accrued loss on firm purchase commitments	444,000		—
Current maturities of long-term debt	30,831,502		8,924,747
Current portion of interest rate swaps, at fair value	827,887		1,181,483
Total current liabilities	42,060,094		20,451,155

Long-Term Liabilities
Notes payable	86,353		25,770,222
Long-term portion of interest rate swaps, at fair value	—		524,440
Contracts payable	275,000		275,000
Total long-term liabilities	361,353		26,569,662

Commitments and Contingencies	—		—

Members’ Equity	46,776,431		42,904,136

Total Liabilities and Members’ Equity	$	89,197,878	$	89,924,953

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

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RED TRAIL ENERGY, LLC

Statements of Operations



	Nine Month			Twelve-Month			Twelve-Month
	Transition Period Ended			Period Ended			Period Ended
	September 30, 2011			December 31, 2010			December 31, 2009
Revenues, primarily related party	$	112,290,222		$	109,895,184		$	93,836,661

Cost of Goods Sold
Cost of goods sold	107,243,084			95,946,218			86,217,369
Lower of cost or market inventory adjustment	450,000			—			1,464,500
Loss on firm purchase commitments	444,000			—			169,000
Total Cost of Goods Sold	108,137,084			95,946,218			87,850,869

Gross Profit	4,153,138			13,948,966			5,985,792

General and Administrative Expenses	1,972,679			3,116,212			2,812,891

Operating Income	2,180,459			10,832,754			3,172,901

Other Income (Expense)
Interest income	43,259			37,297			470,055
Other income	3,225,574			1,358,731			706,620
Interest expense	(1,596,997		)	(3,200,010		)	(3,988,916		)
Total other income (expense), net	1,671,836			(1,803,982		)	(2,812,241		)

Net Income	$	3,852,295		$	9,028,772		$	360,660

Weighted Average Units Outstanding - Basic	40,193,973			40,193,973			40,191,494

Weighted Average Units Outstanding - Diluted	40,213,973			40,193,973			40,191,494

Net Income Per Unit - Basic and Diluted	$	0.10		$	0.22		$	0.01

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

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RED TRAIL ENERGY, LLC

Statements of Changes in Members' Equity

Nine-Month Transition Period Ended September 30, 2011

Twelve-Month Periods December 31, 2010 and 2009



	Class A Member Units									Treasury Units
	Units (a)	Amount		Additional Paid in Capital			Accumulated Deficit/Retained Earnings			Units		Amount			Total Member Equity

Balance - January 1, 2009	40,188,973	$	37,810,408	$	106,825		$	(4,147,389	)	185,000		$	(210,839	)	$	33,559,005
Unit-based compensation	5,000	—		(50,000		)	—			(5,000	)	5,699			(44,301		)
Net Income	—	—		—			360,660			—		—			360,660

Balance - December 31, 2009	40,193,973	37,810,408		56,825			(3,786,729		)	180,000		(205,140		)	33,875,364
Net Income	—	—		—			9,028,772			—		—			9,028,772

Balance - December 31, 2010	40,193,973	37,810,408		56,825			5,242,043			180,000		(205,140		)	42,904,136
Unit-based compensation	—	—		20,000			—			—		—			20,000
Net Income	—	—		—			3,852,295			—		—			3,852,295

Balance - September 30, 2011	40,193,973	$	37,810,408	$	76,825		$	9,094,338		180,000		$	(205,140	)	$	46,776,431

(a) - Amounts shown represent member units outstanding.

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

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RED TRAIL ENERGY, LLC

Statements of Cash Flows



	Nine Month Transition Period Ended			Twelve-Month Period Ended			Twelve-Month Period Ended
	September 30, 2011			December 31, 2010			December 31, 2009
Cash Flows from Operating Activities
Net income	$	3,852,295		$	9,028,772		$	360,660
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	4,448,266			5,874,232			5,893,180
Amortization and write-off of debt issuance costs	—			—			567,385
Loss on disposal of fixed assets	—			68,446			—
Lower of cost or market inventory adjustment	450,000			—			1,464,500
Change in fair value of derivative instruments	102,825			(18,829		)	116,994
Equity-based compensation	20,000			—			(49,301		)
Noncash patronage equity income	(282,851		)	(250,602		)	(75,911		)
Unrealized loss on firm purchase commitments	444,000			—			169,000
Change in operating assets and liabilities:
Restricted cash - commodities derivatives account including settlements	578,359			888,654			31,778
Accounts receivable	(1,806,308		)	(1,996,525		)	61,920
Other receivables	(1,386,498		)	—			—
Inventory	(5,713,339		)	596,507			(6,699,739		)
Prepaid expenses	(77,616		)	113,150			4,244,174
Deposits	(145,150		)	40,000			—
Accounts payable	(800,657		)	420,882			2,053,648
Accrued expenses	412,437			(315,793		)	789,433
Cash settlements on interest rate swap	(931,599		)	(1,362,623		)	(991,463		)
Net cash provided by (used in) operating activities	(835,836		)	13,086,271			7,936,258

Cash Flows from Investing Activities
Investment in RPMG	—			—			(169,110		)
Refund of sales tax on fixed assets	—			—			763,630
Proceeds from disposal of fixed assets	—			134,845			—
Capital expenditures	(797,378		)	(1,206,585		)	(62,350		)
Net cash (used in) provided by investing activities	(797,378		)	(1,071,740		)	532,170

Cash Flows from Financing Activities
Debt repayments	(4,247,355		)	(15,425,056		)	(2,516,684		)
Proceeds from long-term debt	—			—			3,573,508
Restricted cash	750,000			—			(750,000		)
Treasury units issued	—			—			5,000
Net cash (used in) provided by financing activities	(3,497,355		)	(15,425,056		)	311,824

Net Increase (Decrease) in Cash and Equivalents	(5,130,569		)	(3,410,525		)	8,780,252
Cash and Equivalents - Beginning of Period	9,803,566			13,214,091			4,433,839
Cash and Equivalents - End of Period	$	4,672,997		$	9,803,566		$	13,214,091
Notes to Financial Statements are an integral part of this Statement.

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	Nine Month Transition Period Ended		Twelve-Month Period Ended
	September 30, 2011		December 31, 2010		December 31, 2009
Supplemental Disclosure of Cash Flow Information
Interest paid	$	1,410,604	$	2,739,854	$	3,026,980
Noncash Investing and Financing Activities
Assets acquired under capital lease	$	470,241	$	—	$	—
Capital expenditures included in accounts payable	$	53,448	$	—	$	—

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

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

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 name-plate production ethanol plant near Richardton, North Dakota (the “Plant”). 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.

Fiscal Reporting Period

Effective January 1, 2011, the Board of Governors approved a change in the Company's fiscal year of September 30 for reporting financial operations, as further discussed in Note 17.

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, patronage equity and purchase commitments; the analysis of long-lived assets impairment and other contingencies. Actual results could differ from those estimates.

Reclassifications

The presentation of certain items in the financial statements for the year ended December 31, 2010 have been changed to conform to the classifications used in 2011. The reclassifications had no effect on members' equity or net income as previously reported.

Restricted Cash

During June 2009, the Company was required to restrict cash for use as collateral on two letters of credit issued in relation to its distilled spirits and grain warehouse bonds. As of September 30, 2011 and December 31, 2010 , the total amount of restricted cash related to these bonds was $0 and $750,000, respectively. In 2011, $750,000 of restricted cash was released and $750,000 of the Company's operating line-of-credit was restricted to satisfy the collateral requirement for the letters of credit. At certain times, the Company also has restricted cash to meet its derivative hedge account requirements. The total amount of cash restricted in its hedge account at September 30, 2011 and December 31, 2010 was $0 and approximately $578,000 respectively.

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 totaling $0 and $753,175 at September 30, 2011 and December 31, 2010, respectively.

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 distiller's 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 modified distiller's grains internally.

For sales of modified distiller's 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.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

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. The Company has an allowance for doubtful accounts of approximately $30,000 and $0 at September 30, 2011 and December 31, 2010, respectively.

The Company had a receivable in the amount of approximately $1,500,000 at September 30, 2011 related to the alternative fuel tax credit which was newly issued in 2011. The amount was included in other receivables at September 30, 2011 on the Company’s balance sheet.

Inventory

Corn is the primary raw material and, along with other raw materials and supplies, is stated at the lower of cost or market on a first-in, first-out (FIFO) basis. Work in process and finished goods, which consists of ethanol and distillers grains produced, is stated at the lower of average cost or market. Spare parts inventory is valued at lower of cost or market on a FIFO basis.

Patronage Equity

Derivative Instruments

The Company enters into derivative transactions to hedge its exposure to commodity and interest rate price fluctuations. The Company is required to record these derivatives in the balance sheet 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 within the statements of operations. Changes in the fair value of undesignated derivatives related to ethanol are recorded in revenue within the statements of operations. Changes of fair value of undesignated interest rate swaps are recorded in interest expense within the statement of operations.

Additionally the Company is required 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. Certain corn, ethanol and distiller's grain contracts that meet the requirement of normal purchases or sales are documented as normal and exempted from the accounting and reporting requirements, and therefore, are not marked to market in our financial statements.

Firm Purchase Commitments

The Company typically enters into fixed price contracts to purchase corn to ensure an adequate supply of corn to operate its plant. The Company will generally seek to use exchange traded futures, options or swaps as an offsetting economic hedge position. The Company closely monitors the number of bushels hedged using this strategy to avoid an unacceptable level of margin exposure. Contract prices are analyzed by management at each period end and, if necessary, valued at the lower of cost or market in the balance sheets.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

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

Depreciation is computed using the straight-line method over the following estimated useful lives:



Land improvements	15-20 years
Buildings	10-40 years
Plant and equipment	3-20 years

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.

Fair Value of Financial Instruments

The Company has adopted guidance for accounting for fair value measurements of financial assets and financial liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the financial statements on a recurring basis. The Company has adopted guidance for fair value measurement related to nonfinancial items that are recognized and disclosed at fair value in the financial statements on a nonrecurring basis. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to measurements involving significant unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

· Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

· Level 3 inputs are unobservable inputs for the asset or liability.

The level in the fair value hierarchy within which a fair measurement in its entirety falls is based on the lowest level input that is significant to the fair value measurement in its entirety.

Except for those assets and liabilities which are required by authoritative accounting guidance to be recorded at fair value in our balance sheets, the Company has elected not to record any other assets or liabilities at fair value. No events occurred during the

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

nine-month period ended September 30, 2011 and the year ended December 31, 2010 that required adjustment to the recognized balances of assets or liabilities, which are recorded at fair value on a nonrecurring basis.

The fair value of the Company's cash and equivalents, accounts receivable, accounts payable, and derivative instruments approximate their carrying value. The Company evaluated the fair value of its long-term debt and derivatives at September 30, 2011 and December 31, 2010 which is disclosed in Note 6. Except for those assets and liabilities which are required by authoritative accounting guidance to be recorded at fair value in our balance sheets, the Company has elected not to record any other assets or liabilities at fair value. No events occurred during the period ended September 30, 2011 that would require adjustment to the recognized balances of assets or liabilities, which are recorded at fair value on a nonrecurring basis.

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.

The Company has evaluated whether they have any significant tax uncertainties that would require recognition or disclosure. Primarily due to its partnership tax status, the Company does not have any significant tax uncertainties that would require recognition or disclosure.

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 2011, 2010 and 2009, the Company had 20,000, 0 and 0 member unit equivalents, respectively.

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. The Company recorded a liability of $47,000 as of December 31, 2010. During fiscal 2011, this liability was settled and paid off. Currently, the Company is not aware of any environmental liabilities identified as of September 30, 2011.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

2. CONCENTRATIONS

Coal

Coal is an important input to our manufacturing process. During the fiscal year ended September 30, 2011, we used approximately 63,000 tons of coal. We have entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through December 2011 and the Company does not anticipate any problems negotiating a renewal of this contract. The Company's intentions are to renew this supply agreement with its current coal supplier. We believe there is sufficient supply of coal from the PRB coal regions in Wyoming and Montana to meet our demand for PRB coal. In addition to coal, we could use natural gas as a fuel source if our coal supply is significantly interrupted. Because we are already operating on coal, we do not expect to need natural gas unless coal interruptions impact our operations.

Sales

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. Amounts due from RPMG represent approximately 80% and 74% of the Company's outstanding trade receivables balance at September 30, 2011 and December 31, 2010, respectively. Approximately 84%, 84%, and 83% of revenues are comprised of sales to RPMG for the nine months ended September 30, 2011 and the years ended December 31, 2010 and 2009, respectively.

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 (consistently approximately 13% of our total revenues), 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.

3. DERIVATIVE INSTRUMENTS

Commodity Contracts

As part of its hedging strategy, the Company may enter into ethanol and corn commodity-based derivatives in order to protect cash flows from fluctuations caused by volatility in commodity prices in order to protect gross profit margins from potentially adverse effects of market and price volatility on ethanol sales and corn purchase commitments where the prices are set at a future date. These derivatives are not designated as effective hedges for accounting purposes. For derivative instruments that are not accounted for as hedges, or for the ineffective portions of qualifying hedges, the change in fair value is recorded through earnings in the period of change. Ethanol derivative fair market value gains or losses are included in the results of operations and are classified as revenue and corn derivative changes in fair market value are included in cost of goods sold.

The following table presents notional amounts and derivative contracts outstanding:



As of:	September 30, 2011						December 31, 2010
Contract Type	# of Contracts	Notional Amount (Qty)		Fair Value			# of Contracts	Notional Amount (Qty)		Fair Value
Corn futures	10	50,000	bushels	$	(21,062	)	237	1,185,000	bushels	$	49,262
Total fair value				$	(21,062	)				$	49,262
Amounts are recorded separately on the balance sheet - negative numbers represent liabilities

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

Interest Rate Contracts

The Company had approximately $25.1 million and $27.7 million of notional amount outstanding in interest rate swap agreements, as of September 30, 2011 and December 31, 2010, respectively, that exchange variable interest rates (three-month LIBOR) for fixed interest rates over the terms of the agreements. At September 30, 2011 and December 31, 2010, the fair value of the interest rate swaps totaled approximately $0.8 million and $1.7 million, respectively, and are recorded as a liability on the balance sheets. These agreements are not designated as effective hedges for accounting purposes and the change in fair market value and associated net settlements are recorded in interest expense. The swaps mature in April 2012.

The following tables provide details regarding the Company's derivative financial instruments at September 30, 2011 and December 31, 2010:



Derivatives not designated as hedging instruments:

Balance Sheet - as of September 30, 2011	Asset		Liability
Commodity derivative instruments, at fair value	$	—	$	21,062
Interest rate swaps, at fair value	—		827,887
Total derivatives not designated as hedging instruments for accounting purposes	$	—	$	848,949

Balance Sheet - as of December 31, 2010	Asset		Liability
Commodity derivative instruments, at fair value	$	49,262	$	—
Interest rate swaps, at fair value	—		1,705,923
Total derivatives not designated as hedging instruments for accounting purposes	$	49,262	$	1,705,923



Statement of Operations Income/(expense)	Location of gain (loss) in fair value recognized in income	Amount of gain (loss) recognized in income during the nine months ended September 30, 2011			Amount of gain (loss) recognized in income during the year ended December 31, 2010			Amount of gain (loss) recognized in income during the year ended December 31, 2009
Corn derivative instruments	Cost of Goods Sold	$	(1,086,381	)	$	(1,826,268	)	$	(474,643	)
Ethanol derivative instruments	Revenue	—			1,830,306			(1,561,940		)
Interest rate swaps	Interest Expense	(53,562		)	(707,859		)	(490,619		)
Total		$	(1,139,943	)	$	(703,821	)	$	(2,527,202	)

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

4. INVENTORY

Inventory is valued at lower of cost or market. Inventory values as of September 30, 2011 and December 31, 2010 were as follows:



As of	September 30, 2011		December 31, 2010
Raw materials, including corn, chemicals and supplies	$	7,843,358	$	3,531,671
Work in process	1,276,576		907,967
Finished goods, including ethanol and distillers grains	1,480,899		1,180,857
Spare parts	1,059,030		776,029
Total inventory	$	11,659,863	$	6,396,524

Lower of cost or market adjustments for the nine months ended September 30, 2011 and the year ended December 31, 2010 and 2009 were as follows:



	For the nine months ended September 30, 2011		For the year ended December 31, 2010		For the year ended December 31, 2009
Loss on firm purchase commitments	$	444,000	$	—	$	169,000
Loss on lower of cost or market adjustment for inventory on hand	450,000		—		1,464,500
Total loss on lower of cost or market adjustments	$	894,000	$	—	$	1,633,500

The Company has entered into fixed forward corn purchase contracts under which it is required to take delivery at the contract price. At the time the contracts were created, the price of the contract price approximated market price. Subsequent changes in market conditions could cause the contract prices to become higher or lower than market prices. As of September 30, 2011, the average price of corn purchased under certain fixed price contracts, that had not yet been delivered, was higher than market price. Based on this information, the Company accrued an estimated loss on firm purchase commitments of $444,000 for the nine months ended September 30, 2011. The loss is 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 lower of cost or market impairment valuation with respect to inventory. Given the uncertainty of future ethanol prices, this loss may or may not be recovered, and further losses on the outstanding purchase commitments could be recorded in future periods.

The Company recorded inventory valuation impairments of $450,000 for the nine months ended September 30, 2011 and $0 and $1,464,500 for the years ended December 31, 2010 and 2009, respectively. The impairments, as applicable, were attributable primarily to decreases in market prices of corn and ethanol. The inventory valuation impairment was recorded in “Lower of cost or market inventory adjustment” on the statement of operations.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

5. BANK FINANCING



As of	September 30, 2011		December 31, 2010
Notes payable under loan agreement to bank	$	25,116,771	$	29,160,099
Subordinated notes payable	5,525,000		5,525,000
Capital lease obligations (Note 6)	276,084		9,870
Total Long-Term Debt	30,917,855		34,694,969
Less amounts due within one year	30,831,502		8,924,747
Total Long-Term Debt Less Amounts Due Within One Year	$	86,353	$	25,770,222

Market value of interest rate swaps	$	827,887	$	1,705,923
Less amounts due within one year	827,887		1,181,483
Total Interest Rate Swaps Less Amounts Due Within One Year	$	—	$	524,440



Scheduled maturities for the twelve months ending September 30
	Interest rate swaps		Long-term debt		Totals

2012	$	827,887	$	30,831,502	$	31,659,389
2013	—		84,189		84,189
2014	—		2,164		2,164
Total	$	827,887	$	30,917,855	$	31,745,742

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; 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.

As of September 30, 2011, the Company was in compliance with all of its debt covenants.

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, which is included in the total under notes payable under loan agreement to bank above. 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. Fair value adjustments and net settlements are recorded in interest expense within the statement of operations.



Interest Expense	For the nine months ended September 30, 2011			For the year ended December 31, 2010			For the year ended December 31, 2009
Interest expense on long-term debt	$	1,543,435		$	2,492,149		$	3,498,297
Change in fair value of interest rate swaps	(878,037		)	(654,762		)	(500,844		)
Net settlements on interest rate swaps	931,599			1,362,623			991,463
Total interest expense	$	1,596,997		$	3,200,010		$	3,988,916

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

Construction Loan

The Company has three long-term notes (collectively the “Term Notes”) in place as of September 30, 2011 and December 31, 2010. Three of the notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007. Each note has specific interest rates and terms as described below. Based on the terms of the security agreement, the debt is secured by substantially all of the assets of the Company.



	Outstanding Balance (Millions)		Interest Rate		Range of Estimated Quarterly Principal Payment Amounts
Term Note	September 31, 2011	December 31, 2010	September 31, 2011	December 31, 2010	Range of Estimated Quarterly Principal Payment Amounts	Notes
Fixed Rate Note	$18.30	$21.30	6.00%	6.00%	$641,000 - $654,000	1, 2, 3
2007 Fixed Rate Note	6.80	7.90	6.00%	6.00%	$237,000 - $242,000	1, 2, 3
Long-Term Revolving Note	0.00	0.00	6.00%	6.00%	—	1, 2, 3, 4

Notes

1 - The scheduled maturity date is April 2012.

2 - Range of estimated quarterly principal payments is based on principal balances and interest rates as of September 30, 2011.

3 - Interest rate based on 4.0% over three-month LIBOR with a 6% minimum, reset quarterly.

4 - Upon execution of the 7th Amendment to the construction loan agreement in March 2010, amount available to borrow on this revolving note is reduced until available amount equals $4.1m. As of September 30, 2011, amount available was $4.1m, all of which is restricted.

Revolving Line of Credit

The Company has a $7,000,000 line of credit agreement with its bank subject to certain borrowing base limitations with a maturity date of April 16, 2012. $750,000 of this line of credit is restricted. Outstanding borrowings on the line-of-credit accrue interest at the greater of the three-month LIBOR plus 400 basis points or 5%. The Company has no outstanding borrowings on this line of credit at September 30, 2011 or December 31, 2010.

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.

Letters of Credit

During 2009, the Company was issued $750,000 in letters of credit from the Bank in conjunction with the issuance of two bonds required for operations. There is no expiration date on the letters of credit and the Company does not anticipate the Bank having to advance any funds under these letters of credit. The letters of credit are subject to a 2.0% quarterly commitment fee.

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 which totaled 8.0% at September 30, 2011 and December 31, 2010. Per the terms of the Mediated Settlement Agreement (the Agreement) (Note 10) interest on $4,000,000 of the subordinated debt continues to accrue subsequent to the November 8, 2010 date of the Agreement but is only due and payable if the Company fails to pass the Qualified Emissions Test as defined in the Agreement. Interest on the remaining $1,525,000 of subordinated debt is due and payable on a quarterly basis with a principal maturity date of April 16, 2012. The balance outstanding on all subordinated debt was $5,525,000 as of September 30, 2011 and December 31, 2010, respectively.

6. FAIR VALUE MEASUREMENTS

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010, respectively.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010



					Fair Value Measurement Using
	Carrying Amount as of September 30, 2011		Fair Value as of September 30, 2011		Level 1		Level 2		Level 3
Liabilities
Commodities derivative instruments	$	21,062	$	21,062	$	21,062	$	—	$	—
Interest rate swaps	827,887		827,887		—		827,887		—
Total	$	848,949	$	848,949	$	21,062	$	827,887	$	—

					Fair Value Measurement Using
	Carrying Amount as of December 31, 2010		Fair Value as of December 31, 2010		Level 1		Level 2		Level 3
Assets
Commodities derivative instruments	$	49,262	$	49,262	$	49,262	$	—	$	—
Liabilities
Interest rate swaps	$	1,705,923	$	1,705,923	$	—	$	1,705,923	$	—

The fair value of the 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 discounted cash flow analysis on the expected cash flows of each instrument. The analysis of the interest rate swaps reflect 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.

Financial Instruments Not Measured at Fair Value

The estimated fair value of the Company's long-term debt, including the short-term portion, at September 30, 2011 and December 31, 2010 approximated the carrying value of approximately $30.9 and $34.7 million, respectively. Fair value was estimated using estimated variable market interest rates as of September 30, 2011. The fair values and carrying values consider the terms of the related debt and exclude the impacts of debt discounts and derivative/hedging activity.

7. LEASES

The Company leases equipment under operating and capital leases through June 2015. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under operating lease includes a locomotive and rail cars. Rent expense for operating leases was approximately $445,000 for the nine months ended September 30, 2011 and $546,000 and $506,000 for the years ended December 31, 2010 and 2009, respectively. Equipment under capital leases consists of office equipment and plant equipment.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

Equipment under capital leases is as follows at:



As of	September 30, 2011			December 31, 2010
Equipment	$	483,217		$	12,976
Less accumulated amortization	(5,839		)	(3,893		)
Net equipment under capital lease	$	477,378		$	9,083

At September 30, 2011, the Company had the following minimum commitments, which at inception had non-cancelable terms of more than one year. Amounts shown below are for the 12 months period ending September 30:



	Operating Leases		Capital Leases
2012	$	557,259	$	201,094
2013	243,260		85,746
2014	104,460		2,236
2015	29,705		—
Thereafter	—		—
Total minimum lease commitments	$	934,684	289,076
Less amount representing interest			(12,992		)
Present value of minimum lease commitments included in liabilities on the balance sheet			$	276,084

8. 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. As of September 30, 2011 and December 31, 2010 there were 40,193,973 units issued and outstanding. The Company also held a total of 180,000 treasury units as of September 30, 2011 and December 31, 2010.

In July 2011, the Company entered into an equity grant agreement with its Chief Financial Officer for the grant of 100,000 units. The units will be issued on a five year vesting schedule with the first units awarded on October 1, 2011. Compensation expense related to this award will be recognized over the period of service. Compensation expense of $20,000 relating to this equity grant agreement was recorded for the nine month period ended September 30, 2011. The compensation expense was determined using the fair value of the underlying units at the grant date.

Total units authorized are 40,373,973 as of September 30, 2011 and December 31, 2010.

9. GRANTS

In 2006, the Company entered into a contract with the State of North Dakota through the Industrial Commission for a lignite coal grant not to exceed $350,000. The Company received $275,000 from this grant during 2006 with this amount currently shown in the liability section of the Company's Balance Sheet as Contracts Payable. Because the Company has not met the minimum lignite usage requirements specified in the grant for any year in which the plant has operated, it expects to have to repay the grant and is awaiting instructions from the Industrial Commission as to the terms of the repayment schedule. This repayment could begin in fiscal 2012.

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

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

$270,000 over ten years. The Company received and earned approximately $29,000 and $36,000 for the nine month period ended September 30, 2011 and the year ended December 31, 2010, respectively.

10. COMMITMENTS AND CONTINGENCIES

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 September 30, 2011, the Company had various fixed price contracts for the purchase of approximately 1,725,000 bushels of corn. Using the stated contract price for the fixed price contracts, the Company had commitments of approximately $11.8 million related to the 1,725,000 bushels under contract.

Construction in progress

The Company had construction in progress of approximately $649,000 at September 30, 2011 relating to two capital projects: One being improvements to the plant's water filtration system and the other being replacement of the plant's bin sweeps. The Company anticipates that both of these projects will be completed during the first quarter of fiscal year 2012 for a total combined cost of approximately $750,000.

Design Build Contract

11. DEFINED BENEFIT CONTRIBUTION PLAN

The Company established a 401k retirement plan for its employees effective January 1, 2011. The Company matches employee contributions to the plan up to 4% of employee's gross income. The Company contributed approximately $56,000 to the 401k plan for the nine month period ended September 30, 2011.

Prior to January 1, 2011, the Company matched employee contributions up to 3% of employee's gross income to a simple IRA retirement plan. The Company contributed approximately $57,000 and $48,000 to the IRA plan for the years ended December 31, 2010 and 2009, respectively.

12. 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 distillers grains and sale of ethanol. The related parties include Unit holders, members of the board of governors of the Company, and RPMG, Inc. (“RPMG”). Significant related party activity affecting the financial statements are as follows:

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010



			September 30, 2011		December 31, 2010
Balance Sheet
Accounts receivable			$	5,392,559	$	3,821,873
Accounts payable			757,460		725,184

	For the nine months ended September 30, 2011		For the year ended December 31, 2010		For the year ended December 31, 2009
Statement of Operations
Revenues	$	96,730,967	$	92,533,888	$	82,162,189
Cost of goods sold	2,057,245		3,317,920		2,854,692
General and administrative	60,804		114,614		470,906

Inventory Purchases	$	7,984,774	$	6,112,139	$	6,996,695

13. INCOME TAXES

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



	September 30, 2011 (estimate)			December 31, 2010

Financial Statement Basis of Assets	$	89,197,878		$	89,924,953
Organization and start-up costs	3,692,743			4,087,843
Allowance for doubtful accounts	30,109			—
Inventory and compensation	50,000			30,225
Net book value of property, plant and equipment	(35,155,455		)	(34,299,928		)
Book to tax derivative difference	—			49,262
Income Tax Basis of Assets	$	57,815,275		$	59,792,355

Financial Statement Basis of Liabilities	$	42,421,447		$	46,976,008
Interest rate swap	(827,887		)	(1,705,923		)
Purchase commitments	(444,000		)	—
Book to tax derivative difference	(21,063		)	—
Income Tax Basis of Liabilities	$	41,128,497		$	45,270,085

14. SUBSEQUENT EVENTS

In October 2011, the Company entered into an agreement to purchase a corn oil extraction system with plans for the system to be installed and operational during the 2012 fiscal year. The total cost of this system is expected to be approximately $2.4 million dollars.

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

15. UNCERTAINTIES IMPACTING THE ETHANOL INDUSTRY AND OUR FUTURE OPERATIONS

The Company has certain risks and uncertainties that it experiences during volatile market conditions, which can have a severe impact on operations. The Company's revenues are derived from the sale and distribution of ethanol and distillers grains to customers primarily located in the U.S. Corn for the production process is supplied to the plant primarily from local agricultural producers and from purchases on the open market. The Company's operating and financial performance is largely driven by prices at which the Company sells ethanol and distillers grains and by the cost at which it is able to purchase corn for operations. The price of ethanol is influenced by factors such as prices of supply and demand, weather, government policies and programs, and unleaded gasoline and the petroleum markets, although since 2005 the prices of ethanol and gasoline began a divergence with ethanol selling for less than gasoline at the wholesale level. Excess ethanol supply in the market, in particular, puts downward pressure on the price of ethanol. The Company's largest cost of production is corn. The cost of corn is generally impacted by factors such as supply and demand, weather, government policies and programs. The Company's risk management program is used to protect against the price volatility of these commodities.

The Company anticipates that the results of operations into fiscal 2012 will continue to be affected by volatility in the commodity markets. The volatility is due to various factors, including uncertainty with respect to the availability and supply of corn, increased demand for grain from global and national markets, speculation in the commodity markets, and demand for corn from the ethanol industry.

16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarter results are as follows:



Nine-Month Transition Period Ended September 30, 2011	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	31,953,093		$	35,142,332		$	45,194,797	N/A
Gross profit	998,644			277,220			2,877,274		N/A
Operating income (loss)	321,889			(340,688		)	2,199,258		N/A
Net income (loss)	(149,257		)	213,875			3,787,677		N/A
Net income per unit-basic and diluted	—			0.01			0.09		N/A

Year ended December 31, 2010	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	28,886,891		$	22,518,058		$	27,737,274	$	30,752,961
Gross profit	3,707,899			579,134			4,774,362		4,887,571
Operating income (loss)	3,067,744			(7,038		)	3,976,025		3,796,023
Net income (loss)	2,984,492			(773,587		)	3,534,146		3,283,721
Net income (loss) per unit-basic and diluted	0.07			(0.02		)	0.08		0.08

Year ended December 31, 2009	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	20,895,613		$	23,632,831		$	25,247,196	$	24,061,021
Gross profit	(6,964		)	(394,550		)	3,120,074		3,267,232
Operating income (loss)	(787,973		)	(1,095,887		)	2,361,585		2,695,176
Net income (loss)	(2,050,974		)	(1,259,653		)	1,829,319		1,841,968
Net income (loss) per unit-basic and diluted	(0.05		)	(0.03		)	0.05		0.05

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

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RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD ENDED SEPTEMBER 30, 2011

AND THE YEAR ENDED DECEMBER 31, 2010

17. CHANGE IN FISCAL REPORTING PERIOD

Effective January 1, 2011, the Board of Governors approved a change in our fiscal year and changed the fiscal year end to September 30 for reporting financial operations. As a result of this change, our audited statements of operations, changes in members equity and cash flows presented herein include the two previous years ended December 31, 2010 and 2009, and the nine-month transition period ended September 30, 2011.

The below table provides a comparative of the 2011, 2010, and 2009 nine-month period ended for comparative purposes.



	Transition Period Ended September 30, 2011				Nine Month Period Ended September 30, 2010 (unaudited)					Nine Month Period Ended September 30, 2009(unaudited)
Statement of Operations Data	Amount		%		Amount			%		Amount			%
Revenues	$	112,290,222	100.00	%	$	79,142,223		100.00	%	$	69,775,640		100.00	%
Cost of Goods Sold	108,137,084		96.30		70,080,830			88.55		67,057,080			96.10
Gross Profit	4,153,138		3.70		9,061,393			11.45		2,718,560			3.90
General and Administrative Expenses	1,972,679		1.76		2,024,673			2.56		2,240,835			3.21
Operating Income	2,180,459		1.94		7,036,720			8.89		477,725			0.68
Other Income (Expense)	1,671,836		1.49		(1,291,670		)	(1.63	)	(1,959,033		)	(2.81	)
Net Income (Loss)	$	3,852,295	3.43	%	$	5,745,050		7.26	%	$	(1,481,308	)	(2.12	)%

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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 Rules 13a-15(e) and 15d - 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 September 30, 2011, have concluded that our disclosure controls and procedures are effective in ensuring that material information required to be disclosed is included in the reports that we file with the SEC.

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 September 30, 2011, 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.

Management's Transition Report on Internal Control Over Financial Reporting .

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting purposes.

Management conducted an evaluation of the effectiveness of the Company's internal control over financial reporting based on the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management's assessment included evaluation of elements such as the design and operating effectiveness of key financial reporting controls, process documentation, accounting policies, and overall control environment.

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Based on this evaluation, management has concluded that the Company's internal control over financial reporting was effective as of September 30, 2011.

This transition report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. As we are a non-accelerated filer, management's report is not subject to attestation by our registered public accounting firm pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 that permits us to provide only management's report in this transition report.

ITEM 9B. OTHER INFORMATION

In July 2011 the Company entered into an equity grant agreement with its Chief Financial Officer for the grant of 100,000 units. The units will be issued based on a five year vesting schedule with the first units awarded on October 1, 2011. Compensation expense related to this award will be recognized over the period of service related to the units. Compensation expense of approximately $20,000 was incurred for the transition period ended September 30, 2011 .

PART III

ITEM 10. GOVERNOR, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference in the definitive proxy statement from our 2012 Annual Meeting of Members to be filed with the Securities and Exchange Commission within 120 days of our 2011 fiscal year end. This proxy statement is referred to in this report as the 2012 Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION.

The Information required by this Item is incorporated by reference to the 2012 Proxy Statement.

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

The Information required by this Item is incorporated by reference to the 2012 Proxy Statement.

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

The Information required by this Item is incorporated by reference to the 2012 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The Information required by this Item is incorporated by reference to the 2012 Proxy Statement.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Exhibits Filed as Part of this Report and Exhibits Incorporated by Reference.

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


(1)	Financial Statements

The financial statements appear beginning at page 30 of this report.


(2)	Financial Statement Schedules

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


(3)	Exhibits

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Exhibit No.	Exhibit	Filed Herewith	Incorporated by Reference
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.
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.

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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.
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.

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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.
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.
10.47	Amended and Restated Member Control Agreement of Red Trail Energy, LLC.	Filed as exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on June 1, 2009 (000-52033) and incorporated by reference herein.

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10.48	Sixth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha effective date April 16, 2009.		Filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 2, 2009 (000-52033) and incorporated by reference herein.
10.49	Coal Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal Sales Company dated November 5, 2009.		Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (000-52033) and incorporated by reference herein.
10.50	Amended and Restated Management Agreement made and entered into as of September 10, 2009 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC.		Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (000-52033) and incorporated by reference herein.
10.51	Seventh Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated March 1, 2010.		Filed as Exhibit 10.51 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (000-52033) and incorporated by reference herein.
10.52	Employment Agreement between Red Trail Energy, LLC and Gerald Bachmeier dated July 8, 2010.		Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (000-52033) and incorporated by reference herein.
10.53	Mediated Settlement Agreement between Red Trail Energy, LLC, Fagen, Inc. and Fagen Engineering, LLC, and ICM, Inc. dated November 8, 2010. +		Filed as Exhibit 99.1 to our Current Report on Form 8-K filed with the SEC on December 20, 2010 (000-52033) and incorporated by reference herein.
10.54	Eight Amendment to Construction Loan Agreement between First National Bank of Omaha and Red Trail Energy, LLC dated November 15, 2010.		Filed as Exhibit 10.54 to our Current Report on Form 10-K for the fiscal year ended December 31, 2010 (000-52033) and incorporated by reference herein.
10.55	Revolving Promissory Note between First National Bank of Omaha and Red Trail Energy, LLC dated November 15, 2010.		Filed as Exhibit 10.55 to our Current Report on Form 10-K for the fiscal year ended December 31, 2010 (000-52033) and incorporated by reference herein.
10.56	Letter Agreement between Greenway Consulting, LLC and Red Trail Energy, LLC dated January 13, 2011.		Filed as Exhibit 10.56 to our Current Report on Form 10-K for the fiscal year ended December 31, 2010 (000-52033) and incorporated by reference herein.
10.57	Ninth Amendment to Construction Loan Agreement dated June 1, 2011 by and between Red Trail Energy, LLC and First National Bank of Omaha.		Filed as Exhibit 99.1 to our Current Report on Form 8-K dated June 1, 2011 (000-52033) and incorporated by reference herein.
10.58	First Amended and Restated Revolving Promissory Note dated June 1, 2011 by and between Red Trail Energy, LLC and First National Bank of Omaha.		Filed as Exhibit 99.2 to our Current Report on Form 8-K dated June 1, 2011 (000-52033) and incorporated by reference herein.
10.59	Equity Grant Agreement between Kent Anderson and Red Trail Energy, LLC dated July 1, 2011.		Filed as Exhibit 10.1 to our Current Report on Form 10-Q for the quarter ended June 30, 2011 (000-52033) and incorporated by reference herein.
10.60	Corn Oil Separation System Agreement between Solution Recovery Services, LLC and Red Trail Energy, LLC dated October 6, 2011. +	X
31.1	Certificate Pursuant to 17 CFR 240.13a-14(a)	X
31.2	Certificate Pursuant to 17 CFR 240.13a-14(a)	X
32.1	Certificate Pursuant to 18 U.S.C. Section 1350	X
32.2	Certificate Pursuant to 18 U.S.C. Section 1350	X

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101	The following financial information from Red Trail Energy, LLC's Annual Report on Form 10-K for the transition period ended September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Balance Sheets as of September 30, 2011 and December 31, 2010, (ii) Statements of Operations for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010 and 2009, (iii) Statement of Changes in Members' Equity; (iv) Statements of Cash Flows for the transition period ended September 30, 2011 and fiscal year ended December 31, 2010 and 2009, and (v) the Notes to Financial Statements.**

(+) Confidential Treatment Requested.

(X) Filed herewith.

(**) Furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		RED TRAIL ENERGY, LLC

Date:	December 13, 2011	/s/ Gerald Bachmeier
		Gerald Bachmeier
		President and Chief Executive Officer
		(Principal Executive Officer)

Date:	December 13, 2011	/s/ Kent Anderson
		Kent Anderson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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



Date:	December 13, 2011	/s/ Gerald Bachmeier
		Gerald Bachmeier, Chief Executive Officer and President
		(Principal Executive Officer)

Date:	December 13, 2011	/s/ Kent Anderson
		Kent Anderson, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

Date:	December 13, 2011	/s/ Mike Appert
		Mike Appert, Chairman and Governor

Date:	December 13, 2011	/s/ Tim Meuchel
		Tim Meuchel, Vice Chairman and Governor

Date:	December 13, 2011	/s/ Ambrose Hoff
		Ambrose Hoff, Secretary and Governor

Date:	December 13, 2011	/s/ Ron Aberle
		Ron Aberle, Governor

Date:	December 13, 2011	/s/ Frank Kirschenheiter
		Frank Kirschenheiter, Governor

Date:	December 13, 2011	/s/ Sid Mauch
		Sid Mauch, Governor

Date:	December 13, 2011	/s/ William A. Price
		William A. Price, Governor

Confidential Treatment Requested. Confidential portions of this document have been redacted and have been separately filed with the Commission.

SRS Contract - Corn Oil Separation System Agreement

THIS CORN OIL SEPARATION SYSTEM AGREEMENT ("COSS Agreement") is entered into this 6th day of October , 2011 (the "Effective Date"), by and between Solution Recovery Services, LLC, a Michigan limited liability company (hereinafter "SRS"), whose principal place of business is located at 7455 Newman Blvd., Dexter, Michigan, USA, and Red Trail Energy LLC , a North Dakota limited liability company (hereinafter "Customer"), whose principal place of business is located at 3682 HWY 8 S, Richardton, ND 58652, USA. SRS and Customer are sometimes referred to individually as a "party" and collectively as the "parties".

Introductory Statements


A.	SRS has developed purification and separation technologies for application as a single source solution for recovery of corn oil as a by-product of ethanol production (the "Corn Oil Product"), together with installation and supporting maintenance and service programs.

Following initial lab samples taken from Customer's business premises, 3682 HWY 8 S, Richardton, ND 58652, USA (the "Customer Premises"), Customer desires to purchase a Corn Oil Separation System and related equipment, as more particularly described in Exhibit A attached hereto (collectively, the "COSS Equipment") from SRS, for the purchase price and upon the terms and conditions hereinafter set forth (the "Equipment Purchase Agreement").


C.	The Equipment Purchase Agreement, together with all other terms, conditions, covenants and obligations of the parties set forth in this COSS Agreement and in the attached and incorporated Exhibits, collectively form this "Agreement".

Agreement

FOR AND IN CONSIDERATION of the above Introductory Statements, which the parties acknowledge to be true and accurate, and the mutual promises, covenants and agreements contained herein, SRS and Customer agree as follows:


1.0	EXHIBITS & TERM

1.1 The following Exhibits are incorporated into and form a part of this Agreement:

Exhibit A COSS Equipment: Design, Installation & Training

Exhibit B Technology Service Program

Exhibit C Site & Customer Requirements; Excluded Items

Exhibit D Performance Test and Deliverables

Exhibit E Scope Of SRS Services

1.2 This Agreement shall be binding and enforceable from the Effective Date and shall continue in full force and effect for an initial period of *** (the "Initial Term") from the date that Corn Oil Product of sufficient marketable quality and quantity, is extracted using the COSS Equipment (the "Commencement Date").

1.3 Following the Initial Term, this Agreement shall be automatically renewed annually on each successive anniversary of the Commencement Date for a further ***, unless otherwise terminated in accordance with the provisions hereof.

1.4 Any reference in this Agreement to measurements of quantity, quality or temperature, to prevailing industry standards, definitions or descriptions, or to currency shall have the meaning ordinarily ascribed to such term or thing in the United States of America.

*** Confidential material redacted and filed separately with the Commission.

2.0 EQUIPMENT PURCHASE AGREEMENT

2.1 SRS agrees to sell and deliver the COSS Equipment, inclusive of related design, engineering, electrical hardware, separation modules and start up training to Customer all for which Customer agrees to pay the sum of *** (the "Purchase Price"). SRS also agrees to supply the equipment and services based on a Not To Exceed (NTE) purchase price basis and further agrees to scope change modification deducts as appropriate reflecting process design and deliverable modifications that reduce the cost of the project. See Exhibit A for a full listing of equipment and deliverables on which the NTE price is based. The purchase price is to be paid through a series of progress payments as defined below:


1.	Payment Schedule:


a.	An initial payment of *** is due on the Effective Date.


i.	***


b.	Second scheduled payment in the sum of *** is due immediately upon receipt of the COSS Equipment at the Customer Premises.


c.	A final bill of sale will be issued by SRS upon payment in full for the COSS Equipment.

2. Performance Runoff:

a. All payments are subject to a *** holdback (the “Performance Holdback”) payable upon successful completion and approval of the performance test and deliverables checklist by SRS and Customer. The performance test criteria and process is included within Exhibit D. Proper retention by Customer of the Performance Holdback, provided all other required payments under this Agreement are made, shall constitute "payment in full."

2.2 SRS shall retain all right, title and interest in and to the COSS Equipment installed in accordance with this Agreement until payment by Customer for designated equipment is received by SRS, at which time SRS shall deliver a bill of sale to Customer in accordance with section 2.1. In the event Customer has not paid for any COSS Equipment located at Customer's premises, and Customer has failed to pay for such equipment within thirty (30) days following receipt of written notice of default by SRS, SRS shall have the right to enter upon the Customer Premises to remove the COSS Equipment which has not been paid for by Customer.

2.3 Upon receipt of payment in full of the allocated Purchase Price for designated COSS Equipment, SRS shall deliver a final bill of sale to Customer and release the designated COSS Equipment from any applicable security interest.

2.4 Upon receipt of the signed contract from Customer, SRS agrees to commence construction of the COSS Equipment and Customer acknowledges and agrees that the delivery of the COSS Equipment by SRS, subject to delays beyond the control of SRS, is projected to be complete within ***.

2.5 Customer acknowledges that Customer shall be responsible under this Agreement for the Customer Requirements set forth in Exhibit C attached hereto and SRS agrees that all specifications that are required in connection with the installation of the COSS Equipment shall be delivered to Customer in advance and shall be subject to the review and approval by Customer or Customer's engineering consultants. Customer agrees that the Customer Requirements set forth in Exhibit C, subject to delays beyond the control of Customer, is projected to be complete within *** from the Effective Date.

2.6 Upon completion of the installation of the COSS Equipment at the Customer Premises, SRS shall provide training to Customer's designated employees regarding the operation of the COSS Equipment and extraction of the Corn Oil Product.

*** Confidential material redacted and filed separately with the Commission.

2.7 All amounts payable to SRS under this Section 2.0 will be in the form of immediately available funds to an account specified by SRS.

3.0 DELIVERY

3.1 SRS is responsible for all costs related to shipping the COSS Equipment to the Customer. The Equipment is sold F.O.B. Customer Premises.

3.2 SRS agrees to make every effort to deliver the COSS Equipment to the Customer Premises within *** days of execution of the Agreement.

3.3 Customer agrees that it shall be solely responsible for all site and installation preparations assigned to Customer under this Agreement, in accordance with Exhibit C. Customer is responsible for installation of the Equipment.

4.0 LIMITED WARRANTY

4.1 SRS hereby warrants the Equipment to be new, of good quality and free from defects in materials and/or workmanship under normal use and service, with such warranty beginning upon execution of this Agreement and continuing for a period of one (1) year following the Commencement Date (the “Warranty Period”). Should any defect in materials and/or workmanship appear during the Warranty Period, SRS shall, upon notification, correct such defects in material and/or workmanship either by repairing or replacing any defective equipment or components, including all other costs related to the repair and/or replacement, including freight, travel costs and reasonable living expenses, if any, incurred by SRS to perform the warranty work.

4.2 SRS shall not be responsible for any expenses incurred for service or repairs performed by any persons other than SRS authorized service representatives unless such other persons are otherwise expressly authorized by SRS; provided, that this limitation shall not apply to the installation of the equipment by Customer, pursuant to Section 3.3 above, following successful completion and approval of the performance test and deliverables checklist by SRS and Customer. SRS shall not be responsible for replacement or repair of parts or components that are missing or damaged due to service or repairs performed by persons other than SRS authorized service representatives.

4.3 This warranty does not apply to any damage or loss to any component and/or equipment caused by alteration by unauthorized persons, fire, accident, artificially generated electric current, acts of God, misuse or abuse, or any other cause whatsoever other than defects in workmanship and/or materials.

4.4 This warranty shall be null and void if the Equipment is abused, operated beyond rated capacities or not operated and maintained in strict accordance with all manuals and instructions.

4.5 The following are expressly excluded from this warranty and are not covered by any other warranty given by SRS, express or implied:

4.5.1 Pump mechanical seals, impellers, diaphragms and check seals;

4.5.2 Bowl seal kits;

4.5.3 Clutch pads;

4.5.4 Electrical Breakers;


4.5.5	Centrifuge bowl gaskets, bowl valve gaskets, inlet-outlet flow unit gaskets for unions, intermediate and regulating disks;


4.5.6	Vacuum and pressure relief valves whose settings have been altered without express authorization from SRS; and


4.5.7	Any equipment manufactured by a third party and covered under the standard manufacturer's warranty.

4.6 All replacement parts hereunder are themselves warranted until the end of the warranty period set forth in Section 4.1 hereof.

4.7 This warranty is non transferable and shall become null and void upon the sale or other disposition of any part of the Equipment to any other party other than Customer, provided that this exception shall not apply in the event of the sale of all or substantially all the ethanol plant assets by Red Trail Energy LLC, or other acquisition transaction involving Red Trail Energy LLC membership interests.

5.0 INDEPENDENT CONTRACTOR

5.1 It is understood that SRS and Customer are independent contractors and neither entity is an employee, agent, partner, or joint venturer of the other party.

5.2 SRS agrees that its employees and/or its agents and subcontractors will follow the existing safety procedures, rules and guidelines of the Customer ethanol facility.

5.3 Neither Customer nor SRS shall have any authority to bind or transact any business or to incur any obligations or liabilities on behalf of the other, or represent to anyone that it has a right to do so.

5.4 Except as may be required by law, there shall be no withholdings, including without limitation of any federal, state or local taxes, from the payments due SRS hereunder and SRS and Customer acknowledge and agree each shall be solely responsible for payment of its own workers' compensation, payroll and other taxes with respect to the subject matter of this Agreement.

5.5 SRS and Customer represent and warrant to the other that their respective shareholders, officers, directors, managers, members, employees, contractors and agents are not nor shall be entitled to claim nor receive any personal benefits whatsoever from the other.

5.6 SRS and Customer represent and warrant to one another that each shall comply with all applicable federal, state and local laws and regulations, including any and all laws regarding the payment of taxes, duties or other charges levied on account of their respective businesses.

6.0 TERMINATION

6.1 Either Party shall have the right to terminate this Agreement at any time “for cause” in the event of a material breach of the terms of this Agreement by the other, including SRS's representations and warranties hereunder, and the failure of the breaching Party to cure or remedy such material breach within thirty (30) days after receipt of a notice of such default. Cause for termination shall include, but not be limited to:


6.1.1	The failure of a party to make any payment due hereunder within thirty (30) days of its due date, and such nonpayment is not cured within thirty (30) days after receipt of a notice of default.


6.1.2	The denial by Customer to SRS to enter upon the Customer Premises or access to the COSS Equipment as provided herein, and such default is not cured within fifteen (15) days after receipt of a notice of default by SRS to Customer.


6.1.3	The failure of SRS or Customer to comply with any obligation hereunder, and such default is not cured

within fifteen (15) days after receipt of a notice of default by the non-defaulting party to the other party, describing with particularity the nature of the default.


6.1.4	The other party shall become insolvent, file for bankruptcy or have an involuntary bankruptcy filed against such party, or such party shall generally fail to pay, or shall admit in writing its inability to pay, debts as they become due, with such termination being effective upon receipt of notice of such default.

6.2 This Agreement shall continue in full force and effect until the earlier of (1) termination of this Agreement in accordance with the provisions hereof, or (2) by mutual written agreement of the parties; provided that, the termination or expiration of this Agreement will not affect any accrued obligation of a party not performed by such party prior to the date of such termination or expiration and such obligation, including all representations and warranties set forth in this Agreement, will survive the termination or expiration hereof. Following payment in full for the COSS Equipment, this Agreement may be terminated by either party hereto at the end of the Initial Term or any renewal term by delivery of written notice of such termination to the other party not less than sixty (60) days prior to the expiration of the Initial Term or the applicable renewal term. If Customer has paid in full for the Equipment at the time of termination, Customer shall continue to have full ownership of and title to the COSS Equipment.

6.3 All representations and warranties and indemnification obligations of SRS and Customer in this Agreement shall survive the termination or expiration of this Agreement.

7.0 EQUIPMENT PERFORMANCE TEST

7.1 Following completion of the installation of the COSS Equipment at the Customer facility, SRS shall have fifteen (15) days or such additional time as may be reasonably required to conduct a performance evaluation of the COSS Equipment to determine the quality and anticipated annual quantity of recoverable Corn Oil Product (the “Performance Test”) and to deliver the results of the evaluation (the “Performance Results”) for review and approval by Customer. The detailed protocol is included within this Agreement as Exhibit D.

7.2 In the event that the Performance Test criteria detailed in Exhibit D are not achieved, SRS shall, at its option, have up to thirty (30) days, or such additional time as may be reasonably required, to undertake appropriate modifications to the COSS Equipment and conduct further performance evaluations, the results of which (the “Revised Results”) shall be delivered for review and approval by Customer. The initial fifteen (15) day performance evaluation period, together with the SRS cure period if required, are collectively referred to as the “Test Period”.

7.3 If, following the Test Period, the operational parameters of the Performance Test are not met as stated in Exhibit D, the Performance Holdback will be retained by Customer as the sole and exclusive remedy for failure to meet the Performance Test criteria.

8.0 COMPLIANCE WITH LAWS

8.1 Each party shall be solely responsible for compliance with all applicable laws pertaining to the activities contemplated by this Agreement, within their respective jurisdictions; provided that, each party agrees to take all reasonable steps necessary and to use its best efforts to cooperate with the other to comply with all such laws as are applicable to the transactions contemplated hereby.

9.0 INTELLECTUAL PROPERTY & MARKS

9.1 Except to the extent permitted by this Agreement, or as required pursuant to Court order or applicable law, neither Customer nor SRS, for any reason or at any time, shall disclose to any person, corporation, partnership, joint venture or other entity or individual confidential information relating to the COSS Equipment or processes, products, apparatus, intellectual property or trade secrets of the other, whether such confidential information is provided verbally or in writing. Upon the request of SRS, Customer agrees to obtain non-disclosure covenants from employees,

*** Confidential material redacted and filed separately with the Commission.

agents and contractors involved in the performance of this Agreement or the installation, operation or maintenance of the COSS Equipment with terms substantially similar to those contained herein.

9.2 Neither Customer nor SRS shall acquire any right whatsoever under this Agreement to any goodwill, patent, trademark, copyright or other intellectual property rights of the other party. Should any such rights become vested by operation of law or otherwise in a party during the term of this Agreement or afterwards, such party hereby assigns any and all such rights to the other, without cost or other consideration; provided that nothing contained herein shall require a party to assign any goodwill, patent, trademark, copyright or other trade secret relating exclusively to products or material now or hereafter owned thereby unrelated to the subject matter of this Agreement.

9.4 SRS represents and warrants to Customer that it has valid and exclusive title and ownership in and to all of the COSS Equipment sold to Customer pursuant to this Agreement.

9.5 SRS further represents and warrants to Customer that, to its knowledge and as of the Effective Date: (i) it is the owner or authorized user of any intellectual property rights embodied or represented in the COSS Equipment; (ii) it has full right, power and authority to sell the COSS Equipment to Customer, free and clear of liens, security interests and encumbrances, and (iii)***

10.0 INDEMNITIES

10.1 SRS shall not be liable to Customer, or to Customer's agents, employees, contractors, customers or invitees (other than SRS or its employees or agents) or to any other person whomsoever for any injury or damage to person or property, or for any loss of production or profit, or any environmental contamination resulting from, caused by or arising out of any negligent act or omission of Customer, its agents, contractors, employees or invitees (other than SRS or its employees or agents) or any other person entering upon the Customer Premises for any reason. Customer shall defend, with counsel acceptable to SRS, indemnify, and hold harmless SRS and its representatives and agents from and against all claims, demands, liabilities, causes of action, suits, judgments, damages, and expenses (including reasonable attorneys' fees) arising from (1) any injury to or death of any person or the damage to or theft, destruction, loss, or loss of use of any property or inconvenience (collectively, a “Loss”) arising from any occurrence on the Customer Premises caused by Customer, its agents, employees, contractors, customers or invitees (other than SRS or its employees or agents) or (2) a Loss of any kind resulting from or arising out of any breach of this Agreement by Customer.

10.2 Customer shall not be liable to SRS, or to the agents, employees, contractors, customers or invitees of SRS (other than Customer or its employees or agents) or to any other person whomsoever for any injury or damage to person or property, or for any loss of production or profit, or any environmental contamination resulting from, caused by or arising out of any negligent act or omission of SRS, its agents, contractors, employees or invitees (other than Customer or its employees or agents). SRS shall defend, with counsel acceptable to Customer, indemnify, and hold harmless Customer and its representatives and agents from and against all claims, demands, liabilities, causes of action, suits, judgments, damages, and expenses (including reasonable attorneys' fees) arising from (1) any Loss arising from any occurrence on the Customer Premises caused by SRS, its agents, employees, contractors, customers or invitees (other than Customer or its employees or agents) or (2) a Loss of any kind resulting from or arising out of any breach of this Agreement by SRS.

10.3 Other than as a claim by GS (for which Customer shall be solely responsible, as defined in Section 10.4), SRS shall defend (through counsel of its selection and at its expense) and, as set forth herein, indemnify and hold harmless Customer and its representatives and agents from and against claims, demands, liabilities, causes of action, suits, judgments, damages and expenses arising out of any allegation of infringement of any of the claimant's patents related to Customer ownership or use of the COSS Equipment or production of Corn Oil Product pursuant to this Agreement. If the COSS Equipment is claimed to be infringing, or SRS believes that it is likely to infringe, then SRS may, at its sole option and in full satisfaction of its obligations under this Section, either: (i) procure for Customer the right to continue using the equipment; or (ii) replace or modify the equipment such that it is non-infringing but maintains substantially the same functionality. If SRS defends infringement allegations which result in a final

*** Confidential material redacted and filed separately with the Commission.

judgment of liability or settles such allegations, including under subsection (i) above, Customer agrees that it, and not SRS, shall be responsible for any royalty based damages or settlement related to corn oil production revenue and that SRS shall be responsible for any lost profit or analogous damages or settlement attributable directly to the purchase of the COSS Equipment. Customer agrees that, irrespective of any request for injunctive relief or injunction order, that at no time shall Customer be entitled to any refund of the amounts paid to SRS under this Agreement or to any other types of damages. Customer, may, at its own expense, retain counsel of its selection in addition to counsel appointed by SRS in any action in which SRS is providing a defense under this Section. SRS is empowered to negotiate and settle under this provision, subject only to Customer's approval which shall not unreasonably be withheld.

10.4 ***

10.5 In no event shall either party be liable to the other party in connection with this Agreement, regardless of the form of action or theory of recovery, for any: (a) indirect, special, exemplary, consequential, incidental or punitive damages, even if that party has been advised of the possibility of such damages; (b) lost profits, lost revenues, lost business expectancy, business interruption losses and/or benefit of the bargain damages; and/or (c) direct damages in an amount in excess of the amounts actually received in payment by SRS under this Agreement. Notwithstanding the foregoing, the limitations set forth in this Section shall not apply to (i) either party's breach of its confidentiality obligations under this Agreement; and/or (ii) either party's infringement, misappropriation or violation of the other party's intellectual property rights. Any claim arising out of this Agreement must be initiated within three (3) years of the date the party knew, or reasonably should have known, of the existence of such claim against the other party. The indemnities of this Section are not intended to indemnify any party or its representatives and agents against the consequences of their own negligence or fault.

10.6 In order to receive the indemnification in this Section, the party seeking the indemnification must promptly notify the other party of the assertion of the claim; allow the other party to retain sole and exclusive control over the defense and/or settlement of the claim; and cooperate with the other party, at the other party's expense, in the defense and/or settlement of the claim.

11.0 NON-SOLICITATION

11.1 Neither SRS nor Customer shall employ or attempt to employ directly or indirectly any person employed by the other during the existence and for a period one year after the termination of this Agreement, nor induce or influence, or attempt to do so, any person who is engaged as an employee, agent, independent contractor, or representative, or otherwise by SRS or Customer to terminate his or her relationship therewith or to engage or otherwise participate in any business or activity which is competitive with the business conducted by SRS or Customer.

12.0 GOVERNING LAW

12.1 This Agreement, and any disputes that arise hereunder, are governed by the laws of the State of North Dakota, without regard to conflicts of laws principles and any controversy or claim arising out of or related to this Agreement, or the breach thereof, shall be settled by arbitration administered by the American Arbitration Association in North Dakota, under its Commercial Arbitration Rules, and judgment on the award rendered by the arbitrator(s) may be entered in any court having jurisdiction therein.

13.0 MISCELLANEOUS

13.1 The parties agree that that terms of this Agreement, including without limitation, all price and performance terms are confidential and constitute "confidential information" not to be disclosed by either party. For purposes of this Agreement, the term "confidential information" includes any business, financial, sales, pricing or technical information or data and like materials furnished by a party regarding, without limitation, the COSS Equipment and the processes employed in connection therewith. Confidential information shall not include any information which is in the public domain, otherwise than through action which constitutes a default of such party's confidentiality obligations under this Agreement.

13.2 The parties hereto shall not assign or transfer any rights or obligations under this Agreement without the prior written consent of the other, not to be unreasonably withheld, conditioned or delayed, provided that that this provision shall not apply in the event of the sale of all or substantially all the ethanol plant assets by Red Trail Energy LLC, or other acquisition transaction involving Red Trail Energy LLC membership interests.

13.3 This Agreement shall be binding on and insure to the benefit of the parties and their respective successors and assigns.

13.4 No failure or delay by any party to this Agreement in exercising any right, power or privilege under this Agreement shall operate as a waiver thereof, and no single or partial exercise thereof shall preclude any other or further exercise thereof or the exercise of any other right, power or privilege. No waiver of any terms, provision or condition of this Agreement shall be deemed to be or construed as a further or continuous waiver of such term, provision or condition. Time shall be of the essence of this Agreement.

13.5 The unenforceability or invalidity of any section, subsection or provision of this Agreement shall not affect the enforceability or validity of the rest of this Agreement.

13.6 Any notices shall be deemed given when personally delivered, telexed, faxed, or sent certified mail, return receipt requested, to the address of the parties first above written, or to the party at its last known address or fax number.

13.7 This Agreement and attached Exhibits constitute the entire Agreement between the parties and supersede all prior agreements, proposals, understandings and arrangements by or between the parties or any affiliated individuals or entities. This Agreement may only be amended or modified by a writing signed by the parties hereto.

13.8 This Agreement may be executed and delivered by the Parties hereto by facsimile and in counterpart, each of which shall be deemed to be an original, but all of which shall constitute one and the same instrument. A facsimile copy of this Agreement executed by both parties, including in counterpart, shall be deemed to be an original.

13.9 The parties hereto both acknowledge that they have reviewed this Agreement with their own independent counsel prior to entering into this Agreement.

13.10 Each party represents and warrants to the other that it has the full authority, power and right to execute, deliver and perform its obligations under this Agreement and that the individual signing on its behalf is authorized to do so pursuant to the requirements of its organizational and governing documents.

[Signatures appear on next page following.]

IN WITNESS WHEREOF, the parties hereto have authorized the individuals whose signatures appear below to sign this Agreement with full authority to bind the parties hereto.



		CUSTOMER : Red Trail Energy LLC, a North Dakota limited liability company
	By:	/s/ Gerald Bachmeier
	Name: Its:	Gerald Bachmeier C.E.O. I have the authority to bind the corporation.
	By:	SRS : SOLUTION RECOVERY SERVICES, LLC a Michigan limited liability company
	By:	/s/ Philip Schoof
	Name: Its:	Philip Schoof SR. V.P., General Manager I have the authority to bind the company.

Exhibit A

COSS Equipment: Design, Installation and Training

1.0 TECHNOLOGY DELIVERABLES

SRS will provide the components of the proprietary COSS system to the Red Trail Energy LLC, Richardton, North Dakota facility. The deliverables relating to providing the COSS system are detailed in the following sections:

1.1 Process Design and Engineering Drawings

Two sets of the following documentation will be provided in English along with all measurements and dimensions in English units unless otherwise stated. Any items not expressly mentioned below are not included in this offer.


•	Piping and Instrument Diagrams - including instrument control loops, pipe diameter and material, insulation and steam tracing locations, and utility connection locations.


•	Equipment Arrangement Drawings (layout) - for the main equipment in the delivery indicating approximate static loads for all items weighing more than 100 kg.


•	Specifications for Equipment and Instrumentation for purchase by SRS as shown on the P&ID.


•	Operating Instructions including process recommendations.


•	Maintenance Manuals for delivered equipment with technical descriptions; and instructions for start up, operation, maintenance and repair.


•	Major Equipment, Instrumentation and Electrical Horsepower Lists.


•	Electrical Drawings.


•	Two (2) sets of blueprints and one (1) electronic original (Adobe PDF) of all final drawings.

Preliminary Drawings and Material Lists will be submitted for approval by Purchaser. Purchaser will have five (5) working days to propose changes and the drawings will then be issued for fabrication and material ordering. Costs for changes requested by the Purchaser, whether involving proposed or additional materials, equipment or engineering, shall be reimbursed by the Purchaser to SRS.

1.2 Included COSS Components

The following are the primary components for the COSS System:


•	PCOSS Module:


◦	Automated Inlet Brush Screen: This unit will enhance the separation process and efficiency and protect the down stream components. This unit is stainless construction.


◦	Automated Inlet Control System: This system integrates with the evaporator system to provide a controlled inlet to the COSS system.


◦	Instrumentation including necessary level/pressure switches, flow indicator, solenoid valves, sight glasses and pressure/temperature indicators as required for good operational control.


◦	Primary Centrifugal Separator: SE 602 ESX centrifugal separator.


◦	Integrated CIP System: Automated valves and pumping systems to accommodate clean in place with caustic and or water.


◦	Pillar Mounted Jib Crane to remove bowl


•	Intermediate Process Tanks:


◦	Series of two (2) 900 gallon stainless steel cone bottom insulated tanks with fixed internal weirs, one fitted with a rotating bottom sweep.


◦	Automated decantation system including actuated valving and pump system to periodically remove heavy phase.


•	Feed and Syrup Return System:


◦	Valves and controls to enable pressurized feed and controlled syrup return.


◦	Actuated valves, piping, and controls to accommodate bypassing of COSS units and return of the fluid to the main process stream.


◦	Feed pump assembly.


◦	Return pump package assembly.


◦	Feed pump control panel.


•	Centralized Process Control system:


◦	Control panel with Allen-Bradley PLC and PC based touch screen control interface.


◦	Ethernet connectivity for remote monitoring and controls.


◦	Electrical equipment including motor starters, breakers, racks, lighting fixtures, conduit, and wiring.


•	Oil Storage and Load-out Systems:


◦	Two (2) 13,000 gallon, cone bottom atmospheric storage tanks, level sensors and controls.


◦	Oil Storage Pump, centrifugal type, complete with motors, couplings and base plates.


◦	Tank Truck Load Package complete with control panel and safety shut off device.


◦	Additional touch screen interface to be located at load out platform


•	Additional Items:


◦	None

1.3 General Specifications

Additional general specifications are detailed within the following bulleted list of items:


•	All materials will be designed for use in non-hazardous areas per the National Electric Code.


•	Skids will be built to ASME B31.3 standards, but none of the items will be code stamped.


•	Electric Motors - all motors are of totally enclosed design for alternating current of normal voltage and frequency. All motors 1/2 H.P. and greater are 460V 3-Phase/60 Hz.


•	Materials not explicitly specified are generally either high grade carbon steel or cast iron. Stainless steel is of quality AISI 304 and acid resistant steel of quality AISI 316 or equivalent.


•	Not Included in Delivery: The delivery includes only the items clearly identified in this quotation.


•	Battery limits are defined as the connection point for mentioned items supplied or specified by SRS. All items outside the PCOSS Module and Process Tank Skid battery limits will be assembled by Customer.

1.4 COSS System Installation Project Management and Assistance


•	Collaboration with Customer engineering staff to design the site improvements.


•	Routine site construction assistance and consultation.

2.0 SYSTEM STARTUP, COMMISSIONING AND TRAINING

SRS will provide, for a minimum of three (3) working days, coverage by SRS Engineering and Technical Services personnel specialized in the COSS equipment for the supervision of the start-up of the COSS.

The training program offered will include not only the maintenance and operation of the system but a detailed explanation of corn oil separation by means of weight separation. The training will include, at a minimum, the four primary areas defined below and will require up to three days of both classroom and hands on instruction.


•	Principles of Weight Separation and Corn Oil Separation


◦	Stillage / Corn Oil separation and purification of crude corn oil


◦	Weight separation and theory of operation


◦	Optimization and maximum yield


•	Primary Centrifuge and Weight Separation Overview


◦	System design


◦	Disassembly and assembly


◦	Drive mechanism


◦	High speed disc configuration and bowl design


◦	Purging mechanisms


◦	Bowl repair and adjustments


•	The Entire Module and Controls Overview


◦	Control panel components


◦	Touch screen interface, timers and sensing devices


◦	Controlling the purge


◦	Controlling separation


•	Preventative Maintenance and Repair Overview


◦	Centrifuge bowl inspection


◦	Cleaning components correctly


◦	Drive mechanism - belt and gear


◦	Purge diagnostics


◦	Module controls and diagnostics


◦	Ordering spare parts

*** Confidential material redacted and filed separately with the Commission.

Exhibit B

Technology Service Program (TSP)

Customer shall have until the date the second scheduled payment is due to elect to participate in the TSP. If so elected on or before such time, Customer will pay to SRS, for the duration of the Agreement, a TSP fee (Silver Service Package) equal to *** per pound of crude corn oil shipped or otherwise utilized as compensation for technology and services provided pursuant to scope of services detailed within Exhibit E.

*** Confidential material redacted and filed separately with the Commission.

Exhibit C

Site & Customer Requirements; Excluded Items

All equipment, engineering, services, drawings, etc., not specifically detailed in this contract will be provided by others.

1.0 Materials AND SUPPLIES not Included


•	Process materials, operating supplies such as feedstock, reagents, and chemicals.


•	Utilities such as condensate, caustic, process water, instrument air and electrical power in quantities, pressures and temperatures as stated in the project drawings.

2.0 SERVICES NOT INCLUDED


•	Offloading, installation, and rigging of all equipment and skid assemblies.


•	Termination of all Electrical and Mechanical at Battery Limits.


•	Piping, instrumentation, and power between various skids and control panels.


•	Soils test or investigation.


•	Environmental impact report or other required regulatory approvals/reviews/permits.


•	Construction, electrical or building permits and inspections.


•	Demolition drawings.


•	Review of any drawings supplied by other engineering companies.


•	Installation bills of material.


•	Operation of the COSS system on a day-to-day basis.

3.0 MANAGEMENT OF THE SITE IMPROVEMENTS NOT INCLUDED

Site improvements are to be coordinated and carried out by Customer or Customer's general contractor. SRS will provide engineering consultation for the site improvements.


•	Mechanical


◦	Piping, valves, pumps, heat tracing, insulation and instrumentation for stillage transfer.


◦	Piping, valves, pumps, heat tracing, insulation and instrumentation for clean oil storage.


◦	Clean oil transfer line.


◦	Utility supplies to the COSS modules (condensate, CIP, process water, instrument air).


◦	Piping connections between the prefabricated PCOSS and Tank skids.


•	Electrical


◦	Controls and power wiring on stillage transfer system ***.


◦	Controls and power wiring on tank farm ***.


◦	Supply power ***.


◦	Power and control wiring ***.


•	Structural


◦	Containment for Tanker Truck Loading and Storage Tanks.


◦	Foundations for Storage Tanks and Loading Platforms.


◦	Prefab unit or building ***.


◦	Obtaining all required building permits, as well as obtaining inspections and approvals of all state and local regulatory agencies having jurisdiction.


◦	***.

4.0 UTILITY REQUIREMENTS - PROVIDED BY CUSTOMER

***

All required process variables above shall be as measured at COSS battery limits.

*** Confidential material redacted and filed separately with the Commission.

EXHIBIT D

Process Performance Test and Deliverables

SRS and Customer will conduct a Process Performance Test following installation of the Equipment.

1.0 TEST PROTOCOL

The COSS system will be tested for up to a three (3) day duration to evaluate the separation and operational performance.


1.	Testing will commence immediately or as soon as practical upon completion of installation.


2.	The COSS system will be started up and operated by SRS personnel for the entire testing duration.


3.	The individual systems will be evaluated and monitored including validation of proper operation of the following components:


a.	***


b.	***


c.	***


d.	***


4.	The Performance Test Criteria are as specifically detailed as follows:



Extraction Performance Test Criteria	Objective	Performance
***
***	***
***	***
***	***

2.0 FEEDSTOCK PROFILE


1.	The Test Criteria were set based on a typical plant of your size and general location. The feedstock profile is as follows:



Feedstock Profile Item	Parameter
***	***
***	***
***	***
***	***
***	***
***	***


2.	In the event the plant is not operating as per the feedstock profile, Customer has the option to adjust plant to the agreed upon profile to perform the Performance Runoff or to waive the Performance Runoff and pay the Performance Holdback.


3.

3.0 DELIVERABLES CHECK LIST

SRS and Customer will review the equipment components and operation to validate the COSS system components have been delivered, installed and are operational. The following table represents the checklist of deliverables:

*** Confidential material redacted and filed separately with the Commission.



Operational Integrity and Deliverables Checklist	Operates or serves as designed, delivered or completed/performed
Process Design and Engineering Drawings
Final as build drawings
Piping and Instrument Diagrams
Operating Instructions, Manuals
Training and start-up assistance
3 day start-up assistance
Class room and hands on 3 day training
***
***
***
***
***
***
***
***
***
***
***
***
***
***
***
***
***
***
***

*** Confidential material redacted and filed separately with the Commission.

Exhibit E

Scope of SRS Technology Services

The SRS Technology Service Program is designed to augment the daily operational, maintenance and repair duties of the customer wherein the customer has primary responsibility to operate, maintain and repair the equipment and process. The SRS program supplies specialized technology parts, repair assistance and oversight.

SRS will provide routine technical and operational support a minimum of *** per week to include the following categorical supporting components:


•	Repair and maintenance


•	Sample collection and evaluation


•	Preventative maintenance


•	Key component cleaning and inspection


•	Equipment calibration


•	Process optimization

1. PARTS AND SPARES

SRS will maintain an inventory of primary and perishable service parts for the Equipment at our Dexter, Michigan facility and our Omaha, Nebraska facility. Additional spare parts will be stocked on location at the Customer's Premises and all parts and repair consumables will be provided as part of the service program with the following exceptions:


a.	The Technology Service Program does not cover any damage or loss to any component and/or equipment caused by alteration by unauthorized persons, fire, accident, artificially generated electric current, acts of God, misuse or abuse, or any other cause whatsoever other than defects in workmanship and/or materials.


b.	The Technology Service Program does not cover damage to Equipment if the Equipment is abused, operated beyond rated capacities or not operated and maintained in strict accordance with all manuals and instructions.

2. EMERGENCY RESPONSE

SRS will monitor the operation and, whenever possible, make appropriate corrective actions remotely and the SRS technical staff will consult directly with Customer's trained operations staff to remedy any operational or repair issues. If the issue cannot be resolved via the remote monitoring and telephone consultation and require resolution prior to the next scheduled routine maintenance, SRS will provide on-site emergency response within a ***.

3. DIVISION OF RESPONSIBILITIES

The SRS Technology Service Program will enhance the daily operational, maintenance and repair duties of the customer. The objective of this Division of Responsibility (DOR) is to define which party is responsible for production of an activity/deliverable. The DOR is not intended to define reviews and/or approvals. For specialized operations such as centrifuge bowl repair, SRS will work with the customer staff to conduct repair and maintenance efforts.



	RED TRAIL ENERGY LLC	SRS
ENGINEERING & DESIGN
***		X
***	X
***		X
***		X

*** Confidential material redacted and filed separately with the Commission.



***		X
***	X	X
***	X	X
***	X	X
***	X	X
***	X	X
***	X	X
***	X
***		X
***	X
***	X
***		X
***	X
***	X
***		X
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***		X
***	X
***	X
***
PROCUREMENT
***		X
***		X
***		X
***		X
***	X
***		X
***	X
***		X
***	X
***		X
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CONSTRUCTION
***	X
***		X
***	X
***	X	Support
***	X
***	X
***	X
***	X
***	X
***	X
***	X
***	X
***	X
***	X
***	X
***	X (Install)	X (Provide)

*** Confidential material redacted and filed separately with the Commission.



COMMISSIONING / START-UP
***	X
***	X	X
***	X	X
***	X	X
***	X
***		X
***		X

PROJECT MANAGEMENT
***	X	X
***	X	X
***	X
***	X	X
***	X	X
***	X
***	X	X
***	X
***	X

CERTIFICATION PURSUANT TO 17 CFR 240.15(d)-14(a)

(SECTION 302 CERTIFICATION)

I, Gerald Bachmeier, certify that:


1.	I have reviewed this transition report on Form 10-K of Red Trail Energy, LLC;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant, as of, and for, the periods presented in this report;


4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:


a)	Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	December 13, 2011	/s/ Gerald Bachmeier
		Gerald Bachmeier Chief Executive Officer

CERTIFICATION PURSUANT TO 17 CFR 240.15(d)-14(a)

(SECTION 302 CERTIFICATION)

I, Kent Anderson, certify that:


1.	I have reviewed this transition report on Form 10-K of Red Trail Energy, LLC;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant, as of, and for, the periods presented in this report;


4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:


a)	Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	December 13, 2011	/s/ Kent Anderson
		Kent Anderson Chief Financial Officer

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the transition report on Form 10-K in accordance with Rule 15(d)-14 of the Securities Exchange Act of 1934 of Red Trail Energy, LLC (the “Company”) for the nine month transition period ended September 30, 2011 filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerald Bachmeier, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:


1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



	/s/ Gerald Bachmeier
	Gerald Bachmeier
	Chief Executive Officer

	Dated: December 13, 2011

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the transition report on Form 10-K in accordance with Rule 15(d)-14 of the Securities Exchange Act of 1934 of Red Trail Energy, LLC (the “Company”) for the nine month transition period ended September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kent Anderson, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:


1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



	/s/ Kent Anderson
	Kent Anderson
	Chief Financial Officer

	Dated: December 13, 2011