RED TRAIL ENERGY, LLC - FORM 10-K

Attached files

file	filename
EX-10.56 - RED TRAIL ENERGY, LLC	v216581_ex10-56.htm
EX-32.1 - RED TRAIL ENERGY, LLC	v216581_ex32-1.htm
EX-10.55 - RED TRAIL ENERGY, LLC	v216581_ex10-55.htm
EX-31.1 - RED TRAIL ENERGY, LLC	v216581_ex31-1.htm
EX-32.2 - RED TRAIL ENERGY, LLC	v216581_ex32-2.htm
EX-10.54 - RED TRAIL ENERGY, LLC	v216581_ex10-54.htm
EX-31.2 - RED TRAIL ENERGY, LLC	v216581_ex31-2.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2010

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

Commission file number 000-1359687

RED TRAIL ENERGY, LLC

(Exact name of registrant as specified in its charter)

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

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

(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. ¨ 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. £ 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 £ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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).

£ Yes £ 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. £

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 £		Accelerated filer £
Non-accelerated filer x (Do not check if a smaller reporting company)		Smaller Reporting Company £

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

£ Yes x No

The aggregate market value of the membership units held by non-affiliates of the registrant as of June 30, 2010 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 March 31, 2011 the Company has 40,193,973 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.

INDEX

		Page No.

PART I		4

ITEM 1. BUSINESS		4
ITEM 1A. RISK FACTORS		11
ITEM 2. PROPERTIES		16
ITEM 3. LEGAL PROCEEDINGS		16
ITEM 4. (REMOVED RESERVED)		16

PART II		16

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		16
ITEM 6. SELECTED FINANCIAL DATA		18
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		19
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		31
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. GOVERNOR, 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 GOVERNOR INDEPENDENCE		53
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		53

PART IV		54

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		54

SIGNATURES		60

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:

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

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

Changes in the environmental regulations that apply to our plant operations and our ability to comply with such regulations;

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;

Our ability to generate and maintain sufficient liquidity to fund our operations, meet debt service requirements and necessary capital expenditures;

Changes in plant production capacity or technical difficulties in operating the plant;

Lack of transport, storage and blending infrastructure preventing our products from reaching high demand markets;

Our ability to continue to meet our loan covenants;

Limitations and restrictions contained in the instruments and agreements governing our indebtedness;

Results of our hedging transactions and other risk management strategies;

Changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices impacting the ethanol industry including:

national, state or local energy policy – examples include legislation already passed such as the California low-carbon fuel standard;

federal and state ethanol tax incentives;

implementation of tariffs on distillers grains exported to other countries;

legislation mandating the use of ethanol or other oxygenate additives;

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

reduction or elimination of tariffs on foreign ethanol.

Changes and advances in ethanol production technology; and

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.

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 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.

On December 3, 2010, the Company signed a Revolving Promissory Note for a $7,000,000 revolving line of credit with First National Bank of Omaha (the “Lender”) (the “Line of Credit”). The funds from the Line of Credit will be used for working capital at the Company’s ethanol plant. The maturity date on this Line of Credit is June 1, 2011 unless it is otherwise extended by the Lender and Company.

On December 14, 2010, the Company entered into a Mediated Settlement Agreement (the “Settlement Agreement”) with Fagen, Inc. and Fagen Engineering, LLC, (collectively referred to as "Fagen"), and ICM, Inc. ("ICM"). The subject of the Settlement Agreement is the negotiated resolution of operational issues related to the plant’s fluidized bed combustor/boiler. The effective date of the Settlement Agreement is November 8, 2010.

The financial terms of the Settlement Agreement will only be enforceable if the Company’s ethanol plant achieves the required emissions standard (“Required Emissions Standard”) as defined in the Settlement Agreement. The Required Emissions Standard is generally the North Dakota permit limits for emissions originating from the ethanol plant’s boiler, namely PM/PM10, VOC, SO2, NOx, CO and opacity. The Company, Fagen and ICM will cooperate to make certain plant modifications to enable the plant to meet the Required Emissions Standard and then engage in an emissions testing protocol to determine whether the Required Emissions Standard has been met. The Company anticipates the timing of the emissions testing to take place during the 2011 fiscal year.

Effective January 1, 2011, the Company’s board of governors determined to change the date of the end of its fiscal year from December 31 to September 30. The change is effective beginning January 1, 2011. For the fiscal year ended September 30, 2011, the Company will file a transition report on Form 10-K for the nine months ending September 30, 2011.

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.

Approximately 84% of our total revenue was derived from the sale of ethanol during our fiscal year ended December 31, 2010. Ethanol sales accounted for approximately 83% and 84% of our total revenue for our fiscal years ended December 31, 2009 and 2008, 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”) and 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 fiscal year ended December 31, 2010. Distillers grains sales accounted for approximately 17% and 16% of our total revenue for our fiscal years ended December 31, 2009 and 2008 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 fourth quarter of 2010, 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 in our 2011 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 8.33% 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.

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 2010, we were able to secure sufficient grain to operate the plant and do not anticipate any problems securing enough corn during 2011. 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 2010 fiscal year 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 the fiscal year ended December 31, 2010, we used approximately 98,000 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 long-term contract. This arrangement helps us to mitigate price volatility in the coal market. Our coal contract is up for renewal in December 2011. 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 2011.

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 $600,000.

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”). For our 2011 fiscal year, we anticipate using 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 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. 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. The estimated combined cost of these two projects is $1,500,000. Management believes that our current sources of working capital are sufficient to sustain our operations

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 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 March 28. 2011, the Renewable Fuels Association estimates that there are 204 ethanol production facilities in the United States with capacity to produce approximately 14.1 billion gallons of ethanol annually. The RFA also estimates that approximately 3.33% of the ethanol production capacity in the United States was not currently operating. 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.

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)

POET Biorefining		1,629.0		5.0

Archer Daniels Midland		1,450.0		275

Valero Renewable Fuels		1,130.0		—

Green Plains Renewable Energy		657.0		—

Updated: March 28, 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. This could put us at a competitive disadvantage to other ethanol producers.

In 2008, Valero Renewable Fuels, which is a subsidiary of a major gasoline refining company, purchased several ethanol plants from the VeraSun Energy bankruptcy auction. Currently, Valero Renewable Fuels owns 10 ethanol plants with capacity to produce approximately 1.1 billion gallons of ethanol annually. This makes Valero Renewable Fuels one of the largest ethanol producers in the United States. Further, since the parent company of Valero Renewable Fuels is a gasoline blender, Valero Renewable Fuels has an established customer for the ethanol it produces which may allow Valero Renewable Fuels to be more competitive in the ethanol industry than we are able. At times when ethanol demand may be lower, it is unlikely that Valero Renewable Fuels will have difficulty selling the ethanol it produces due to the fact that it is a subsidiary of a company that is required to blend a significant amount of ethanol. While Valero is currently the largest oil company which has purchased ethanol production capacity, other large oil companies may follow the lead of Valero in the future. Should other large oil companies become involved in the ethanol industry, it may be increasingly difficult for us to compete. 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 2010 was approximately 13 billion gallons, of which corn based ethanol could be used to satisfy approximately 12 billion gallons. The RFS for 2011 is approximately 14 billion gallons, of which corn based ethanol can be used to satisfy approximately 12.6 billion gallons. Current ethanol production capacity exceeds the 2011 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 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. Many in the ethanol industry believe that we will reach this blend wall in 2011, since the RFS requirement for 2011 is 14 billion gallons, much of which will come from ethanol. 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.

Recently, the United States Environmental Protection Agency allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2001 and later. Management believes that many gasoline retailers will refuse to provide E15 due to the fact that not all standard vehicles will be allowed to use E15 and due to the labeling requirements the EPA may impose. The EPA is considering instituting labeling requirements associated with E15 which may unfairly discourage consumers from purchasing E15. As a result, the approval of E15 may not significantly increase demand for ethanol. In addition to E15, the ethanol industry is pushing the use of an intermediate blend of 12% ethanol and 88% gasoline called E12. Management believes that E12 may be more beneficial to the ethanol industry than E15 because many believe that E12 could be approved for use in all standard vehicles. Management believes this will make it easier for retailers to supply E12 compared to E15, unless E15 is approved for use in all standard vehicles. Two lawsuits were filed on November 9, 2010 by representatives of the food industry and the petroleum industry challenging the EPA’s approval of E15. It is unclear what effect these lawsuits will have on the implementation of E15 in the United States retail gasoline market.

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 was recently renewed until December 31, 2011. If this tax credit is not renewed before the end of 2011, it likely would have a negative impact on the price of ethanol and demand for ethanol in the market due to reducted 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 recently 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. In the fiscal year ended December 31, 2010, we incurred costs and expenses of approximately $1,661,000 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.

In late 2009, California passed a Low Carbon Fuels Standard (LCFS). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in green house gases which is measured using a lifecycle analysis, similar to RFS2. Management believes that this lifecycle analysis is based on unsound scientific principles that unfairly harms corn based ethanol. Management believes that these new regulations will preclude corn based ethanol from being used in California. California represents a significant ethanol demand market. If we are unable to supply ethanol to California, it could significantly reduce demand for the ethanol we produce. Currently, several lawsuits have been filed challenging the California LCFS.

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 was recently extended until December 31, 2011. 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. Ethanol imported from other countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably.

Employees

As of December 31, 2010, we had 40 full-time employees. Seven of our employees are primarily involved in management and administration and the other 33 are primarily involved in Plant operations.

Financial Information about Geographic Areas

All of our operations are domiciled in the United States. All of the products sold to our customers for fiscal years 2010, 2009 and 2008 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 natural gas. 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 2011 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 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 13 billion gallons in 2010. 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

The California Low Carbon Fuel Standard may decrease demand for corn based ethanol which could negatively impact our profitability. Recently, California passed a Low Carbon Fuels Standard (LCFS). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which are measured using a lifecycle analysis. Management believes that these new regulations could preclude corn based ethanol produced in the Midwest from being used in California. California represents a significant ethanol demand market. If we are unable to supply ethanol to California, it could significantly reduce demand for the ethanol we produce. While implementation of the California LCFS has recently been delayed, any decrease in ethanol demand as a result of these regulations could negatively impact ethanol prices which could reduce our revenues and negatively impact our ability to profitably operate the ethanol plant.

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 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. However, the EPA is also expected to introduce E15 labeling requirements which may cause consumers to avoid using E15. 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 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 March 15, 2011 there are 204 ethanol plants in the United States with capacity to produce approximately 13.7 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 522 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% of the ethanol production capacity in the United States was idled as of March 15, 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.

The price of distiller grains may decline as a result of China's antidumping investigation of distiller grains originating in the United Sates. Estimates indicate that as much as 10 to 15 percent of the distiller grains produced in the United States will be exported to China in the coming year. However, this export market may be jeopardized if the Chinese government imposes trade barriers in response to the outcome of an antidumping investigation currently being conducted by the Chinese Ministry of Commerce. If producers and exporters of distiller grains are subjected to trade barriers when selling distiller grains to Chinese customers, there may be a reduction in the price of distiller grains in the United States. Declines in the price we receive for our distiller grains will lead to decreased revenues and may result in our inability to operate the ethanol plant profitably.

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 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 55,000,000 gallon annual 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 RESERVED).

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBERMATTERS 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 March 15, 2011, there were 962 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.

Quarter	Low Price		High Price		Average Price		# of Units Traded
2009 1st	$	—	$	—	$	—		—
2009 2nd	$	0.30	$	0.30	$	0.30		10,000
2009 3rd	$	0.20	$	0.20	$	0.20		50,000
2009 4th	$	—	$	—	$	—		—
2010 1st	$	—	$	—	$	—		—
2010 2nd	$	.50	$	.50	$	.50		10,000
2010 3rd	$	—	$	—	$	—		—
2010 4th	$	—	$	—	$	—		—

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 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, 2008, 2007 and 2006 and the selected income statement data and other financial data for the years ended December 31, 2007 and 2006 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 December 31, 2010 and 2009 and the selected statement of operations data and other financial data for each of the years in the three 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.

Statement of Operations Data:	2010			2009			2008			2007			2006
Revenues	$	109,895,184		$	93,836,661		$	131,903,514		$	101,885,969		$	—

Cost Goods Sold		95,946,218			87,850,869			131,025,238			87,013,208			—

Gross Profit		13,948,966			5,985,792			878,276			14,872,761			—

General and Administrative		3,116,212			2,812,891			2,857,091			3,214,002			3,747,730

Operating Income (Loss)		10,832,754			3,172,901			(1,978,815	)		11,658,759			(3,747,730	)

Other Income (Expense)		(1,803,982	)		(2,812,241	)		(3,387,757	)		(5,501,431	)		1,243,667

Net Income (Loss)	$	9,028,772		$	360,660		$	(5,366,572	)	$	6,157,328		$	(2,504,063	)

Weighted Average Units Outstanding – Basic and Diluted		40,193,973			40,191,494			40,176,974			40,371,238			39,625,843

Net Income (Loss) Per Unit	$	0.22		$	0.01		$	(0.13	)	$	0.15		$	(0.06	)

Balance Sheet Data:	2010		2009		2008		2007		2006
Current Assets	$	22,292,500	$	25,384,612	$	16,423,730	$	8,231,709	$	4,761,974

Net Property and Equipment		66,544,644		71,415,582		78,010,042		81,942,542		84,039,740

Total Assets		89,924,953		97,677,401		95,802,453		108,524,254		89,864,228

Current Liabilities		20,451,155		18,634,421		61,968,448		16,807,461		9,781,240

Long-Term Liabilities		26,569,662		45,167,616		275,000		52,813,310		47,153,960

Members’ Equity		42,904,136		33,875,364		33,559,005		38,903,483		32,929,088

Book Value Per Unit	$	1.07	$	0.84	$	0.84	$	0.96	$	0.83

* See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of our financial results.

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.

Results of Operations

Comparison of Fiscal Years Ended December 31, 2010 and 2009

	2010					2009
Income Statement Data	Amount			%		Amount			%
Revenues	$	109,895,184			100.0	$	93,836,661			100.0

Cost of Goods Sold		95,946,218			87.3		87,850,869			93.6

Gross Profit		13,948,966			12.7		5,985,792			6.4

General and Administrative Expenses		3,116,212			2.8		2,812,891			3.00

Operating Income		10,832,754			9.9		3,172,901			3.4

Other Income (Expense), net		(1,803,982	)		1.6		(2,812,241	)		3.0

Net Income	$	9,028,772			8.3	$	360,660			0.4

Revenue

During our 2010 fiscal year, our total revenue increased significantly compared to our 2009 fiscal year. Management attributes this increase in total revenue primarily with a significant increase in the average price we received per gallon of ethanol sold during the 2010 fiscal year in addition to an approximate 2 million gallon increase in gallons sold. We also sold more distillers grains at a higher price during our 2010 fiscal year compared to our 2009 fiscal year. For our 2010 fiscal year, ethanol sales accounted for approximately 84% of our total revenue and distillers grains sales accounted for approximately 16% of our total revenue. For our 2009 fiscal year, ethanol sales accounted for approximately 83% of our total revenue and distillers grains sales accounted for 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 are currently operating the plant at a higher run rate and producing more ethanol for sale. During the first six months of 2009 we experienced very poor margin conditions and chose to run our plant at a slower rate and during the remainder of 2009 we experienced a reduction in production due to an unplanned outage related to an issue with our boiler. These factors reduced our total ethanol production during our 2009 fiscal year.

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. These increases in ethanol exports and corn prices mostly occurred during our fourth quarter of 2010. Additionally, during the year ended December 31, 2010, hedging effects increased revenues by approximately $1.8 million while decreasing revenues by $1.6 million in 2009.

Management anticipates that ethanol prices will remain steady during our 2011 fiscal year. Management anticipates ethanol production will be comparable during our 2011 fiscal year provided the ethanol industry can maintain current ethanol prices. However, in the event ethanol prices decrease significantly, we may be forced to reduce ethanol production during times when our operating margins are unfavorable. Further, our operating margins depend on corn prices which can affect the spread between the price we receive for our ethanol and our raw material costs. In times when this spread decreases or becomes negative, we may reduce or terminate ethanol production until these spreads become more favorable.

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. As we produce more ethanol, the total tons of distillers grains that we produce also increases. 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. During our 2009 fiscal year, uncertainty existed regarding the supply of distillers grains in the market due to the fact that many ethanol producers were reducing production during late 2008 and early 2009. Management believes this resulted in higher distillers grains prices due to increasing demand and lower supplies during our 2009 fiscal year. Further, management believes that distillers grains prices lag behind corn prices. As a result, distillers grains prices during our 2010 fiscal year may not have fully benefited from recent increases in corn prices that we experienced in the second half of our 2010 fiscal year. Management believes corn prices affect the market price of distillers grains since distillers grains are typically used as an animal feed substitute for corn.

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.

Management anticipates demand for distillers grains will remain steady, especially if corn prices trend higher during our 2011 fiscal year. Management believes that increased revenue from distillers grains sales during times when corn prices are high helps us to somewhat offset our increased cost of goods sold from the higher corn prices. Management believes that distillers grains prices could decrease significantly if export demand for distillers grains decreases. This could be especially true in the summer months when distillers grains demand is lower in the United States.

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. In addition to this increase in the total bushels of corn we purchased was an increase in our average cost, net of hedging, per bushel of corn of approximately 1% for our 2010 fiscal year compared to our 2009 fiscal year.

The market price of corn started to increase during December 2010 and has continued to rise well into March 2011. Management attributes this increase in corn prices with uncertainty regarding an imbalance between corn supply and demand. Management anticipates that corn prices will continue to be volatile until corn planting and thereafter will be subject to weather factors that may influence corn prices during the 2011 growing season.

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.

Management anticipates that coal prices will remain steady during our 2011 fiscal year unless demand significantly increases due to improved global economic conditions. Management anticipates that our coal consumption will be comparable during our 2011 fiscal year unless our ethanol and distillers grains production decrease due to market factors in the ethanol industry.

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. We anticipate our general and administrative expenses for 2011 to be lower than 2010, primarily due to a decrease in legal fees.

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.

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.

Comparison of Fiscal Years Ended December 31, 2009 and 2008

	2009					2008
Income Statement Data	Amount			%		Amount			%
Revenues	$	93,836,661			100.0	$	131,903,514			100.0

Cost of Goods Sold	$	87,850,869			93.6	$	131,025,238			99.3

Gross Profit	$	5,985,792			6.4	$	878,276			0.7

General and Administrative Expenses	$	2,812,891			3.0	$	2,857,091			2.2

Operating Income (Loss)	$	3,172,901			3.4	$	(1,978,815	)		1.5

Other Expense	$	(2,812,241	)		3.0	$	(3,387,757	)		2.6

Net Income (Loss)	$	360,660			0.4	$	(5,366,572	)		4.1

Revenue

We experienced a significant decrease in our total revenue for our 2009 fiscal year compared to our 2008 fiscal year. Management attributes this decrease primarily to significant decreases we experienced in the average prices we received for our ethanol and distillers grains during fiscal year 2009 compared to fiscal year 2008. We also experienced a decrease in the total amount of ethanol and distillers grains we sold during our 2009 fiscal year compared to our 2008 fiscal year. For our 2009 fiscal year, ethanol sales comprised approximately 83% of our total revenue and distillers grains comprised approximately 17% of our total revenue. For our 2008 fiscal year, ethanol sales comprised approximately 84% of our total revenue and distillers grains comprised approximately 16% of our total revenue.

Ethanol

We experienced a decrease of approximately 23% in the average price we received for our ethanol for our 2009 fiscal year compared to the same period of 2008. Management attributes this decrease in the average price we received for our ethanol during our 2009 fiscal year compared to the same period of 2008 with decreased commodity prices generally. We experienced a peak in commodity prices during the middle of our 2008 fiscal year. Following this peak, commodity prices, including the price of ethanol, decreased sharply.

During our 2009 fiscal year, the total gallons of ethanol we sold decreased by approximately 10% compared to our 2008 fiscal year. Management attributes this decrease in ethanol sales with decreased ethanol production during 2009 compared to 2008 as a result of a deliberate plant slowdown and unscheduled downtime during our 2009 fiscal year. During the early part of our 2009 fiscal year, the ethanol industry was enduring unfavorable operating conditions. This resulted in periods when our operating margins became negative. In an attempt to avoid losses, we reduced ethanol production during the first six months of 2009. The remaining decrease in production and sales came in October 2009 when we experienced an unplanned outage related to an issue with our boiler. Additionally, we experienced a loss of approximately $474,000 related to derivatives versus a gain of $6.2 million in 2008.

Distillers Grains

The average prices we received for our distillers grains, both DDGS and MDGS, decreased during our 2009 fiscal year compared to the same period of 2008. The average price we received for our DDGS decreased by approximately 19% during our 2009 fiscal year compared to our 2008 fiscal year. In addition, the average price we received for our MDGS decreased by approximately 6% during our 2009 fiscal year compared to our 2008 fiscal year. We experienced a significant decrease in the market prices of corn and soybean meal starting in the middle of 2008 which resulted in a significant decrease in market distillers grains prices.

The total tons of distillers grains we sold during our 2009 fiscal year decreased compared to our 2008 fiscal year. The total tons of DDGS we sold during our 2009 fiscal year increased by approximately 3% compared to our 2008 fiscal year. However, the total tons of MDGS we sold during our 2009 fiscal year decreased by approximately 31% compared to the same period of 2008. We attribute this overall reduction in distillers grains sales with to decreased distillers grains production during our 2009 fiscal year compared to our 2008 fiscal year. Management attributes the decrease in distillers grains production during our 2009 fiscal year with increased plant downtime we experienced during the early part of our 2009 fiscal year.

Cost of Goods Sold

We experienced a significant decrease in our cost of goods sold for our 2009 fiscal year compared to our 2008 fiscal year.

Corn Costs

The total amount we paid for corn, net of hedging, decreased by approximately 34% for our 2009 fiscal year compared to our 2008 fiscal year. Further, our corn consumption decreased by approximately 9% during our 2009 fiscal year compared to our 2008 fiscal year. We used less corn to produce ethanol and distillers grains during our 2009 fiscal year compared to the same period of 2008 as a result of the fact that we experienced increased plant downtime during our 2009 fiscal year compared to our 2008 fiscal year. Additionally, we experienced a net benefit of $475,000 as compared to expense of $6.2 million in fiscal 2008.

During the middle of our 2008 fiscal year, commodities prices, including corn prices, increased significantly causing a peak at the end of June and early July 2008. Following the peak, commodities prices fell sharply. The record high corn prices we experienced during most of our 2008 fiscal year resulted in significantly higher cost of goods sold related to corn costs during our 2008 fiscal year.

Coal Costs

Our cost of coal decreased by approximately 25% during our 2009 fiscal year compared to our 2008 fiscal year, primarily due to a decrease in the price of coal and the amount of coal used during our 2010 fiscal year compared to our 2009 fiscal year. We consumed approximately 9% less coal during our 2009 fiscal year compared to our 2008 fiscal year. This decrease in coal consumption was due to our reduced production of ethanol and distillers grains during our 2010 fiscal year. The per ton cost of coal also decreased by approximately 17% during our 2010 fiscal year compared to our 2009 fiscal year. Management attributes this decrease in our per ton cost of coal with the lower market prices of most commodities from the period 2008 to 2009.

General and Administrative Expenses

Our general and administrative expenses decreased by approximately 2% during our 2009 fiscal year compared to our 2008 fiscal year. Management attributes this decrease in operating expenses with to a reduction in fees paid to our management company during our 2009 fiscal year compared to our 2008 fiscal year. We also had a decrease in various general and administrative costs due to cost cutting measures instituted at the beginning of 2009. We had lower board meeting expense costs as our board members suspended their pay for 2009, we also had lower office supplies expense costs, lower purchased services costs and smaller decreases in other areas. Some of these decreases were partially offset by an increase in bank fees as we negotiated a deferral of certain principal payments and an increase in professional fees associated with the development of our corn procurement program and environmental permit compliance.

Other Expense

Our net other expenses decreased during our 2009 fiscal year compared to our 2008 fiscal year. This was primarily due to decreases in the amount of interest expense paid in 2009 compared to 2008 as we paid down our long-term debt obligations and had a lower effective interest rate on our long term debt in 2009 versus 2008. Additionally, we experienced a net expense from our swap agreement of approximately $490,000 as compared to approximately $2.3 million in 2009.

Changes in Financial Condition for Fiscal Years Ended December 31, 2009 and 2008

Assets

Our current assets were 55% higher at December 31, 2009 compared to December 31, 2008. We had more cash and inventory on hand at December 31, 2009 compared to December 31, 2008. We were accumulating cash in anticipation of making a principal and interest payments to our primary lender and as a precaution due to market uncertainty at the time.

The value of our inventory was higher at December, 31 2009 and at December 31, 2008, primarily because we had more raw materials on hand at December 31, 2009. However, the value of our raw material inventory was lower at December 31, 2009 compared to December 31, 2008 primarily as a result of decreased market corn prices at December 31, 2009. In addition, the value of our finished goods inventory was higher at December 31, 2009 compared to December 31, 2008 as a result of an increase in the volume of ethanol on hand compared to December 31, 2008.

The net value of our property, plant and equipment was significantly lower at December 31, 2009 compared to December 31, 2008. This decrease in the net value of our property and equipment resulted primarily from continued depreciation of assets which increased accumulated depreciation.

Liabilities

The amount of current maturities of long-term debt was approximately $6,500,000 at December 31, 2009 compared to approximately $49,000,000 at December 31, 2008. This is primarily a result of all our long-term debt being shown as current at December 31, 2008 because we were in violation of our loan covenants and were projecting that we would be in violation of those covenants throughout 2009. As of December 31, 2009, we were able to reclassify our debt between current and long-term in accordance with the scheduled principal payments due to projections for fiscal 2010 estimating compliance with those covenants.

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.

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.

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 December 31, 2010, we had approximately $9,800,000 in cash, $7,000,000 available to draw on one line of credit and $8,200,000 available on another line of credit, $4,100,000 of which is restricted for use related to construction retention payables. 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.

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	$	13,083,114		$	7,936,258
Net cash (used in) provided by 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.

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.

The following table shows cash flows for the fiscal years ended December 31, 2009 and 2008:

	Year ended December 31,
	2009		2008
Net cash provided by operating activities	$	7,936,258	$	8,495,564
Net cash provided by (used in) investing activities		532,170		(2,300,195	)
Net cash provided by (used in) financing activities		311,824		(9,993,239	)

Cash Flow From Operations

Cash flows provided by operating activities in our 2009 fiscal year decreased approximately $560,000 as compared to fiscal 2008. Contributing to this decrease was a reduction in the fair value of our interest rate swaps and other derivative instruments by approximately $3,400,000. This reduction in the value of our derivatives was offset by an increase in net income in the amount of approximately $5,727,000 between our 2008 fiscal year and our 2009 fiscal year. We also had a net increase in cash flow from changes in working capital items of approximately $1,478,000, this increase was offset by a reduction in restricted cash set aside for our commodities derivatives account of approximately $1,470,000.

Cash Flow From Investing Activities

Cash flows provided by (used in) investing activities in 2009 decreased significantly compared to 2008, the result of lower capital expenditures in 2009. We had very minimal capital expenditures during 2009 as we didn’t have any major projects to being completed and conserved cash in an effort to maintain liquidity. We also received a refund of sales tax amounts paid on the original construction of our plant which reduced the cost of our plant and are shown as an offset to our capital expenditures on the cash flow statement. We had one major capital project during 2008 which was our coal unloading facility.

Cash Flow From Financing Activities

Cash flows provided by (used in) financing activities in 2009 decreased significantly compared to 2008 primarily related to lower debt payments in 2009 and borrowing the remaining capacity on our long-term note during 2009. Our bank allowed us to defer two principal payments during 2009 which decreased our debt service requirements by approximately $2,200,000. These payments will be added to the end of the term of the loan. We made scheduled debt service payments of approximately $2,500,000. In addition we borrowed the remaining $3,500,000 of available capacity on our long-term note during 2009.

Short-Term Debt Sources

During November 2010, we entered into a $7,000,000 line of credit agreement with our bank subject to certain borrowing base limitations with a maturity date of June 1, 2011. The line-of-credit accrues 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 December 31, 2010.

Long-Term Debt Sources

Our primary debt instruments are with First National Bank of Omaha (the “Bank” of “FNBO”) and have a scheduled maturity date of April 2012. These debt instruments include fixed and variable rate notes. The following table summarizes our long-term debt instruments with the Bank.

	Outstanding Balance (Millions)				Interest Rate						Range of Estimated
Term Note	December 31, 2010		December 31, 2009		December 31, 2010			December 31, 2009			Quarterly Principal Payment Amounts		Notes
Fixed Rate Note	$	21.30	$	23.60		6.00	%		6.00	%	$	600,000 - $660,000		1, 2, 3
2007 Fixed Rate Note		7.90		8.80		6.00	%		6.00	%	$	220,000 - $240,000		1, 2, 3
Variable Rate Note		0		2.10		6.00	%		6.00	%	$	450,000 - $460,000		5
Long-Term Revolving Note		0		10.00		6.00	%		6.00	%	$	277,000 - $535,000		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 December 31, 2010.

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 loan agreement in March 2010, amount available to borrow on this revolving note is reduced by $634,700 per quarter until available amount equals $4,100,000. As of December 31, 2010, amount available is $8,200,000.

5 - This note was paid and closed in March 2010 upon execution of the loan agreement amendment.

Interest Rate Swap Agreements

In December 2005, we entered into an interest rate swap transaction that effectively fixed the interest rate at 8.08% on the outstanding principal of the Fixed Rate Note. In December 2007, we entered into a second interest rate swap transaction that effectively fixed the interest rate at 7.695% on the outstanding principal of the December 2007 Fixed Rate Note. The interest rate swaps were not designated as either a cash flow or fair value hedge. Fair value adjustments are shown in interest expense.

Subordinated Debt

As part of the construction loan agreement, we entered into three separate subordinated debt agreements totaling approximately $5,525,000 and received funds from these debt agreements during 2006. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate which totaled 8.0% at December 31, 2010, 2009 and 2008. Per the terms of the Mediated Settlement Agreement (the Agreement) 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 we fail 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 December 31, 2010 and 2009, respectively.

Letters of Credit

We were issued two letters of credit during the second quarter of 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 2.5% quarterly commitment fee. The letters of credit remain outstanding at December 31, 2010.

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 “audited” 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;

Limiting our ability to make distributions to members; and

Maintain a threshold of capital expenditures

The debt instruments with the Bank also contain a number of events of default (including violation of our loan covenants) which, if any of them were to occur, would give the Bank certain rights, including but not limited to:

declaring all the debt owed to the Bank immediately due and payable; and

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

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

As of December 31, 2010 we are in compliance with our loan covenants.

Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of December 31, 2010:

Contractual Obligations	Total		Less than 1 Yr		1-3 Years		3-5 Years		More than 5 Yrs
Long-term debt obligations *	$	37,219,651	$	10,695,451	$	26,524,200	$	―	$	―
Capital leases		11,460		3,354		8,106		―		―
Operating lease obligations		1,130,964		545,184		538,980		46,800		―
Corn Purchases **		5,886,148		5,886,148		―		―		―
Coal purchases		1,487,250		1,487,250		―		―		―
Contractual Obligation		517,900		517,900		―		―		―
Management Agreement		171,600		171,600		―		―		―
Water purchases		2,438,400		406,400		812,800		812,800		406,400
Total	$	48,863,373	$	19,713,287	$	27,884,086	$	859,600	$	406,400

* - 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 December 31, 2010 for basis contracts that had not yet been fixed.

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 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 in 2011.

Job Service North Dakota

We have entered into an agreement with Job Service North Dakota for a new jobs training program. This program provides incentives to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training. We are eligible to receive up to approximately $270,000 over ten years. We have received and earned approximately $36,000 and $37,000 fiscal years ended December 31, 2010 and 2009, respectively.

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 commodity prices and interest rates 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 natural gas. 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 accounting guidance.

Interest Rate Risk

Exposure to interest rate risk results primarily from holding revolving lines of credit and subordinated debt which bear variable interest rates. As of December 31, 2010, we did not have any amounts drawn on our variable rate senior debt that expose us to interest rate risk as the interest rate on our senior debt has effectively been set at a fixed rate with the use of underlying interest rate swap agreements. Our subordinated debt bears variable interest rates. Specifically, we had approximately $5,525,000 outstanding in variable rate subordinated debt as of December 31, 2010. The specifics of each note are discussed in greater detail in “ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Credit Facilities.”

Below is a sensitivity analysis we prepared regarding our income exposure to an adverse 10% change in interest rates on our subordinated debt for a one year period as of December 31, 2010.

Outstanding Subordinated Variable Rate Debt at 12/31/10				Interest Rate at 12/31/10				Interest Rate After Adverse 10% Change				Approximate Adverse Change to Income
$	5,525,000				8.0	%			8.8	%		$	44,200

Commodity Price Risk

We seek to minimize the risks from fluctuations in the prices of raw material inputs, such as corn, and finished products, such as ethanol and distillers grains, through the use of hedging instruments. In practice, as markets move, we actively manage our risk and adjust hedging strategies as appropriate. Although we believe our hedge positions accomplish an economic hedge against our future purchases and sales, management has chosen not to use hedge accounting, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged. We are using fair value accounting for our hedge positions, which means as the current market price of our hedge positions changes, the realized or unrealized gains and losses are immediately recognized in our cost of goods sold or as an offset to revenues. The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged.

As corn prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects, but are expected to produce long-term positive growth for us.

A sensitivity analysis has been prepared to estimate our exposure to ethanol, corn and coal price risk. Market risk related to these factors is estimated as the potential change in income resulting from a hypothetical 10% adverse change in the fair value of our corn and coal prices and average ethanol price as of December 31, 2010, net of the forward and future contracts used to hedge our market risk for corn and coal usage requirements. The volumes are based on our expected use and sale of these commodities for a one year period from December 31, 2010. The results of this analysis, which may differ from actual results, are as follows:

	Estimated Volume Requirements for the next 12 months (net of forward and futures contracts)		Unit of Measure	Hypothetical Adverse Change in Price as of 12/31/2010			Approximate Adverse Change to Income
Coal		98,000	Tons		10	%	$	375,000
Ethanol		53,000,000	Gallons		10	%	$	11,660,000
Corn		19,000,000	Bushels		10	%	$	10,450,000

For comparison purposes, a sensitivity analysis for our 2009 fiscal year ended December 31, 2009 is set forth below.

	Estimated Volume Requirements for the next 12 months (net of forward and futures contracts)		Unit of Measure	Hypothetical Adverse Change in Price as of 12/31/2009			Approximate Adverse Change to Income
Coal		89,000	MMBtu		10	%	$	365,000
Ethanol		50,000,000	Gallons		10	%	$	7,800,000
Corn		18,000,000	Bushels		10	%	$	6,785,000

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements begin on page 33.

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 December 31, 2010 and 2009, and the related statements of operations, changes in members’ equity, and cash flows for each of the years in a three-year period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in a three-year period ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

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

Minneapolis, Minnesota

March 31, 2011

RED TRAIL ENERGY, LLC

Balance Sheets

December 31, 2010 and 2009

	2010		2009
ASSETS
Current Assets
Cash and equivalents	$	9,800,409	$	13,214,091
Restricted cash		1,331,516		2,217,013
Accounts receivable, primarily related party		4,632,300		2,635,775
Commodities derivative instruments, at fair value		49,262		129,063
Inventory		6,396,524		6,993,031
Prepaid expenses		82,489		195,639
Total current assets		22,292,500		25,384,612

Property, Plant and Equipment
Land		351,280		351,280
Land improvements		3,984,703		3,970,500
Buildings		5,317,283		5,312,995
Plant and equipment		79,671,534		79,199,850
Construction in progress		441,897		―
		89,766,697		88,834,625

Less accumulated depreciation		23,222,053		17,419,043
Net property, plant and equipment		66,544,644		71,415,582

Other Assets
Investment in RPMG		605,000		605,000
Patronage equity		442,809		192,207
Deposits		40,000		80,000
Total other assets		1,087,809		877,207
Total Assets	$	89,924,953	$	97,677,401

LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
Accounts payable	$	8,026,184	$	7,605,302
Accrued expenses		2,318,741		2,634,534
Commodities derivative instruments, at fair value		―		806,490
Current maturities of long-term debt		8,924,747		6,500,000
Current portion of interest rate swaps, at fair value		1,181,483		1,088,095
Total current liabilities		20,451,155		18,634,421

Long-Term Liabilities
Notes payable		25,770,222		43,620,025
Long-term portion of interest rate swaps, at fair value		524,440		1,272,591
Contracts payable		275,000		275,000
Total long-term liabilities		26,569,662		45,167,616

Commitments and Contingencies (See Note 10)		―		―

Members' Equity		42,904,136		33,875,364

Total Liabilities and Members' Equity	$	89,924,953	$	97,677,401

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

RED TRAIL ENERGY, LLC

Statements of Operations

Years Ended December 31, 2010, 2009 and 2008

	2010			2009			2008

Revenues, primarily related party	$	109,895,184		$	93,836,661		$	131,903,514

Cost of Goods Sold
Cost of goods sold		95,946,218			86,217,369			126,783,928
Lower of cost or market adjustment		―			1,464,500			771,200
Loss on firm purchase commitments		―			169,000			3,470,110
Total Cost of Goods Sold		95,946,218			87,850,869			131,025,238

Gross Profit		13,948,966			5,985,792			878,276

General and Administrative Expenses		3,116,212			2,812,891			2,857,091

Operating Income (Loss)		10,832,754			3,172,901			(1,978,815	)

Other Income (Expense)
Interest income		37,297			470,055			426,232
Other income		1,358,731			706,620			2,199,310
Interest expense		(3,200,010	)		(3,988,916	)		(6,013,299	)
Total other expense, net		(1,803,982	)		(2,812,241	)		(3,387,757	)

Net Income (Loss)	$	9,028,772		$	360,660		$	(5,366,572	)

Basic and diluted for each:
Weighted Average Units Outstanding		40,193,973			40,191,494			40,176,974

Net Income (Loss) Per Unit	$	0.22		$	0.01		$	(0.13	)

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

RED TRAIL ENERGY, LLC

Statements of Changes in Members’ Equity

Years Ended December 31, 2010, 2009 and 2008

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

Balance - January 1, 2008		40,173,973	$	37,810,408	$	101,825		$	1,219,183			200,000		$	(227,933	)	$	38,903,483
Unit-based compensation		―		―		20,000			―			―			―			20,000
Units issued under compensation agreement		15,000		―		(15,000	)		―			(15,000	)		17,094			2,094
Net Loss		―		―		―			(5,366,572	)		―			―			(5,366,572	)

Balance - December 31, 2008		40,188,973		37,810,408		106,825			(4,147,389	)		185,000			(210,839	)		33,559,005
Unit-based compensation		―		―		(55,000	)		―			―			―			(55,000	)
Units issued under compensation agreement		5,000		―		5,000			―			(5,000	)		5,699			10,699
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

(a) - Amounts shown represent member units outstanding.

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

RED TRAIL ENERGY, LLC

Statements of Cash Flows

Years Ended December 31, 2010, 2009 and 2008

	2010			2009			2008

Cash Flows from Operating Activities
Net income (loss)	$	9,028,772		$	360,660		$	(5,366,572	)
Adjustment to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depreciation		5,874,232			5,893,180			5,796,805
Amortization and write-off of debt issuance costs		―			567,385			201,020
Loss on disposal of fixed assets		68,446			―			―
Change in fair value of derivative instruments		(18,829	)		116,994			3,505,350
Equity-based compensation		―			(49,301	)		22,094
Non-cash patronage equity		(250,602	)		(75,911	)		(116,296	)
Unrealized loss on firm purchase commitments		―			(1,426,800	)		1,426,800
Grant income applied to long-term debt		―			―			(59,874	)
Changes in assets and liabilities
Restricted cash - commodities derivatives account		885,497			31,778			1,504,072
Accounts receivable		(1,996,525	)		61,920			3,262,346
Inventory		596,507			(3,639,439	)		4,943,764
Prepaid expenses		113,150			4,244,174			(4,386,402	)
Deposits		40,000			―			―
Accounts payable		420,882			2,053,648			(1,130,676	)
Accrued expenses		(315,793	)		789,433			(657,835	)
Cash settlements on interest rate swaps		(1,362,623	)		(991,463	)		(449,032	)
Net cash provided by operating activities		13,083,114			7,936,258			8,495,564
Cash Flows from Investing Activities
Investment in RPMG		―			(169,110	)		(435,890	)
Refund of sales tax on fixed assets		―			763,630			―
Proceeds from disposal of fixed assets		134,845			―			―
Capital expenditures		(1,206,585	)		(62,350	)		(1,864,305	)
Net cash provided by (used in) investing activities		(1,071,740	)		532,170			(2,300,195	)
Cash Flows from Financing Activities
Debt repayments		(15,425,056	)		(2,516,684	)		(10,153,739	)
Proceeds from long-term debt		―			3,573,508			160,500
Restricted cash		―			(750,000	)		―
Treasury units issued		―			5,000			―
Net cash provided by (used in) financing activities		(15,425,056	)		311,824			(9,993,239	)

Net Increase (Decrease) in Cash and Equivalents		(3,413,682	)		8,780,252			(3,797,870	)
Cash and Equivalents - Beginning of Period		13,214,091			4,433,839			8,231,709
Cash and Equivalents - End of Period	$	9,800,409		$	13,214,091		$	4,433,839

Supplemental Disclosure of Cash Flow Information
Interest paid net of swap settlements	$	2,739,854		$	3,026,980		$	4,404,790

SUPPLEMENT DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Investments included in accounts payable	$	―		$	―		$	169,110

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

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

Fiscal Reporting Period

The Company adopted a fiscal year ending December 31 for reporting financial operations for the periods presented in these financial statements. Effective January 1, 2011, the Company adopted a fiscal year end of September 30 for reporting financial operations.

Use of Estimates

The preparation of the financial statements, in accordance with generally accepted principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Significant items subject to such estimates and assumptions include the useful lives of property, plant and equipment; valuation of derivatives, inventory, 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 years ended December 31, 2009 and 2008 have been changed to conform to the classifications used in 2010. The reclassifications had no effect on members’ equity, net income (loss) or operating cash flows 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 December 31, 2010 and 2009, the total amount of restricted cash related to these bonds was $750,000. The Company also had restricted cash to meet its derivative hedge account requirements. The total amount of cash restricted in its hedge account at December 31, 2010 and 2009 was approximately $578,000 and $1.5 million, 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 $753,175 and $5,010,325 at December 31, 2010 and 2009, 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 wet distiller’s grains internally.

For sales of wet 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.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

All receivables are stated at amounts due from customers net of any allowance for doubtful accounts. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s perceived current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. There was no allowance for doubtful accounts deemed necessary based on management’s analysis at December 31, 2010 or 2009.

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 first-in, first-out (FIFO) basis.

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.

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 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.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

Revenue Recognition

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

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

Long-lived Assets

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

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.

Debt Issuance Costs

Debt issuance costs were amortized over the term of the related debt by use of the effective interest method. Amortization commenced June 2006 when the Company began drawing on the related bank loan. Due to uncertainties with our loan agreements, the Company wrote off the remaining balance (approximately $517,000) of its debt issuance costs during the first quarter of 2009. Amortization and impairment expense totaled $0, $567,000 and $201,000 for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts are included in interest expense within the statement of operations.

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.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

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.

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 years ended December 31, 2010 or 2009 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 at December 31, 2010 and 2009 and the fair value approximated the carrying value (see Note 6). The fair value of long-term debt has been estimated using discounted cash flow analysis based upon the Company’s current incremental borrowing rates for similar types of financing arrangements.

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 2010, 2009, and 2008, the Company had 0, 0 and 50,000 member unit equivalents, respectively. For 2008, member unit equivalents were not included in diluted equivalents outstanding as their effect is anti-dilutive.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

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 was notified in March 2011 that an environmental liability of approximately $47,000 existed as of December 31, 2010. Currently, the Company is not aware of any further liabilities identified as of December 31, 2010 or prior years.

2. CONCENTRATIONS

Coal

Coal is an important input to our manufacturing process. During the fiscal year ended December 31, 2010, we used approximately 98,200 tons of coal. We have entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2011. 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 74% and 77% of the Company’s outstanding receivable balance at December 31, 2010 and 2009, respectively. Approximately 84%, 83% and 84% of revenues are comprised of sales to RPMG for the years ended December 31, 2010, 2009 and 2008, 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

From time to time, the Company enters into derivative transactions to hedge its exposures to interest rate and commodity price fluctuations. The Company does not enter into derivative transactions for trading purposes.

The Company provides qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses from derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

During 2010 and 2009, the Company had entered into interest rate swap agreements along with corn and ethanol derivative instruments. The Company records its derivative financial instruments as either assets or liabilities at fair value in the balance sheets. Derivatives qualify for treatment as hedges when there is a high correlation between the change in fair value of the derivative instrument and the related change in value of the underlying hedged item. Based upon the exposure being hedged, the Company designates its hedging instruments as a fair value hedge, a cash flow hedge, a hedge against foreign currency exposure or leaves them undesignated. The Company formally documents, designates, and assesses the effectiveness of transactions that receive hedge accounting initially and on an on-going basis. The Company does not currently have any derivative instruments that are designated as effective hedging instruments for accounting purposes. The following table presents notional amounts and derivative contracts outstanding:

As of:	December 31, 2010					December 31, 2009
Contract Type	# of Contracts		Notional Amount (Qty)	Fair Value		# of Contracts		Notional Amount (Qty)	Fair Value
Corn futures		237	1,185,000 bushels	$	49,262		82	410,000 bushels	$	129,063
Ethanol swap contracts		―	― gallons		―		530	7,632,000 gallons		(806,490	)
Total fair value				$	49,262				$	(677,427	)

Amounts are recorded separately on the balance sheet - negative numbers represent liabilities

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 and 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.

Interest Rate Contracts

The Company manages its floating rate debt using interest rate swaps. The Company has entered into fixed rate swaps to alter its exposure to the impact of changing interest rates on its results of operations and future cash outflows for interest. Fixed rate swaps are used to reduce the Company’s risk of the possibility of increased interest costs. Interest rate swap contracts are therefore used by the Company to separate interest rate risk management from the debt funding decision.

At December 31, 2010 and 2009, the Company had approximately $27.7 million and $30.8 million, respectively, of notional amount outstanding in swap agreements that exchange variable interest rates (one-month LIBOR and three-month LIBOR) for fixed interest rates over the terms of the agreements. The fair value of the interest rate swaps is included in current liabilities and other long-term liabilities in the balance sheets and totaled approximately $1.7 million and $2.4 million as of December 31, 2010 and 2009, respectively. These agreements are not designated as effective hedges for accounting purposes and the change in fair market value is recorded in interest expense within the statement of operations. The swaps mature in April 2012.

The following tables provide details regarding the Company’s derivative financial instruments at December 31, 2010 and 2009:

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

Derivatives not designated as hedging instruments for accounting purposes

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

Balance Sheet - as of December 31, 2009	Asset		Liability
Commodity derivative instruments, at fair value	$	129,063	$	806,490
Interest rate swaps, at fair value		―		2,360,686
Total derivatives not designated as hedging instruments for accounting purposes	$	129,063	$	3,167,176

Statement of Operations Income/(expense)	Location of gain (loss) recognized in income	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			Amount of gain (loss) recognized in income during the year ended December 31, 2008
Corn derivative instruments	Cost of Goods Sold	$	(1,826,268	)	$	(474,643	)	$	6,154,162
Ethanol derivative instruments	Revenues		1,830,306			(1,561,940	)		(2,326,266	)
Interest rate swaps	Interest Expense		(707,859	)		(490,619	)		(2,266,371	)
Total		$	(703,821	)	$	(2,527,202	)	$	1,561,525

4. INVENTORY

Inventory values as of December 31, 2010 and 2009 consists of the following:

As of December 31,	2010		2009
Raw materials, including corn, chemicals and supplies	$	3,531,671	$	4,260,376
Work in process		907,967		642,701
Spare parts		776,029		661,156
Finished goods, including ethanol and distillers grains		1,180,857		1,428,798
Total inventory	$	6,396,524	$	6,993,031

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

5. BANK FINANCING

As of	December 31, 2010		December 31, 2009
Notes payable under loan agreement to bank	$	29,160,099	$	44,541,350
Subordinated notes payable		5,525,000		5,525,000
Capital lease obligations (Note 7)		9,870		53,675
Total Long-Term Debt		34,694,969		50,120,025
Less amounts due within one year		8,924,747		6,500,000
Total Long-Term Debt Less Amounts Due Within One Year	$	25,770,222	$	43,620,025

Market value of interest rate swaps		1,705,923		2,360,686
Less amounts due within one year		1,181,483		1,088,095
Total Interest Rate Swaps Less Amounts Due Within One Year	$	524,440	$	1,272,591

Scheduled maturities for the twelve months ended December 31
	Interest rate swaps		Long-term debt		Totals

2011	$	1,181,483	$	8,924,747	$	10,106,230
2012		524,440		25,765,769		26,290,209
2013		―		3,086		3,086
2014		―		1,367		1,367
Thereafter		―		―		―
Total	$	1,705,923	$	34,694,969	$	36,400,892

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.

The Company had interest expense of $3,200,010, $3,988,916, and $6,013,299 for the years ended December 31, 2010, 2009 and 2008, respectively.

Construction Loan

The Company has three long-term notes (collectively the “Term Notes”) in place as of December 31, 2010 and four long-term notes in place as of December 31, 2009. Three of the notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007. The fourth note was entered into during December 2007 (the “December 2007 Fixed Rate Note”) when the Company entered into a second interest rate swap agreement which effectively fixed the interest rate on an additional $10 million of debt. The construction loan agreement requires the Company to maintain certain financial ratios and meet certain non-financial covenants. Each note has specific interest rates and terms as described below. Based on the terms of the security agreement, the debt is secured by substantially all of the assets of the Company.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

Term Notes - Construction Loan

	Outstanding Balance
	(Millions)				Interest Rate						Range of Estimated
	December		December		December			December			Quarterly Principal
Term Note	31, 2010		31, 2009		31, 2010			31, 2009			Payment Amounts		Notes

Fixed Rate Note	$	21.30	$	23.60		6.00	%		6.00	%	$	600,000 - $660,000		1, 2, 3
2007 Fixed Rate Note		7.90		8.80		6.00	%		6.00	%	$	220,000 - $240,000		1, 2, 3
Long-Term Revolving Note		0		10.00		6.00	%		6.00	%	$	277,000 - $535,000		1, 2, 3, 4
Variable Rate Note		0		2.10		6.00	%		6.00	%	$	450,000 - $460,000		5

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 December 31, 2010.

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 by $634,700 per quarter until available amount equals $4.1m. As of December 31, 2010, amount available was $8.2m.

5 - This note was paid and closed in March 2010 upon execution of the 7th Amendment to the construction loan agreement.

Revolving Line of Credit

During November 2010, the Company entered into a $7,000,000 line of credit agreement with its bank subject to certain borrowing base limitations with a maturity date of June 1, 2011. The line-of-credit accrues 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 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. See Note 3 for details of these agreements at December 31, 2010 and 2009.

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 2.5% 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 December 31, 2010, 2009 and 2008. 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 December 31, 2010 and 2009, respectively.

6. FAIR VALUE

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010 and 2009, respectively.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

					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	$	―
Total	$	1,705,923	$	1,705,923	$	―	$	1,705,923	$	―

					Fair Value Measurement Using
	Carrying Amount as of December 31, 2009		Fair Value as of December 31, 2009		Level 1		Level 2		Level 3
Assets
Commodities derivative instruments	$	129,063	$	129,063	$	129,063		―		―
Liabilities
Interest rate swaps	$	2,360,686	$	2,360,686	$	―	$	2,360,686	$	―
Commodities derivative instruments		806,490		806,490		806,490		―		―
Total	$	3,167,176	$	3,167,176	$	806,490	$	2,360,686	$	―

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 discounting cash flow analysis on the expected cash flows of each instrument. The analysis of the interest rate swap reflects the contractual terms of the derivatives, including the period to maturity and uses observable market-based inputs and uses the market standard methodology of netting the discounted future fixed cash receipts and the discounted expected variable cash payments. The variable cash payments are based on an expectation of future interest rates derived from observable market interest rate curves.

Financial Instruments Not Measured at Fair Value

The estimated fair value of the Company’s long-term debt, including the short-term portion, at December 31, 2010 and 2009 approximated the carrying value of approximately $34.7 and $50.0 million, respectively. Fair value was estimated using estimated market interest rates as of December 31, 2010 and 2009. 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 an operating lease includes a locomotive, rail cars and a pay-loader. Rent expense for operating leases was $546,000, $506,000 and $356,000 for the years ending December 31, 2010, 2009 and 2008, respectively. Equipment under capital leases consists of office and plant equipment.

Equipment under capital leases is as follows:

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

As of December 31,	2010		2009
Equipment	$	12,976	$	219,476
Accumulated amortization		3,893		63,248
Net equipment under capital lease	$	9,083	$	156,228

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

As of December 31, 2010	Operating Leases		Capital Leases
2011	$	545,184	$	3,354
2012		473,080		3,354
2013		65,900		3,354
2014		31,200		1,398
2015		15,600		―
Total minimum lease commitments	$	1,130,964		11,460
Less amount representing interest				1,590
Present value of minimum lease commitments included in liabilities on the balance sheet			$	9,870

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 December 31, 2010 and 2009 there were 40,193,973 units issued and outstanding. The Company also held a total of 180,000 treasury units as of December 31, 2010 and 2009.

Total units authorized are 40,373,973 as of December 31, 2010 and 2009.

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 2011.

The Company has entered into an agreement with Job Service North Dakota for a new jobs training program. This program provides incentives to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training. The Company is eligible to receive up to approximately $270,000 over ten years. The Company received and earned approximately $36,000 and $37,000 fiscal years ended December 31, 2010 and 2009, respectively.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

10. COMMITMENTS AND CONTINGENCIES

Design Build Contract

The Company signed a Design-Build Agreement with Fagen, Inc. (“Fagen”) in September 2005 to design and build the ethanol plant at a total contract price of approximately $77 million. The 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. Currently, the Company is working towards meeting the terms of the Test by constructing certain capital additions to the Plant. The Test is expected to take place during fiscal 2011. Additionally, there will be certain payments to third parties and releases received by the Company from third parties once the Test is achieved. At December 31, 2010 and 2009, 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.

Marketing Agreements

The Company entered into a marketing agreement on January 1, 2008 with RPMG for the purposes of marketing and distributing all of the ethanol produced at the Plant. Currently, the Company owns 8.33% of the outstanding capital stock of RPMG and anticipates that its ownership interest will be reduced if other ethanol plants that utilize RPMG’s marketing services become owners of RPMG. The Company’s ownership interest in RPMG entitles it to a seat on its board of directors which is filled by its Chief Executive Officer (“CEO”). The agreement will be in effect as long as the Company continues to be a member in RPMG. The marketing agreement with RPMG requires the Company to pay a marketing fee of approximately $.004/gallon.

The Company entered into a marketing agreement on March 10, 2008 with CHS for the purpose of marketing and selling its DDGS. The marketing agreement has a term of six months which is automatically renewed at the end of the term. The agreement can be terminated by either party upon written notice to the other party at least thirty days prior to the end of the term of the agreement. Under the terms of the agreement, the Company pays CHS a fee for marketing its DDGS. The fee is 2% of the selling price of the DDGS subject to a minimum of $1.50 per ton and a maximum of $2.15 per ton. Through the marketing of CHS and its relationships with local farmers, the Company is not dependent upon one or a limited number of customers for its DDGS sales.

Firm Purchase Commitments for Corn

To ensure an adequate supply of corn to operate the Plant, the Company enters into contracts to purchase corn from local farmers and elevators. At December 31, 2010, the Company had various fixed and basis contracts for approximately 1.1 million bushels of corn. Of the 1.1 million bushels under contract, essentially all had a fixed price as of December 31, 2010. Using the stated contract price for the fixed contracts and using market prices, as of December 31, 2010 and 2009, to price the basis contracts the Company had commitments of approximately $5.9 and $4.1 million, respectively, related to 1.1 million bushels under contract for both years.

Coal Purchase Contract

The Company entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through December 2011. The Company is required to purchase between 90,000 and 115,000 tons of coal per year under this agreement. Coal costs under this agreement totaled $3.58 and $3.31 million for the years ended December 31, 2010 and 2009, respectively.

Consulting Contracts

In November, 2009, the Company entered into an Amended and Restated Management Agreement (MA) with Greenway Consulting, LLC through December 2011. Under the terms of the MA, the Company assumes responsibility for day to day operations of the plant, and the Company’s plant manager and CEO are direct employees of the Company. For the years ended December 31, 2010, 2009 and 2008, the Company recognized approximately $452,000, $175,000 and $534,000, respectively, per the terms of the MA and recognized approximately $0, $296,000 and $288,000 for reimbursement of salary and benefits.

Construction in progress

The Company had construction in progress of approximately $442,000 at December 31, 2010 relating 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. This project is scheduled to be completed in 2011 with an estimated total cost of $900,000.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

11. DEFINED BENEFIT CONTRIBUTION PLAN

The Company established a simple IRA retirement plan for its employees during 2006. The Company matches employee contributions to the plan up to 3% of employee’s gross income. The amount contributed by the Company is vested 100% as soon as the contribution is made on behalf of the employee. The Company contributed approximately $57,000, $48,000 and $56,000 for fiscal years ended December 31, 2010, 2009 and 2008, respectively.

On December 22, 2010, the Company’s board of governors approved replacing the simple IRA retirement plan with a 401k retirement plan for its employees effective January 1, 2011. Employees aged 19 or over who have worked a minimum of 500 hours for the Company over the previous six month period are eligible to participate in the plan. The Company matches employee contributions to the plan up to 4% of employee’s gross income. No employer match contribution was made to the Plan during the year ended December 31, 2010.

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 DDGs and sale of ethanol. The related parties include unit holders, members of the board of governors of the Company, and RPMG. Significant related party activity affecting financial statements are as follows:

As of December 31,			2010		2009
Balance Sheet
Accounts receivable			$	3,821,873	$	2,155,238
Accounts payable				725,184		1,164,218
Notes payable				―		1,525,000

	2010		2009		2008
Statement of Operations
Revenues	$	92,533,888	$	82,162,189	$	117,379,764
Cost of goods sold		3,317,920		2,854,692		2,712,392
General and administrative expenses		114,614		470,906		1,058,632

Inventory Purchases	$	6,112,139	$	6,996,695	$	9,669,953

13. INCOME TAXES

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

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

As of December 31	2010			2009

Financial Statement Basis of Assets	$	89,924,953		$	97,677,401
Organization and start-up costs		4,087,843			4,614,644
Inventory and compensation		30,225			65,058
Net book value of property, plant and equipment		(34,299,928	)		(27,822,932	)
Book to tax derivative difference		49,262			158,436
Income Tax Basis of Assets	$	59,792,355		$	74,692,607

Financial Statement Basis of Liabilities	$	46,976,008		$	63,802,037
Interest rate swap		(1,705,923	)		(2,360,686	)
Book to tax derivative difference		―			(806,490	)
Income Tax Basis of Liabilities	$	45,270,085		$	60,634,861

14. SUBSEQUENT EVENTS

In January 2011, the Company 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 $600,000.

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 2011 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.

RED TRAIL ENERGY, LLC

Notes to Financial Statements

December 31, 2010 and 2009

16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarter results are as follows:

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 (loss)		(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

Year ended December 31, 2008	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	33,420,005		$	35,692,315		$	36,047,461		$	26,743,733
Gross profit (loss)		5,752,783			5,231,790			(2,596,857	)		(7,509,440	)
Operating income (loss)		5,006,187			4,312,457			(3,263,723	)		(8,033,736	)
Net income (loss)		2,736,199			5,064,044			(3,544,887	)		(9,621,928	)
Net income (loss) per unit-basic and diluted		0.07			0.13			(0.09	)		(0.24	)

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.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES.

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 December 31, 2010, 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 quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Internal Control Over Financial Reporting

Inherent Limitations Over Internal Controls

The Company’s internal control over financial reporting is designed 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. The Company’s internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that the Company’s receipts and expenditures are being made only in accordance with authorizations of the Company’s management and governors; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Management, including the Company’s Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system 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 all control systems, no evaluation of internal controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Also, any evaluation of the effectiveness of controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Annual 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. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.

This annual 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 annual report.

ITEM 9B. OTHER INFORMATION.

None.

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 2011 Annual Meeting of Members to be filed with the Securities and Exchange Commission within 120 days of our 2010 fiscal year end. This proxy statement is referred to in this report as the 2011 Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION.

The Information required by this Item is incorporated by reference to the 2011 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 2011 Proxy Statement.

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

The Information required by this Item is incorporated by reference to the 2011 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The Information required by this Item is incorporated by reference to the 2011 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 33 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

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.

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.

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.

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.	X

10.55	Revolving Promissory Note between First National Bank of Omaha and Red Trail Energy, LLC dated November 15, 2010.	X

10.56	Letter Agreement between Greenway Consulting, LLC and Red Trail Energy, LLC dated January 13, 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

(+) Confidential Treatment Requested.

SIGNATURES

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

		RED TRAIL ENERGY, LLC

Date:	March 31, 2011	/s/ Gerald Bachmeier
		Gerald Bachmeier
		Chief Executive Officer and President (Principal Executive Officer)

Date:	March 31, 2011	/s/ Kent Anderson
		Kent Anderson
		Chief Financial Officer and Treasurer (Principal Financial Officer)

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:	March 31, 2011	/s/ Gerald Bachmeier
		Gerald Bachmeier, Chief Executive Officer and President
		(Principal Executive Officer)

Date:	March 31, 2011	/s/ Kent Anderson
		Kent Anderson, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

Date:	March 31, 2011	/s/ Mike Appert
		Mike Appert, Chairman and Governor

Date:	March 31, 2011	/s/ Tim Meuchel
		Tim Meuchel, Vice Chairman and Governor

Date:	March 31, 2011	/s/ Jody Hoff
		Jody Hoff, Secretary and Governor

Date:	March 31, 2011	/s/ Ron Aberle
		Ron Aberle, Governor

Date:	March 31, 2011	/s/ Frank Kirschenheiter
		Frank Kirschenheiter, Governor

Date:	March 31, 2011	/s/ Sid Mauch
		Sid Mauch, Governor

Date:	March 31, 2011	/s/ William A. Price
		William A. Price, Governor

RED TRAIL ENERGY, LLC - FORM 10-K - March 31, 2011

Attached files

RED TRAIL ENERGY, LLC Reports