UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

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

ONE EARTH ENERGY, LLC

(Exact name of registrant as specified in its charter)

Illinois		20-3852246
(State or other jurisdiction of		(I.R.S. Employer Identification No.)
incorporation or organization)
202 N. Jordan Drive, Gibson City, IL		60936
(Address of principal executive offices)		(Zip Code)

(217) 784-5321
(Registrant’s telephone number, including area code)

Securities registered under Section 12(b) of the Exchange Act:

Securities registered under Section 12(g) of the Exchange Act:

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

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

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

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller Reporting Company o
				(Do not check if a smaller reporting company)

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

As of June 30, 2010, the aggregate market value of the membership units held by non-affiliates (computed by reference to the issuer’s offering price of such membership units in its initial public offering, as no current market exists for such membership units) was $16,905,000.

As of March 31, 2011, there were 13,781 membership units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 

INDEX

		Page
PART I			4
ITEM 1. BUSINESS			4
ITEM 1A. RISK FACTORS			13
ITEM 1B. UNRESOLVED STAFF COMMENTS			19
ITEM 2. PROPERTIES			19
ITEM 3. LEGAL PROCEEDINGS			19
ITEM 4. REMOVED AND RESERVED			19
PART II			20
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			20
ITEM 6. SELECTED FINANCIAL DATA			20
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			22
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			35
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			49
ITEM 9A. CONTROLS AND PROCEDURES			49
ITEM 9B. OTHER INFORMATION			50
PART III			50
ITEM 10. DIRECTORS; EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			50
ITEM 11. EXECUTIVE COMPENSATION			53
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED MEMBER MATTERS			56
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE			57
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			59
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			60
SIGNATURES			64
Exhibit 10.43
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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 upon 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:

•		Changes in the availability and price of corn and natural gas;
•		Our inability to secure credit we may require to continue our operations;
•		Decreases in the market prices of ethanol and distillers grains;
•		Ethanol supply exceeding demand; and corresponding ethanol price reductions;
•		Changes in the environmental regulations that apply to our plant operations;
•		Changes in our business strategy, capital improvements or development plans;
•		Changes in plant production capacity or technical difficulties in operating the plant;
•		Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agriculture, oil or automobile industries;
•		Lack of transport, storage and blending infrastructure preventing ethanol from reaching high demand markets;
•		Changes in federal and/or state laws (including the elimination of any federal and/or state ethanol tax incentives);
•		Changes and advances in ethanol production technology;
•		Additional ethanol plants built in close proximity to our ethanol facility;
•		Competition from alternative fuel additives;
•		Changes in interest rates and lending conditions;
•		Our ability to generate free cash flow to invest in our business and service our debt;
•		Our ability to retain key employees and maintain labor relations; and
•		Volatile commodity and financial markets.

The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, 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

Our website address is www.oneearthenergy.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), are available, free of charge, on our website under the link “SEC Filings,” as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, 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

Business Development

One Earth Energy, LLC is an Illinois limited liability company organized on November 28, 2005, for the purpose of raising capital to develop, construct, own and operate a 100 million gallon per year ethanol plant in east central Illinois near Gibson City, Illinois. References to “we,” “us,” “our,” “One Earth” and the “Company” refer to One Earth Energy, LLC. Since June 24, 2009, we have been engaged in the production of ethanol and distillers grains at the plant.

We are subject to industry-wide factors that affect our operating and financial performance. These factors include, but are not limited to the available supply and cost of corn from which our ethanol and distillers grains are processed; the cost of natural gas, which we use in the production process; dependence on our distillers grains marketer to market and distribute our products; the competitive nature of the ethanol industry; possible legislation at the federal, state and/or local level; changes in federal ethanol tax incentives and the cost of complying with extensive environmental laws that regulate our industry.

We expect our ethanol plant to produce approximately 2.8 gallons of ethanol for each bushel of corn processed in the production cycle. We refer to the difference between the price per gallon of ethanol and the price per bushel of corn (divided by 2.8) as the “crush spread.” Should the crush spread decline, it is possible that our ethanol plant will generate operating results that do not provide adequate cash flows for sustained periods of time. In such cases, production at the ethanol plant may be reduced or stopped altogether in order to minimize variable costs at the plant.

We attempt to manage the risk related to the volatility of corn and ethanol prices by utilizing forward corn purchase and forward ethanol and distillers grain sale contracts. We attempt to match quantities of ethanol and distillers grains sale contracts with an appropriate quantity of corn purchase contracts over a given period of time when we can obtain an adequate gross margin resulting from the crush spread inherent in the contracts we have executed. However, the market for future ethanol sales contracts is not a mature market. Consequently, we generally execute contracts for no more than three months into the future at any given time. As a result of the relatively short period of time our contracts cover, we generally cannot predict the future movements in the crush spread for more than three months; thus, we are unable to predict the likelihood or amounts of future income or loss from our ethanol plant.

The crush spread realized in 2010 was subject to significant volatility. For calendar year 2010, the average Chicago Board of Trade (“CBOT”) near-month corn price was approximately $4.30 per bushel, with highs reaching over $7.00 per bushel in December 2010. We believe corn prices were affected late in the year by global weather conditions, export demand, speculation, currency valuation and global economic conditions. Ethanol prices also had significant fluctuations ranging from approximately $1.50 per gallon in June to approximately $2.38 per gallon in December. Ethanol and corn prices have tended to trade in the same direction but with narrowing spreads, particularly late in the year. In 2010, the CBOT crush spread ranged from a low of approximately $0.05 per gallon in December to a high of approximately $0.55 per gallon in June. We believe ethanol demand late in 2010 was also impacted by the uncertainty of the extension of the VEETC Blender Credit. Crush spreads have continued to decline in 2011 and have at times, become negative (absent the consideration of distillers grains). Prices for distillers grains we sell have generally trended with grain prices. In addition, these prices have partially offset the decline in the crush spread.

The crush spread realized in 2009 was subject to significant volatility. For example, for calendar year 2009, the average Chicago Board of Trade (“CBOT”) near-month corn price was approximately $3.74 per bushel, with highs reaching nearly $4.20 per bushel and retreating to approximately $3.20 per bushel in the fall. Ethanol prices were generally in a range of approximately $1.50 to $1.70 per gallon for most of the year. Ethanol prices increased during the last three months of 2009 reaching as high as $2.00 per gallon. We believe this market volatility with respect to the crush spread was attributable to a number of factors, including but not limited to export demand, speculation, currency valuation, global economic conditions, ethanol demand and current production concerns. In 2009, the CBOT crush spread ranged from approximately $0.19 to $0.63 per gallon of ethanol.

Principal Products and Markets

The principal products we are producing at the plant are fuel-grade ethanol and distillers grains. Raw carbon dioxide gas is another co-product of the ethanol production process. We have no current agreement to capture or market carbon dioxide gas, and are not exploring any options at this time.

Ethanol

Our primary product is ethanol. Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains. According to the Renewable Fuels Association, approximately 85 percent of ethanol in the United States today is produced from corn, and approximately 90 percent of ethanol is produced from a corn and other input mix. The ethanol we produce is manufactured from corn. Although the ethanol industry continues to explore production technologies employing various feedstocks, such as biomass, corn-based production technologies remain the most practical and provide the lowest operating risks. Corn produces large quantities of carbohydrates, which convert into glucose more easily than most other kinds of biomass. The Renewable Fuels Association estimates current domestic annual ethanol production for operating refineries at approximately 13.67 billion gallons as of March 15, 2011.

An ethanol plant is essentially a fermentation plant. Ground corn and water are mixed with enzymes and yeast to produce a substance called “beer,” which contains about 10% alcohol and 90% water. The “beer” is boiled to separate the water, resulting in ethyl alcohol, which is then dehydrated to increase the alcohol content. This product is then mixed with a certified denaturant to make the product unfit for human consumption and commercially saleable.

Ethanol can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide emissions; and (iii) a non-petroleum-based gasoline substitute. Approximately 95% of all ethanol is used in its primary form for blending with unleaded gasoline and other fuel products. Used as a fuel oxygenate, ethanol provides a means to control carbon monoxide emissions in large metropolitan areas. The principal purchasers of ethanol are generally the wholesale gasoline marketer or blender. The principal markets for our ethanol are petroleum terminals in the southeastern and northeastern United States.

Approximately 83% and 85% of our revenue was derived from the sale of ethanol during our fiscal years ended December 31, 2010 and 2009, respectively.

Distillers Grains

The principal co-product of the ethanol production process is distillers grains, a high protein, high-energy animal feed supplement primarily marketed to the dairy, beef, poultry and swine industries. 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. Dry mill ethanol processing creates three forms of distiller grains: Distillers Wet Grains with Solubles (“DWS”), Distillers Modified Wet Grains with Solubles (“DMWS”) and Distillers Dried Grains with Solubles (“DDGS”). DWS is processed corn mash that contains approximately 70% moisture. DWS has a shelf life of approximately three days and can be sold only to farms within the immediate vicinity of an ethanol plant. DMWS is DWS that has been dried to approximately 50% moisture. DMWS have a slightly longer shelf life of approximately ten days and are often sold to nearby markets. DDGS is DWS that has been dried to 10% to 12% moisture. DDGS has an almost indefinite shelf life and may be sold and shipped to any market regardless of its vicinity to an ethanol plant.

Approximately 17% and 15% of our revenue was derived from the sale of distillers grains during our fiscal years ended December 31, 2010 and 2009, respectively.

Ethanol and Distillers Grains Markets

As described below in “Distribution of Principal Products,” we market our ethanol in-house, and distillers grains through a third party. Whether or not distillers grains produced by our ethanol plant are sold in local markets will depend on decisions made in cooperation with our marketer. Local ethanol markets will be limited and must be evaluated on a case-by-case basis. Although local markets will be the easiest to service, they may be oversold. Oversold markets depress ethanol prices.

Our regional market is within a 450-mile radius of our plant and is serviced by rail. We are connected to a short-line railroad that is connected to a Class I railroad, so that we may reach regional and national markets with our products. Because ethanol use results in less air pollution than regular gasoline, regional markets typically include large cities that are subject to anti-smog measures such as either carbon monoxide or ozone non-attainment areas (e.g., Atlanta, Birmingham, Baton Rouge and Washington D.C.).

While we believe that the nationally mandated usage of renewable fuels is currently driving demand, we believe that an increase in voluntary usage will be necessary for the industry to continue its growth trend. In addition, a higher renewable fuels standard (RFS) may be necessary to encourage use by blenders. We expect that voluntary usage by blenders will occur only if the price of ethanol makes increased blending economical. In addition, we believe that heightened consumer awareness and consumer demand for ethanol-blended gasoline may play an important role in growing overall ethanol demand and voluntary usage by blenders. If blenders do not voluntarily increase the amount of ethanol blended into gasoline and consumer awareness does not increase, it is possible that additional ethanol supply will outpace demand and further depress ethanol prices.

Distribution of Principal Products

Our ethanol plant is located near Gibson City, Illinois in Ford County. We selected the site because of its location which is close to an abundant supply of corn and accessibility to road and rail transportation. Our site is in close proximity to rail and a major highway that is connected to Chicago, Illinois.

Ethanol Distribution

We have entered into a non-exclusive marketing agreement with Lansing Ethanol Services, LLC, (“Lansing”) whereby Lansing will, from time to time, purchase ethanol from One Earth for a merchandising fee per gallon of ethanol delivered. The term of the agreement is from June 5, 2009 until December 1, 2012. It will automatically renew for additional periods of one year after the last day of the initial term, and after each renewal term, unless either party sends a written notice of termination to the other. Effective December 1, 2010, the agreement was amended by deleting the per gallon merchandising fee.

Distillers Grains Distribution

We have entered into a marketing agreement with United Bio Energy Ingredients, LLC (“UBEI”). Under the terms of the agreement, UBEI will purchase all of our distillers grains production during the term of the contract. The initial term of the agreement is for 36 months, commencing on the date that our ethanol plant began operations to produce ethanol. The agreement will automatically renew for successive one year terms thereafter unless either party gives written notice of its election not to renew. Pursuant to the agreement, UBEI will provide comprehensive co-products marketing services to us including an onsite merchandiser. However, it was found that the onsite merchandiser arrangement would be better served by allowing the UBEI merchandiser to work from the UBEI offices, and UBEI would reimburse One Earth monthly as a credit. UBEI will pay us for all distillers grains removed by them from our plant as follows: for dried distillers grains, a price equal to a percentage of the F.O.B. facility price charged by UBEI to its customers; for wet distillers grains, a price equal to a percentage of the F.O.B. Facility Price charged by UBEI to its customers; for modified wet distillers grains, a price equal to a percentage of the F.O.B. Facility Price charged by UBEI to its customers. Such percentages are subject to a minimum and maximum price per ton as set forth in the agreement. On December 6, 2010, we amended the agreement, which was effective with shipments on the first day of January 2011. The amendment reduces the price UBEI will pay to One Earth for all DDGS shipped to its customers, with upper and lower limits. UBEI shall no longer give One Earth the monthly credit, and UBEI shall not be required to locate a merchandiser at One Earth’s facility. The termination date was extended to July 1, 2014.

Federal Ethanol Supports and Governmental Regulation

Federal Ethanol Supports

The overall effect of the renewable fuel standard (“RFS”) program contained in the Energy Independence and Security Act signed into law on December 19, 2007 (the “2007 Act”) is uncertain. The mandated minimum level of use of renewable fuels in the RFS under the 2007 Act increased to 10-11 billion gallons per year in 2009 (from 5.4 billion gallons under the RFS enacted in 2005), and is scheduled to increase to 36 billion gallons per year in 2022. However, the 2007 Act also requires the increased use of “advanced” biofuels, which are alternative biofuels produced without using corn starch such as cellulosic ethanol and biomass-based diesel, with 21 billion gallons of the mandated 36 billion gallons of renewable fuel required to come from advanced biofuels by 2022, which essentially caps the annual corn based ethanol volume at 15 billion gallons. Required RFS volumes for both general and advanced renewable fuels in years to follow 2022 will be determined by a governmental administrator, in coordination with the U.S. Department of Energy and U.S. Department of Agriculture. The scheduled RFS for 2011 is approximately 12.6 billion gallons.

																		Undiffer-
														Biomass-				entiated
		Renewable				Advanced				Cellulosic				based				Advanced
Year		Biofuel				Biofuel				Biofuel				Diesel				Biofuel				Total RFS
2008			9.0																				9.0
2009			10.5				.6								.5				0.1				11.1
2010			12				.95				.1				.65				0.2				12.95
2011			12.6				1.35				.25				.8				0.3				13.95
2012			13.2				2				.5				1				0.5				15.2
2013			13.8				2.75				1								1.75				16.55
2014			14.4				3.75				1.75								2				18.15
2015			15				5.5				3								2.5				20.5
2016			15				7.25				4.25								3.0				22.25
2017			15				9				5.5								3.5				24
2018			15				11				7								4.0				26
2019			15				13				8.5								4.5				28
2020			15				15				10.5								4.5				30
2021			15				18				13.5								4.5				33
2022			15				21				16								5				36

Source: Renewable Fuels Association

Waivers of the RFS minimum levels of renewable fuels included in gasoline could have a material adverse effect on our results of operations. Under the RFS, as originally passed as part of the Energy Policy Act of 2005, the U.S. Environmental Protection Agency, or EPA, in consultation with the Secretary of Agriculture and the Secretary of Energy, may waive the renewable fuels mandate with respect to one or more states if the Administrator of the EPA determines upon the petition of one or more states that implementing the requirements would severely harm the economy or the environment of a state, a region or the nation, or that there is inadequate supply to meet the requirement.

On June 18, 2008, the United States Congress overrode a presidential veto to approve the Food, Conservation and Energy Act of 2008 (the “2008 Farm Bill”) and to ensure that all parts of the 2008 Farm Bill are enacted into law. Passage of the 2008 Farm Bill reauthorized the 2002 farm bill and added new provisions regarding energy, conservation, rural development, crop insurance as well as other subjects. The energy title continues the energy programs contained in the 2002 farm bill but refocuses certain provisions on the development of cellulosic ethanol technology. The legislation provided assistance for the production, storage and transport of cellulosic feedstocks and provides support for ethanol production from such feedstocks in the form of grants, loans and loan guarantees. The 2008 Farm Bill also modified the ethanol fuels tax credit from 51 cents per gallon to 45 cents per gallon since 2009. The 2008 Farm Bill is distinct from the Energy Independence and Security Act of 2007, which contains the renewable fuels standards described above.

The Energy Independence and Security Act of 2007 and the 2008 Farm Bill offer a very strong incentive to develop commercial scale cellulosic ethanol. The RFS requires that 16 billion gallons per year of cellulosic bio-fuels 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.

There is currently some debate in the U.S. Senate about whether to repeal the 54 cent per gallon tariff on imported ethanol. In December 2010, the tariff was extended to the end of 2011. If the 54 cent per gallon tariff is allowed to expire at the end of 2011, the demand for domestically produced ethanol may be offset by the supply of ethanol imported from Brazil or other foreign countries.

Effect of Governmental Regulation

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

We are subject to various federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of employees. In addition, some of these laws and regulations require our plant to operate under permits that are subject to renewal or modification.

The government’s regulation of the environment changes constantly. We are subject to extensive air, water and other environmental regulations and we are required to obtain a number of environmental permits to 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. For example, changes in the environmental regulations regarding the required oxygen content of automobile emissions could have an adverse effect on the ethanol industry. Furthermore, plant operations likely will be governed by the Occupational Safety and Health Administration (“OSHA”). OSHA regulations may change such that the costs of the operation of the plant may increase. Any of these regulatory factors may result in higher costs or other materially adverse conditions effecting our operations, cash flows and financial performance.

Competition

We are in direct competition with numerous ethanol producers, many of whom have greater resources than we do. Following the significant growth in the ethanol industry during 2005 and 2006, the industry has grown at a much slower pace. Management attributes the rapid growth during 2005 and 2006 with a very favorable spread between the price of ethanol and the cost of the raw materials to produce ethanol during that time period. Management believes that currently ethanol supply capacity exceeds ethanol demand. This has resulted in some ethanol producers reducing production of ethanol or ceasing operations altogether. As of March 15, 2011, the Renewable Fuels Association estimates that approximately 3% of the ethanol production capacity in the United States is currently idled. This is down from earlier in 2009 when the idled capacity may have been as high as 20%. As a result of this overcapacity, the ethanol industry has become increasingly competitive. Since ethanol is a commodity product, competition in the industry is predominantly based on price. Larger ethanol producers may be able to realize economies of scale that we are unable to realize. This could put us at a competitive disadvantage to other ethanol producers. Management anticipates that without an increase in the amount of ethanol that can be blended into gasoline for use in conventional automobiles, ethanol demand may not significantly increase which may result in ethanol supply capacity exceeding ethanol demand for the foreseeable future.

Many of the current ethanol production incentives are designed to encourage the production of renewable fuels using raw materials other than corn. One type of ethanol production feedstock that is being explored is cellulose. Cellulose is the main component of plant cell walls and is the most common organic compound on earth. Cellulose is found in wood chips, corn stalks, rice, straw, amongst other common plants. Cellulosic ethanol is ethanol produced from cellulose. Currently, cellulosic ethanol production technology is not sufficiently advanced to produce cellulosic ethanol on a commercial scale, however, due to these new government incentives, we anticipate that commercially viable cellulosic ethanol technology will be developed in the near future. Several companies and researchers have commenced pilot projects to study the feasibility of commercially producing cellulosic ethanol. If this technology can be profitably employed on a commercial scale, it could potentially lead to ethanol that is less expensive to produce than corn based ethanol, especially if corn prices remain high. Cellulosic ethanol may also capture more government subsidies and assistance than corn based ethanol. This could decrease demand for our product or result in competitive disadvantages for our ethanol production process.

According to the Renewable Fuels Association, as of March 15, 2011, the most recent data available, the ethanol industry has grown to 204 production facilities in the United States. There are eleven plants currently under construction or expansion. The Renewable Fuels Association currently estimates that the United States ethanol industry has capacity to produce more than 14.14 billion gallons of ethanol per year. The new ethanol plants under construction along with the plant expansions under construction could push United States production of fuel ethanol in the near future to more than 14.66 billion gallons per year. The largest ethanol producers include Archer Daniels Midland, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, each of which is capable of producing more ethanol than we produce.

Ethanol production is also expanding internationally. Ethanol produced or processed in certain countries in Central America and the Caribbean region is eligible for tariff reduction or elimination on importation to the United States under a program known as the Caribbean Basin Initiative. Some ethanol producers, including Cargill, have started taking advantage of this situation by building dehydration plants in participating Caribbean Basin countries, which convert ethanol into fuel-grade ethanol for shipment to the United States. Ethanol imported from Caribbean Basin countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably. Further, despite the fact that there is a significant amount of ethanol produced in the United States, ethanol produced abroad and shipped by sea may be a more favorable alternative to supply coastal cities that are located on international shipping ports.

Our ethanol plant also competes with producers of other gasoline additives having similar octane and oxygenate values as ethanol. Alternative fuels, gasoline oxygenates and alternative ethanol production methods are also continually under development. The major oil companies have significantly greater resources than we have to market other additives, to develop alternative products, and to influence legislation and public perception of ethanol. These companies also have sufficient resources to begin production of ethanol should they choose to do so.

A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells, plug-in hybrids or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological 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 the fuel cell industry continues to expand and gain broad acceptance and becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would negatively impact our profitability.

Demand for ethanol may increase as a result of increased consumption of E85 fuel. E85 fuel is a blend of 85% ethanol and 15% gasoline. The number of retail E85 suppliers increases significantly each year, however, this remains a relatively small percentage of the total number of U.S. retail gasoline stations. In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it. As public awareness of ethanol and E85 increases along with E85’s increased availability, management anticipates some growth in demand for ethanol associated with increased E85 consumption.

Many in the ethanol industry believe that while in the future higher percentage blends of ethanol such as E85 for use in flexible fuel vehicles will positively impact demand for ethanol, in the near term increasing the amount of ethanol that can be blended for use in conventional automobiles will have a greater effect on ethanol demand. In October of 2010, the Environmental Protection Agency approved the use of 15% ethanol (from 10%) for cars and light duty trucks in 2007 and later models. In January 2011, the EPA added cars, pickups, and SUVs made in 2001 through 2006 to the list of vehicles that are approved to use E15. Management believes that this could increase annual ethanol demand by as much as 7 billion gallons per year.

Distillers Grains Competition

Ethanol plants in the Midwest produce the majority of distillers grains and primarily compete with other ethanol producers in the production and sales of distillers grains. According to the Renewable Fuels Association’s Ethanol Industry Outlook 2011, ethanol plants produced nearly 32.5 million metric tons of distillers grains in 2010, and estimates 25 million metric tons were produced in 2008/2009. The amount of distillers grains produced is expected to increase significantly as the number of ethanol plants increases.

The primary consumers of distillers grains are dairy and beef cattle, according to the Renewable Fuels Association’s Ethanol Industry Outlook 2011. In recent years, an increasing amount of distillers grains have been used in the swine and poultry markets. Numerous feeding trials show advantages in milk production, growth, rumen health, and palatability over other dairy cattle feeds. With the advancement of research into the feeding rations of poultry and swine, we expect these markets to expand and create additional demand for distillers grains; however, no assurance can be given that these markets will in fact expand, or if they do, that we will benefit from it. The market for distillers grains is generally confined to locations where freight costs allow it to be competitively priced against other feed ingredients. Distillers grains compete with three other feed formulations: corn gluten feed, dry brewers grain and mill feeds. The primary value of these products as animal feed is their protein content. Dry brewers grain and distillers grains have about the same protein content, and corn gluten feed and mill feeds have slightly lower protein contents.

Sources and Availability of Raw Materials

Corn Feedstock Supply

The major raw material required for our ethanol plant to produce ethanol and distillers grain is corn. To produce 100 million gallons of ethanol per year, our ethanol plant needs approximately 36 million bushels of corn per year, or approximately 100,000 bushels per day, as the feedstock for its dry milling process. We primarily purchase the corn supply for our plant from local markets, but may be required to purchase some of the corn we need from other markets and transport it to our plant via truck or rail in the future. Traditionally, corn grown in the area of the plant site has been exported for feeding or processing and/or overseas export sales.

We have entered into a Grain Handling Agreement with Alliance Grain Co. (“Alliance”). The purpose of the agreement is to set out the terms upon which Alliance has agreed to serve as our exclusive third-party agent to procure corn to be used as feedstock at our ethanol production facility. Pursuant to the agreement, Alliance provides one grain originator to work at the facility to negotiate and execute contracts on our behalf and arrange the shipping and delivery of the corn required for ethanol production. The initial term of the agreement is for two years from the first grind date, to automatically renew for one additional year unless properly terminated by either of the parties. The parties also each have the right to terminate the agreement in certain circumstances, including, but not limited to, default of either party by, bankruptcy or receivership of, the other party, or mutual agreement to terminate the agreement.

We are significantly dependent on the availability and price of corn. The price at which we purchase corn will depend on prevailing market prices. There is no assurance that a shortage will not develop, particularly if there are other ethanol plants competing for corn or an extended drought or other production problem. We anticipate that corn prices will continue to be extremely volatile.

On March 10, 2011, the United States Department of Agriculture (“USDA”) released its Crop Production report, which estimated the 2010 grain corn crop at 12.45 billion bushels. The March 10, 2011 estimate of the 2010 corn crop was approximately 4% lower than the USDA’s estimate of the 2009 corn crop of 12.9 billion bushels. Corn prices have come down from their historical highs of 2008, but as previously idled plants came online in 2009 and 2010, and due to lower production estimates, corn prices have increased sharply towards the end of 2010, and into 2011. Because of this condition, our crush spreads declined towards the end of 2010 and into 2011.

The price and availability of corn are subject to significant fluctuations depending upon a number of factors affecting grain commodity prices in general, including crop conditions, weather, governmental programs and foreign purchases. Because the market price of ethanol is not directly related to grain prices, ethanol producers are generally not able to compensate for increases in the cost of grain feedstock through adjustments in prices charged for their ethanol. We therefore anticipate that our plant’s profitability will be negatively impacted during periods of high grain prices.

Utilities

We engaged U.S. Energy Services, Inc. to assist us in negotiating our utilities contracts and to provide us with on-going energy management services. U.S. Energy manages the procurement and delivery of energy to their clients’ locations. U.S. Energy Services manages energy costs through obtaining, organizing and tracking cost information. Their major services include supply management, price risk management and plant site development. The agreement continued twelve (12) months after the plant’s completion date of June 2009. The agreement is month to month thereafter.

Natural Gas. Natural gas is also an important input commodity to our manufacturing process. Our natural gas usage for our fiscal year ended December 31, 2010 was 3,064,373 MMBTU, constituting approximately 7.3% of our total costs of goods sold. We are using natural gas to produce process steam and to dry our distillers grain products to a moisture content at which they can be stored for long periods of time, and can be transported greater distances, so that we can market the product to overseas markets.

We entered into an agreement with Ameren Energy Generating Company (“Ameren”) on December 9, 2008, whereby we would receive an undivided 10% interest in a lateral natural gas pipeline owned by Ameren which is connected to the interstate natural gas pipeline system owned and operated by Natural Gas Pipeline of America. The term of the assignment is for 10 years, and the contract price, is $4,380,000, paid over 120 months, with payments of $36,500 each, with the initial payment made on February 1, 2009. Upon expiration of the agreement on January 31, 2019, the property will revert back to Ameren. However, prior to the expiration of the initial seven years of the term, Ameren will provide notice to us regarding their willingness to renew the agreement after the final expiration. We will be allowed to install an additional pipeline contiguous to Ameren’s existing pipeline, subject to certain easements and final approval by Ameren.

Electricity. We require a significant amount of electrical power to operate the plant. On January 18, 2008, we entered into an agreement with AmerenCIPS for the construction of a substation and ancillary equipment necessary to provide electric distribution service. The entire cost of the construction was $1,394,000, of which $1,150,000 was required at the signing of the agreement. The remaining balance is to be paid in 36 equal payments of no less than $6,800, which will be included in the monthly invoice from AmerenCIPS as delivery service. The remaining balance is secured by an irrevocable standby letter of credit, which may be reduced annually by the actual or calculated delivery service revenues.

Water. We require a significant supply of water. We obtain water from the Mahomet Aquifer through our two wells located approximately 13 miles east of the plant.

Much of the water used in our ethanol plant is recycled back into the process. There are, however, certain areas of production where fresh water is needed. Those areas include boiler makeup water and cooling tower water. Boiler makeup water is treated on-site to minimize all elements that will harm the boiler and recycled water cannot be used for this process. Cooling tower water is deemed non-contact water because it does not come in contact with the mash, and, therefore, can be regenerated back into the cooling tower process. The makeup water requirements for the cooling tower are primarily a result of evaporation. Much of the water can be recycled back into the process, which minimizes the discharge water. Many new plants today are zero or near zero effluent discharge facilities. Due to the boron level in our discharge water, we are required by the EPA to dilute the discharge with water pumped from wells located on the plant site.

Employees

We currently have 50 full-time employees. We consider our relationship with our employees to be good.

Research and Development

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

Patents, Trademarks, Licenses, Franchises and Concessions

We do not currently hold any patents, trademarks, franchises or concessions. We were granted a license by ICM, Inc. (“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, Inc. (“Fagen”) to design and build our ethanol plant.

Working Capital

We primarily use our working capital for purchases of raw materials necessary to operate the ethanol plant. Our primary source of working capital has been cash flows from our operations along with our two revolving lines of credit with our primary lender First National Bank of Omaha. One line of credit is part of the $100,000,000 loan facility. The amount available under this loan is reduced by $250,000 quarterly. At December 31, 2010 and 2009, we had $8,750,000 and $10,000,000, respectively, available on this revolving line of credit. The other line of credit is in addition to the $100,000,000 loan facility, and we may draw up to $10,000,000 or 75% of our borrowing base at any time. At December 31, 2010 and 2009, we had $10,000,000 available on this revolving line of credit. We have no outstanding drawings as of December 31, 2010 and 2009 on either line of credit. We had issued letters of credit that total approximately $280,000 and $543,000 as of December 31, 2010 and 2009 respectively.

Dependence on Major Customers and Suppliers

As discussed above, we have entered into a marketing agreement with United Bio Energy for the purpose of marketing and distributing our distillers grains. We rely on United Bio Energy for the sale and distribution of our distillers grains. Therefore, although there are other marketers in the industry, we are highly dependent on United Bio Energy for the successful marketing of our product. Any loss of United Bio Energy as our marketing agent for our distillers grains could have a significant negative impact on our revenues.

In addition, we rely on Alliance Grain for the acquisition of all of our corn for production. As such, we are highly dependent upon Alliance Grain for the production of our ethanol. In the event Alliance Grain could not provide us with adequate supplies of corn, or terminated its relationship with us, this could have a significant negative impact on our revenues, especially until we were able to establish procedures to acquire corn in-house or through another entity.

Costs and Effects of Compliance with Environmental Laws

We are subject to extensive air, water and other environmental regulations and we require a number of environmental permits to operate the plant. Fagen and RTP Environmental Engineering Associates, Inc. advise us on general environmental compliance.

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

You should carefully read and consider the risks and uncertainties below and the other information contained in this report. Any of the events discussed in the risk factors below may occur. If one or more of these events does occur, our results of operations, financial condition or cash flows could be materially adversely affected.

Risks Relating to Our Business

We have a significant amount of debt, and our existing debt financing agreements contain, and our future debt financing agreements may contain, restrictive covenants that limit distributions and impose restrictions on the operation of our business. The use of debt financing makes it more difficult for us to operate because we must make principal and interest payments on the indebtedness and abide by covenants contained in our debt financing agreements. The level of our debt may have important implications on our operations, including, among other things: (a) limiting our ability to obtain additional debt or equity financing; (b) placing us at a competitive disadvantage because we may be more leveraged than some of our competitors; (c) subjecting all or substantially all of our assets to liens, which means that there may be no assets left for unit holders in the event of a liquidation; and (d) limiting our ability to make business and operational decisions regarding our business, including, among other things, limiting our ability to pay distributions to our unit holders, make capital improvements, sell or purchase assets or engage in transactions we deem to be appropriate and in our best interest.

Increases in the price of corn or natural gas would reduce our profitability. Our primary source of revenue is from the sale of ethanol and distillers grains. Our results of operations and financial condition are significantly affected by the cost and supply of corn and natural gas. Changes in the price and supply of corn and natural gas 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 will produce lower profit margins and, therefore, negatively affect our financial performance. While corn prices have decreased from highs experienced during the middle of 2008 into the middle of 2010, corn prices could significantly increase 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 natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices as a result of colder than average weather conditions or natural disasters, overall economic conditions and foreign and domestic governmental regulations and relations. Significant disruptions in the supply of natural gas could impair our ability to manufacture ethanol and more significantly, distillers grains for our customers. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to 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 natural gas costs compared to the selling prices of our products for an extended period of time, our financial performance may be negatively affected.

Declines in the price of ethanol or distillers grain 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 natural gas 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 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 negatively affect our financial performance.

We may violate the terms of our credit agreements and financial covenants which could result in our lender demanding immediate repayment of our loans. Unforeseen circumstances may develop which could result in us violating our loan covenants. If we violate the terms of our credit agreement, our primary lender could deem us in default of our loans and require us to immediately repay the entire outstanding balance of our loans. If we do not have the funds available to repay the loans, or we cannot find another source of financing, or we cannot seek relief from our primary lender with respect to any defaults, our financial performance could be negatively affected.

Our inability to secure credit facilities we may require in the future may negatively impact our liquidity. Due to current conditions in the credit markets, it has been difficult for businesses to secure financing. If we require financing in the future and we are unable to secure such financing, or we are unable to secure the financing we require on reasonable terms, it may have a negative impact on our liquidity.

The ethanol industry is an industry that 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 nearly 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 negatively affect our financial performance.

We engage in transactions which involve risks that could harm our business. Exposure to commodity price risk results from our dependence on corn and natural gas in the ethanol production process. We seek to minimize the risks from fluctuations in the prices of corn, natural gas and ethanol by establishing a “crush margin,” which is the difference between the ethanol net price and the corn price per gallon of ethanol. Then we contract the sale of ethanol and the purchase of corn simultaneously that will generate the targeted crush margin. Corn and ethanol prices may not trend in the same direction, which will make it difficult for us to achieve the crush margin required to generate profits.

Price movements in corn, natural gas 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 strategy is impacted by price fluctuations in the cost of corn or natural gas. However, it is likely that commodity cash prices will have the greatest impact on our strategy.

We are currently conducting an odd-lot tender offer to purchase units from some of our smaller unitholders, with the intended end result for us to be eligible to suspend our reporting requirements with the Securities and Exchange Commission, which may not occur and if it occurs will result in less public information being available about the Company. Our offer to purchase units from some of our smaller unitholders will expire April 1, 2011. We have expended time and resources on this offer with the intent that at the conclusion of the offer, we will have less than 300 members of record and will therefore be eligible to again suspend our reporting requirements with the Securities and Exchange Commission. At this time, it is uncertain whether a sufficient number of eligible unitholders will accept the offer in order for us to suspend our reporting requirements. If we do not have less than 300 members of record at the conclusion of the offering, we will likely explore other possible avenues to achieve this result, but we will have to continue to incur the expenses of reporting with the Securities and Exchange Commission until we are able to do so. If we do have less than 300 members of record at the conclusion of the offering, we will suspend our reporting obligations and less information about the Company will be readily available to you.

Our business is not diversified. Our success depends largely 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 or distillers grains, we have no other line of business to fall back on. Our business could 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 officers and key employees may prevent us from operating the ethanol plant profitably and could decrease the value of our units.

We depend on key suppliers and marketers, such as UBE and Alliance Grain, whose failure to perform could force us to abandon business, hinder our ability to operate profitably or decrease the value of our units. We are highly dependent upon UBE to market our products and Alliance Grain to procure our corn for production. Should either UBE or Alliance Grain fail to perform in any manner significant to our operations, we may encounter unforeseen costs or difficulties in the operation of our plant which could affect our profitability negatively.

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 to. 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.

Your investment may decline in value due to decisions made by our board of directors, and you will not have the ability to remove or replace our directors. Under our operating agreement, directors are all appointed by REX American Resources Corporation (“REX”) and other members, however, most members do not have the right to appoint a director and no directors are elected. The appointed directors serve at the option of the members with such appointment rights, and our other members have no right to remove or replace any directors. As a result, your only recourse to replace a director would be through an amendment to our operating agreement, which could be difficult to accomplish. Only members that own at least thirty percent (30%) of our membership voting interests may propose an amendment to our operating agreement, and such proposed amendments must also be approved by REX and the affirmative vote of the majority of the membership voting interests present at a meeting where a quorum is in attendance. Therefore, if the board of directors were to make a decision that would decrease the value of your units, you would have very little ability to change this outcome.

Risks Related to Ethanol Industry

Demand for ethanol may not continue to grow unless ethanol can be blended into gasoline in higher percentage blends for conventional automobiles. Currently, ethanol is blended with conventional gasoline for use in standard (non-flex fuel) vehicles to create a blend which is 10% ethanol and 90% conventional 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 “blending 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 currently on the edge of reaching this blending wall. In order to expand demand for ethanol, higher percentage blends of ethanol must be utilized in conventional automobiles. Such higher percentage blends of ethanol have recently become a contentious issue. Automobile manufacturers and environmental groups have fought against higher percentage ethanol blends. Currently, state and federal regulations prohibit the use of higher percentage ethanol blends in conventional automobiles and vehicle manufacturers have stated that using higher percentage ethanol blends in conventional vehicles would void the manufacturer’s warranty. Recently, the EPA made a ruling on using higher percentage blends (15%) in cars, pickups, and SUV’s made in years 2001 and later; however, there have been lawsuits challenging this ruling. This may delay the implementation of the ruling. 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 which could negatively impact our financial performance.

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 very strong incentive to develop commercial scale cellulosic ethanol. The RFS requires that 16 billion gallons per year of advanced bio-fuels 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 the demand for ethanol 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 more than 14.14 billion gallons of ethanol per year. In addition, there are eleven ethanol plants under construction or expansion underway which together are estimated to increase ethanol production capacity by more than 550 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. Further, demand for ethanol may not increase past approximately 13 billion gallons of ethanol due to the blending wall, unless the E15 blend approved by the EPA is implemented. If the demand for ethanol 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.

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 demand for ethanol. 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 passage of the Energy Policy Act of 2005 included a renewable fuels mandate. The RFS was increased in December 2007 to 36 billion gallons by 2022. Further, some states have passed renewable fuel mandates. All of these increases in ethanol demand have encouraged companies to enter the ethanol industry. 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 consolidation occurring in the ethanol industry in the near future which will likely lead to a few companies who control a significant portion of the 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 affect 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 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 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 conventional automobiles. 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.

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 RFS set forth in the Energy Policy Act of 2005. 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 prices and our revenues by making it more costly or difficult for us to produce and sell ethanol. If the federal tax incentives are eliminated or sharply curtailed, we believe that decreased demand for ethanol 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. While the 2008 Farm Bill extended the tariff on imported ethanol through 2011, this tariff could be repealed earlier which could lead to increased ethanol supplies and decreased ethanol prices.

If the Federal Volumetric Ethanol Excise Tax Credit (“VEETC”) expires on December 31, 2011, it could negatively impact our profitability. The ethanol industry is benefited by VEETC which is a federal excise tax credit of 45 cents per gallon of ethanol blended with gasoline at a rate of at least 10%. This excise tax credit is set to expire on December 31, 2011. We believe that VEETC positively impacts the price of ethanol. If VEETC is allowed to expire at the end of 2011, or is repealed earlier, it could negatively impact the price we receive for our ethanol and could negatively impact our profitability.

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 the 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 seeking 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 Illinois 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 and negatively affect our financial condition.

The California Low Carbon Fuels 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. Any decrease in ethanol demand could negatively impact ethanol prices which could reduce our revenues and negatively impact our ability to profitably operate the ethanol plant.

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 could lead to decreased revenues and may result in our inability to operate the ethanol plant profitably.

Risks Related to Conflicts of Interest

We are a majority-owned subsidiary of REX. REX may have relationships that present conflicts of interest with us. We are highly dependent upon REX, and under our Operating Agreement, REX has the right to appoint up to six directors (and a majority of our directors at a minimum) and has other special rights that other members do not have under our Operating Agreement. REX also has interests in several other ethanol plants with which we compete. REX may have relationships with other individuals, companies or organizations with which we will do business or compete. REX and its other subsidiaries may also become involved in other transactions, some of which may compete with our business.

Our directors may have relationships with individuals, companies or organizations with which we do business which may result in conflicts of interest. There may be business relationships between our directors and other individuals, companies or organizations with which we do business that may pose potential conflicts of interest with us. These relationships may result in conflicts of interest with respect to transactions between us and the other individuals, companies or organizations if our directors and officers put their interests in other companies or their own personal relationships ahead of what is best for our company. A majority of our directors are currently appointed by REX (although all six votes are held by one director, Zafar Rizvi), and the remaining directors are appointed by other members. Our members do not have the right to elect directors.

The Company is not required to include this information due to its status as a non-accelerated filer.

Our plant site is made up of three adjacent parcels which together total approximately 183 acres in east central Illinois near Gibson City, Illinois. The address of our plant is 202 N. Jordan Dr, Gibson City, Illinois 60936. In June 2009, the plant was substantially completed and plant operations commenced. The plant consists of the following buildings:

	•		A grains area, fermentation area, distillation — evaporation area;
	•		A dryer/energy center area;
	•		A tank farm;
	•		An auxiliary area;
	•		An administration building and;
	•		A storage/maintenance building.

Our plant is in excellent condition and is capable of functioning at 100% of its production capacity.

All of our tangible and intangible property, real and personal, serves as the collateral for the debt financing with First National Bank of Omaha, which is described below under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

None.

ITEM 4. REMOVED AND RESERVED.

PART II

As of December 31, 2010, we had approximately 13,781 membership units outstanding and approximately 324 unit holders of record. There is no public trading market for our units and no transfers for value have been completed as of December 31, 2010.

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 One Earth Energy to be deemed a publicly traded partnership. We do not have any securities authorized for issuance under any equity compensation plan.

We have not declared or paid any distributions on our units. Except for restrictions imposed in our loan agreement, our board of directors has complete discretion over the timing and amount of distributions to our unit holders. Provided that we are not in default on loan covenants, and with the prior approval of our lender, which may not be unreasonably withheld, our loan agreement allows us to make cash distributions at such times and in such amounts as will permit our unit holders to satisfy their income tax liability in a timely fashion. Our expectations with respect to our ability to make future distributions are discussed in greater detail in “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We, or any affiliate purchasers, have not completed any purchases of our units during our fiscal year ended December 31, 2010. We do, however, anticipate re-purchasing units from members that own four or less units and accept our offer to purchase, which has been distributed to our members and was filed with the Securities and Exchange Commission.

The following table presents selected financial and operating data as of the dates and for the periods indicated. The selected balance sheet data and the selected statement of operations data and other financial data have been derived from our audited financial statements. You should read the following table in conjunction with “Item 7 — Management’s 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.

Five Year Financial Summary
(Amounts In Thousands, Except Per Unit Amounts)

														Transition								From
														Period, Two								Inception,
														Months				Year				(November
Statement of		Year Ended				Year Ended				Year Ended				Ended				Ended				28, 2005) to
Operations		December 31,				December 31,				December 31,				December 31,				October 31,				October 31,
Data:		2010				2009				2008				2007				2007				2006
Revenues		$	234,545			$	98,190			$	—			$	—			$	—			$	—
Cost of sales			200,587				84,057				—				—				—				—
Gross profit			33,958				14,133				—								—				—
Operating income (loss)			31,141				13,230				(336	)			(87	)			(684	)			(592	)
Losses on derivative financial instruments			3,018				219				4,704				859				—				—
Interest expense			2,808				1,886				—				—				119				—
Net income (loss)		$	25,285			$	11,230			$	(4,827	)			(608	)		$	(694	)		$	(540	)
Net income (loss) per unit		$	1,834.77			$	802.14			$	(344.79	)		$	(43.43	)		$	(694.00	)		$	(540.00	)

Balance Sheet		December 31,				December 31,				December 31,				December 31,				October 31,				October 31,
Data:		2010				2009				2008				2007				2007				2006
Current assets		$	38,346			$	26,701			$	70			$	30,312			$	37,634			$	640
Property and equipment, net			144,131				148,709				128,639				36,032				26,863				43
Total assets			185,317				177,284				130,109				67,548				65,671				965
Current liabilities			17,418				13,780				12,112				4,171				1,937				82
Long-term debt			69,049				89,910				54,957				—				—				—
Derivative financial instruments, Long Term			3,688				3,818				4,494				—				—				—
Members’ equity		$	95,061			$	69,776			$	58,546			$	63,378			$	63,734			$	884

We were formed on November 28, 2005, thus there is no financial information prior to this date. See “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations”, for information regarding our exit from the development stage into production and operations.

Quarterly Financial Data (Unaudited)
(Amounts In Thousands, Except Per Unit Amounts)

		Quarter Ended				Quarter Ended				Quarter Ended				Quarter Ended
		March 31, 2010				June 30, 2010				September 30, 2010				December 31, 2010
Revenues		$	53,501			$	50,758			$	55,988			$	74,298
Cost of sales			44,701				43,678				47,340				64,868
Gross profit			8,800				7,080				8,648				9,430
Operating income			8,281				6,389				8,015				8,456
(Losses) gains on derivative financial instruments			(1,069	)			(1,304	)			(1,068	)			423
Interest expense			721				703				708				676
Income Taxes			—				—				—				144
Net income		$	6,512			$	4,411			$	6,271			$	8,091
Net income per unit		$	472.53			$	320.08			$	455.05			$	587.11

Quarterly Financial Data (Unaudited)
(Amounts In thousands, Except Per Unit Amounts)

		Quarter Ended				Quarter Ended				Quarter Ended				Quarter Ended
		March 31, 2009				June 30, 2009				September 30, 2009				December 31, 2009
Revenues		$	—			$	—			$	45,607			$	52,583
Cost of sales			134				472				40,775				42,676
Gross profit (loss)			(134	)			(472	)			4,832				9,907
Operating (loss) income			(241	)			(807	)			4,637				9,641
(Losses) gains on derivative financial instruments			(153	)			1,214				(1,278	)			(2	)
Interest expense			—				150				921				815
Net (loss) income		$	(354	)		$	285			$	2,456			$	8,843
Net (loss) income per unit		$	(25.29	)		$	20.36			$	175.43			$	631.54

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.

Overview

One Earth Energy, LLC was formed on November 28, 2005. We were formed for the purpose of raising capital to develop, construct, own and operate a 100 million gallon per year ethanol plant in east central Illinois near Gibson City, Illinois. We emerged from the development stage and began producing ethanol and distillers grains at the plant in June 2009. Prior to this, our efforts were focused primarily on raising capital and constructing our ethanol plant.

Results of Operations

Comparison of Fiscal Years Ended December 31, 2010 and 2009

Revenues

During our fiscal year ended December 31, 2009, we transitioned from a development stage company to an operational company, by beginning operations in June 2009. Accordingly, we did not yet have a full year of comparable income, production and sales data for the year ended December 31, 2009.

Our revenues are derived from the sale of our ethanol and distillers grains. For the fiscal years ended December 31, 2010 and 2009, we received approximately 83% and 85%, respectively, of our revenue from the sale of fuel ethanol, and approximately 17% and 15%, respectively, of our revenue from the sale of distillers grains. During the early part of our 2009 fiscal year, the ethanol industry was enduring unfavorable operating conditions. Thus, we postponed our grind date until margins improved. Increased gasoline and ethanol prices towards the end of the second quarter of 2009 allowed the ethanol industry to realize more favorable margins. For the fiscal years ended December 31, 2010 and 2009, the average selling price per gallon of ethanol was $1.80 and $1.66, respectively. Our sales were based upon approximately 107.9 and 50.6 million gallons of ethanol for 2010 and 2009, respectively. For the fiscal years ended December 31, 2010 and 2009, the average selling price per ton of distillers grains was $125.19 and $103.73 respectively. Our sales were based upon approximately 314,956 and 143,000 tons of distillers grains for 2010 and 2009, respectively.

Management anticipates that ethanol prices will continue to change in relation to changes in corn and energy prices. These prices have been somewhat volatile due to the uncertainty that we are experiencing in the overall economy which has been affecting commodities prices for the last year. Further, dry weather conditions during the summer of 2010 have resulted in increased corn prices. Management believes that there is currently a surplus of ethanol production capacity in the United States. We believe this has resulted in some ethanol producers decreasing ethanol and distillers grains production or halting operations altogether. The amount of this idled ethanol production capacity has decreased throughout our 2010 fiscal year as a result of changes in the spread between corn prices and ethanol prices.

A debate continues with respect to changes in the allowable percentage of ethanol blended with gasoline for use in standard (non-flex fuel) vehicles. Currently, ethanol is blended with conventional gasoline for use in standard 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. However, gasoline demand may be shrinking in the United States as a result of the global economic slowdown. 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 “blending 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 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 the ethanol industry is currently on the ege of reaching this blending wall. The Renewable Fuels Standard (“RFS”) mandate requires that 36 billion gallons of renewable fuels 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 conventional automobiles. Such higher percentage blends of ethanol have continued to be a contentious issue. Automobile manufacturers and environmental groups are lobbying against higher percentage ethanol blends. Recently, however, the EPA made a ruling on using higher percentage blends (15%) in cars, pickups, and SUV’s made in years 2001 and later; however, there have been lawsuits challenging this ruling.

Management believes that the market prices for distillers grains change in relation to the prices of other animal feeds, such as corn and soybean meal. As a result of the most current USDA grain estimates and increased demand for grains in Asian countries, there was a significant increase in the market price of corn. This resulted in a significant increase in distillers grains prices. We believe that the export market for distillers grains will continue to have a significant impact on our overall profitability, with ethanol margins narrowing from their highs in 2010.

We expect that revenues in future periods will be based upon production of approximately 100 million to 115 million gallons of ethanol per year. This expectation assumes that we will continue to operate at or near nameplate capacity, which is dependent upon the crush spread realized and other market conditions. In addition, as of December 31, 2010, our air permit allows us to produce up to 125 million gallons per year. While we currently can achieve only 115 million gallons in RINS (Renewable Identification Number System), this may change in the future and our production may exceed 115 million gallons per year.

Cost of Sales

Our cost of goods sold as a percentage of revenues was 85.5% and 85.6% for the fiscal years ended December 31, 2010 and 2009, respectively. See the table under “Additional Information” below. Our two primary costs of producing ethanol and distillers grains are corn costs and natural gas costs. Corn prices have increased approximately 73% from a low in September 2009 to December 2010, and continued to rise into 2011. The cost of corn is the highest input to the plant, approximately 78% of production costs, and these uncertainties could dramatically affect our expected input cost. We expect continued volatility in the price of corn, which could significantly impact our cost of goods sold. We used approximately 38.7 million bushels of corn in 2010, and the average price we paid for corn in 2010 was $4.05 per bushel. Natural gas prices have declined following a peak in mid-2008, and our price per MMBTU was $4.64 and $3.84 in 2010 and 2009, respectively. We used approximately 3.1 million MMBTU’s of natural gas in 2010. Management expects short-term natural gas prices to remain lower than historical levels. Other significant costs are chemical costs, which have continued to increase since 2009. The average cost per gallon of ethanol produced for chemicals in 2009 was approximately $.051, and by the end of 2010, these costs had increased to approximately $.0642 per gallon of ethanol produced, a 26% increase.

Selling, General and Administrative Expense

Our selling, general and administrative expenses were $2.8 million for the fiscal year ended December 31, 2010 compared to $0.9 million for the fiscal year ended December 31, 2009. We experienced a significant increase in our operating expenses for the fiscal year ended December 31, 2010 compared to the same period of 2009 primarily due to our plant becoming fully operational. Operating expenses include sales commissions, salaries and benefits of administrative employees, taxes, professional fees and other general costs. We expect these expenses, on an annualized basis, to be less than the fiscal year ended December 31, 2010 in future periods, as we intend to pursue plans to qualify to suspend our SEC reporting requirements during this fiscal year.

Operating Income

As a result of the foregoing, our income from operations for the fiscal year ended December 31, 2010 was approximately $31.1 million compared to $13.2 million for the fiscal year ended December 31, 2009.

Interest and Other Income

Interest and other income was approximately $115,000 for the fiscal year ended December 31, 2010, and $105,000 for the fiscal year ended December 31, 2009.

Interest Expense

Interest expense was $2.8 million for the fiscal year ended December 31, 2010, and $1.9 million for the fiscal year ended December 31, 2009. The increase was due primarily to the capitalization of interest in the first half of 2009 while the plant was under construction. Based on current interest rates and debt levels, we expect interest expense in 2011 to be in the range of $2.5 million to $3.0 million.

Losses on derivative financial instruments

We recognized losses of approximately $3.0 million and $0.2 million during the fiscal years ended December 31, 2010 and 2009, respectively, related to interest rate swap agreements. In general, declining interest rates have a negative effect on our interest rate swaps as our swaps fixed the interest rate of variable rate debt. Should interest rates continue to decline, we would expect to experience continued losses on the interest rate swaps. We would expect to incur gains on the interest rate swaps should interest rates increase. We cannot predict the future movements in interest rates; thus, we are unable to predict the likelihood or amounts of future gains or losses related to interest rate swaps.

Net income/loss

As a result of the foregoing, net income for the fiscal year ended December 31, 2010 was $25.3 million, an increase of $14.1 million from $11.2 million for the fiscal year ended December 31, 2009.

Additional Information

The following table shows additional data regarding production and price levels for our primary inputs and products for the fiscal years ended December 31, 2010 and 2009.

		Fiscal Year Ended				Fiscal Year Ended
		December 31, 2010				December 31, 2009
Production:
Ethanol sold (gallons)			107,950,514				50,560,316
Distillers grains sold (tons)			314,956				143,095
Revenues:
Ethanol average price per gallon		$	1.80			$	1.66
Distillers grains average price per ton		$	125.19			$	103.73
Primary Inputs:
Corn ground (bushels)			38,694,596				18,600,712
Natural gas purchased (MMBTU)			3,064,373				1,483,285
Costs of Primary Inputs:
Corn average price per bushel ground		$	4.052			$	3.620
Natural gas average price per MMBTU		$	4.643			$	3.844

During the fiscal year ended December 31, 2010, the market price of ethanol varied between approximately $1.70 per gallon and approximately $2.30 per gallon. Our average, price per gallon of ethanol sold was approximately $1.80. If our average price received per gallon of ethanol had been 10% lower, our net income for the fiscal year ended December 31, 2010 would have decreased by approximately $19.4 million assuming our other revenues and costs remained unchanged.

During the fiscal year ended December 31, 2010, the market price of distillers grains varied between approximately $125.00 per ton and approximately $188.00 per ton. Our average price per ton of distillers grains sold was approximately $125.19. If our average price received per ton of distillers grains had been 10% lower, our net income for the fiscal year ended December 31, 2010 would have decreased by approximately $4.0 million assuming our other revenues and costs remained unchanged.

During the fiscal year ended December 31, 2010, the market price of corn varied between approximately $3.25 per bushel and approximately $6.29 per bushel. Our average price per bushel of corn ground was approximately $4.05. If our average price paid per bushel of corn had been 10% higher, our net income for the fiscal year ended December 31, 2010 would have decreased by approximately $15.9 million, assuming our other revenues and costs remained unchanged.

During the fiscal year ended December 31, 2010, the market price of natural gas varied between approximately $3.38 per MMBTU and approximately $7.43 per MMBTU. Our average price per MMBTU of natural gas was approximately $4.64. If our average price paid per MMBTU of natural gas had been 10% higher, our net income for the fiscal year ended December 31, 2010 would have decreased by approximately $1.4 million, assuming our other revenues and costs remained unchanged.

We are currently operating at full, or nearly full, capacity. However, in the event that we decrease our production of ethanol, our production of distillers grains would also decrease accordingly. Such a decrease in our volume of production of ethanol and distillers grains would result in lower revenues. However, if we decreased production, we would require a corresponding decreased quantity of corn and natural gas, thereby lowering our costs of goods sold. Therefore, the effect of a decrease in our product volume would be largely dependent on the market prices of the products we produce and the inputs we use to produce our products at the time of such a production decrease. We anticipate operating at less than full capacity only if operating margins become unfavorable or we experience technical difficulties in operating the plant.

Comparison of Fiscal Years Ended December 31, 2009 and 2008

Revenues

During our fiscal year ended December 31, 2009, we transitioned from a development stage company to an operational company by beginning operations in June of 2009. Accordingly, we did not yet have comparable income, production and sales data for the year ended December 31, 2009 from our previous fiscal year.

Our revenues are derived from the sale of our ethanol and distillers grains. For the fiscal year ended December 31, 2009, we received approximately 85% of our revenue from the sale of fuel ethanol and approximately 15% of our revenue from the sale of distillers grains. During the early part of our 2009 fiscal year, the ethanol industry was enduring unfavorable operating conditions. Thus, we postponed our grind date until margins improved. Increased gasoline and ethanol prices towards the end of the second quarter of 2009 allowed the ethanol industry to realize more favorable margins. For the fiscal year ended December 31, 2009, the average selling price per gallon of ethanol was $1.65 and our sales were based upon approximately 50.6 million gallons of ethanol. For the fiscal year ended December 31, 2009, the average selling price per ton of distillers grains was $103.73 and our sales were based upon approximately 143,000 tons of distillers grains.

Cost of Sales

Our cost of goods sold as a percentage of revenues was 85.6% for the fiscal year ended December 31, 2009. Our two primary costs of producing ethanol and distillers grains are corn costs and natural gas costs. Corn prices reached historical highs in June 2008, but have decreased since that time as stronger than expected corn yields materialized and the global financial crisis brought down the prices of most commodities generally. The cost of corn is the highest input to the plant and these uncertainties could dramatically affect our expected input cost. We used approximately 18.6 million bushels of corn in fiscal year 2009, and the average price we paid for corn in 2009 was $3.62 per bushel. Natural gas prices have declined following a peak in mid-2008, and our price per MMBTU was $3.84 in 2009. We used approximately 1.4 million MMBTU’s of natural gas in fiscal year 2009. Other significant costs are chemical costs, which have continued to increase since 2009. The average cost per gallon of ethanol produced for chemicals in 2009 was approximately $.051.

Selling, General and Administrative Expense

Our selling, general and administrative expenses were $0.9 million for the fiscal year ended December 31, 2009 compared to $0.3 million for the fiscal year ended December 31, 2008. We experienced a significant increase in our operating expenses for the fiscal year ended December 31, 2009 compared to the same period of 2008 primarily due to an increase in our employees as a result of our plant becoming fully operational. Operating expenses include salaries and benefits of administrative employees, taxes, professional fees and other general costs.

Operating Income

As a result of the foregoing, our income from operations for the fiscal year ended December 31, 2009 was approximately $13.2 million compared to a loss of $0.3 million for the fiscal year ended December 31, 2008.

Interest and Other Income

Interest and other income was $105,000 for the fiscal year ended December 31, 2009 and was consistent with the 2008 results.

Interest Expense

Interest expense was $1.9 million for the fiscal year ended December 31, 2009. We reported no interest expense for the fiscal year ended December 31, 2008. The increase was primarily attributable to the higher amounts of average debt outstanding we had upon the completion of construction of our ethanol plant. In addition, we did not capitalize interest during 2009 as we did in 2008 while we were completing the construction of our ethanol plant.

Losses on derivative financial instruments

We recognized losses of approximately $0.2 million and $4.7 million during the fiscal years ended December 31, 2009 and 2008, respectively, related to interest rate swap agreements. In general, declining interest rates have a negative effect on our interest rate swaps as our swaps fixed the interest rate of variable rate debt. Should interest rates continue to decline, we would expect to experience continued losses on the interest rate swaps. We would expect to incur gains on the interest rate swaps should interest rates increase.

Net income/loss

As a result of the foregoing, net income for the fiscal year ended December 31, 2009 was $11.2 million, an increase of $16.0 million from a loss of $4.8 million for the fiscal year ended December 31, 2008.

Changes in Financial Condition for the Fiscal Year Ended December 31, 2010

We experienced an increase in our current assets at December 31, 2010 compared to December 31, 2009. We experienced an increase of approximately $1.5 million in inventory at December 31, 2010 compared to December 31, 2009, partially due to increased volumes in inventories, and primarily due to increased corn prices. Additionally, at December 31, 2010, we had trade accounts receivable of approximately $9.4 million compared to trade accounts receivable at December 31, 2009 of approximately $5.4 million, an increase of $4.0 million. This is due primarily to increased ethanol and DDGS prices from 2009 to 2010. We also had cash of $18.3 million at December 31, 2010, compared to cash of $12.1 million at December 31, 2009 as we generated cash from operations of approximately $30.3 million during the year ended December 31, 2010, offset by purchases of capital assets of $4.8 million, and debt payments of $19.2 million. We had prepaid and other current assets of $2.8 million at December 31, 2010, compared to $2.9 million at December 31, 2009. At December 31, 2010, included within prepaid expenses and other current assets were prepaid natural gas and other prepaid manufacturing supplies of $0.9 million, compared to $1.1 million at December 31, 2009. We also had other noncurrent assets of $1.8 million at December 31, 2010, compared to $0.6 million at December 2009.

We experienced an increase in our total current liabilities at December 31, 2010 compared to December 31, 2009. We experienced an increase of approximately $1.5 million in the current portion of our long term debt at December 31, 2010 compared to December 31, 2009, which is in line with the principal payment schedule incorporated into the loan agreement with First National Bank of Omaha. We also experienced an increase of approximately $0.4 million for the current portion of the swap derivative liability at December 31, 2010 compared to December 31, 2009; and an increase of approximately $1.5 million in our accounts payable for corn purchases and other items at December 31, 2010 compared to December 31, 2009.

We experienced a decrease in our long-term liabilities as of December 31, 2010 compared to December 31, 2009. At December 31, 2010, we had approximately $69.0 million outstanding in the form of long-term loans, compared to approximately $89.9 million at December 31, 2009. This decrease is attributed to payments made in addition to regularly scheduled payments per the loan agreement.

Changes in Financial Condition for the Fiscal Year Ended December 31, 2009

We experienced an increase in our current assets at December 31, 2009 compared to December 31, 2008. We experienced an increase of approximately $6.3 million in the value of our inventory at December 31, 2009 compared to December 31, 2008, as a result of the commencement of operations at our plant. Additionally, at December 31, 2009 we had trade accounts receivable of approximately $5.5 million compared to no trade accounts receivable at December 31, 2008; again, the result of the commencement of operations at our plant. We also had cash of $12.1 million at December 31, 2009, compared to cash of $0.02 million at December 31, 2008 as we generated cash from operations during the year ended December 31, 2009. We had prepaid and other current assets of $2.9 million at December 31, 2009, compared to $0.1 million at December 31, 2008; the increase results from activities associated with commencement of operations at our plant. At December 31, 2009, we had prepaid natural gas and other prepaid manufacturing supplies of $1.1 million and we also had property taxes refundable of $1.0 million.

We experienced an increase in our total current liabilities at December 31, 2009 compared to December 31, 2008. We experienced an increase of approximately $7.0 million in the current portion of our long term debt at December 31, 2009 compared to December 31, 2008 due to the conversion of our construction loan to a term loan with principal and interest payments becoming due on a quarterly basis commencing in July 2009. We also experienced an increase of approximately $3.1 million for accrued expenses at December 31, 2009 compared to December 31, 2008; and an increase of approximately $1.0 million in our accounts payable for corn purchases and other items at December 31, 2009 compared to December 31, 2008. All of these increases relate primarily to the commencement of operations at our plant. Such increases were partially offset by a decrease in our construction payable of approximately $9.8 million at December 31, 2009 compared to December 31, 2008.

We experienced an increase in our long-term liabilities as of December 31, 2009 compared to December 31, 2008. At December 31, 2009, we had approximately $89.9 million outstanding in the form of long-term loans, compared to approximately $55.0 million at December 31, 2008. This increase is attributed to cash we borrowed from our long-term loans to complete the construction of our facility and commence operations.

Critical Accounting Policies

We believe the application of the following accounting policies, which are important to our financial position and results of operations, require significant assumptions, judgments and estimates on the part of management. We base our assumptions, judgments, and estimates on historical experience, current trends and other factors that management believes to be relevant at the time our financial statements are prepared. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented in accordance with generally accepted accounting principles (GAAP). However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates, and such differences could be material. Further, if different assumptions, judgments and estimates had been used, the results could have been different and such differences could be material. For a summary of all of our accounting policies, including the accounting policies discussed below, see Note 1 of the Notes to the Financial Statements. Management believes that the following accounting policies are the most critical to aid in fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

Inventory Reserves — Inventory is recorded at the lower of cost or market. The market value of inventory is often dependent upon fluctuating commodity prices. If these estimates are inaccurate, we may be exposed to market conditions that require an additional reduction in the value of certain inventories affected. We permanently write down inventory for items that have a cost greater than net realizable value. There were no inventory reserves or write downs at December 31, 2010 and December 31, 2009. Assumptions we use to estimate the necessary reserve or write down have not significantly changed over the last two fiscal years. The assumptions we currently use include our estimates of the selling prices of ethanol and distillers grains and the cost of corn.

Financial Instruments — Forward grain purchase and ethanol and distillers grains sale contracts are accounted for under the “normal purchases and normal sales” scope exemption of ASC 815, “Derivatives and Hedging” (“ASC 815”) because these arrangements are for purchases of corn and sales of ethanol and distillers grains that will be delivered in quantities expected to be used by us over a reasonable period of time in the normal course of business. We use derivative financial instruments to manage our balance of fixed and variable rate debt. We do not hold or issue derivative financial instruments for trading or speculative purposes. Interest rate swap agreements involve the exchange of fixed and variable rate interest payments and do not represent an actual exchange of the notional amounts between the parties. Our swap agreements were not designated for hedge accounting pursuant to ASC 815. The interest rate swaps are recorded at their fair values and the changes in fair values are recorded as gain or loss on derivative financial instruments in the accompanying statements of operations.

Recoverability of Long-Lived Assets — We review 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. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of the recoverability of long-lived assets of property and equipment to be a critical accounting estimate. Any adverse change in the spread between ethanol and corn prices could result in impairment charges. Factors that affect the spread between ethanol and corn prices include overall market conditions for ethanol and corn, the availability and price of locally supplied corn and our ability to sell ethanol to existing customers.

Trends and Uncertainties Impacting the Ethanol Industry and Our Operations

We are subject to industry-wide factors, trends and uncertainties that affect our operating and financial performance. These factors include, but are not limited to, the available supply and cost of corn from which our ethanol and distillers grains are processed; the cost of natural gas, which we use in the production process; new technology developments in the industry; dependence on our ethanol marketer and distillers grains marketer to market and distribute our products; the intensely competitive nature of the ethanol industry; and possible changes in legislation/regulations at the federal, state and/or local level. These factors as well as other trends and uncertainties are described in more detail below.

Corn Prices

Our cost of goods sold consists primarily of costs relating to the corn necessary to produce ethanol and distillers grains for sale. On March 10, 2011, the USDA released its Crop Production report, which estimated the 2010 grain corn crop at approximately 12.45 billion bushels, approximately 4% lower than the USDA’s estimate of the 2009 corn crop of 12.9 billion bushels. Corn prices have come down from their historical highs of 2008, but as previously idled plants came back online in 2009 and 2010, and due to lower production estimates, corn prices have increased sharply towards the end of 2010, and into 2011. We expect continued volatility in the price of corn, which could significantly impact our cost of goods sold.

The price at which we will purchase corn depends on prevailing market prices. There is no assurance that a corn shortage will not develop, particularly if there is an extended drought or other production problems in the 2011 crop year. We anticipate that our plant’s profitability could be negatively impacted during periods of high corn prices that are not offset by increased ethanol prices. Although we expect the negative impact on profitability resulting from high corn prices to be mitigated, in part, by the increased value of the distillers grains we intend to market (as the price of corn and the price of distillers grains tend to fluctuate in tandem), we still may be unable to operate profitably if high corn prices are sustained for a significant period of time.

Ethanol Industry Competition

We operate in a competitive industry and compete with a number of larger ethanol producers. The ethanol industry is starting to emerge from the difficult collapse that has occurred since the commencement of our operations in June 2009, and as ethanol margins continue to narrow, ethanol producers are looking to other revenue streams, such as oil extraction, and sales of carbon dioxide, which we have not invested in.

Distillers Grains Markets

With the advancement of research into the feeding of distillers grains based rations to poultry, swine and beef, we anticipate these markets will continue to expand, creating additional demand for distillers grains.

Technology Developments

One current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. Although current technology is not sufficiently efficient to be competitive, the United States Congress is consistently increasing the availability of incentives to promote the development of commercially viable cellulose based ethanol production technology.

Advances and changes in the technology used to produce ethanol may make our technology less desirable or obsolete. As of this date there are no known technologies that would cause our plant to become uncompetitive or completely obsolete.

Government Legislation and Regulations

The ethanol industry and our business are assisted by various federal ethanol supports and tax incentives, including those included in the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. Government incentives for ethanol production, including federal tax incentives, may be reduced or eliminated in the future, which could hinder our ability to operate at a profit. Federal ethanol supports, such as the renewable fuels standard (“RFS”), help support a market for ethanol that might disappear without this incentive; as such, a waiver of minimum levels of renewable fuels included in gasoline could have a material adverse effect on our results of operations. The elimination or reduction of tax incentives to the ethanol industry, such as the VEETC available to gasoline refiners and blenders, could reduce the market for ethanol, causing prices, revenues, and profitability to decrease. Although VEETC was set to expire on December 31, 2010, it was extended retroactively, through December 31, 2011.

The USDA recently announced that it will provide financial assistance to 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. Blender pumps typically can dispense E10, E20, E30, E40, E 50 and E85. These blender pumps accomplish the 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.

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 for the next 12 months. We do not anticipate seeking additional equity or debt financing during our 2011 fiscal year. However, should we experience unfavorable operating conditions in the future, we may have to secure additional debt or equity sources for working capital or other purposes.

As a result of current favorable conditions in the ethanol market, we have not drawn on borrowings from our revolving line of credit since we began production in June 2009. However, should we experience unfavorable operating conditions in the ethanol industry that prevent us from profitably operating the ethanol plant, we could have difficulty maintaining our liquidity.

Cash Flows Provided By/ Used in Operating Activities

Net cash provided by operating activities was approximately $30.4 million for the fiscal year ended December 31, 2010 compared to cash provided of approximately $4.8 million for the fiscal year ended December 31, 2009. For the fiscal year ended December 31, 2010, cash was provided by net income of $25.3 million, adjusted for non-cash items of $10.1 million, which consisted of depreciation and amortization and changes in the fair value of derivative financial instruments. Increases in accounts receivable, inventory and other assets used cash of approximately $4.0 million, $1.5 million and $1.3 million, respectively. In addition, an increase in accounts payable provided cash of approximately $1.4 million.

Net cash provided by operating activities was approximately $4.8 million for the fiscal year ended December 31, 2009 compared to cash used of approximately $0.1 million for the fiscal year ended December 31, 2008. For the fiscal year ended December 31, 2009, cash was provided by net income of $11.2 million, adjusted for non-cash items of $4.6 million, which consisted of depreciation and amortization and changes in the fair value of derivative financial instruments. Increases in accounts receivable, inventory and prepaid expenses and other assets used cash of $5.5 million, $6.3 million and $3.4 million, respectively, a result of the plant becoming operational during the current year. In addition, increases in accounts payable, accrued and other liabilities provided cash of $1.0 million and $3.0 million, respectively, a result of the plant becoming operational during the current year.

Cash Flows From Investing Activities

Net cash used in investing activities was approximately $4.9 million for the fiscal year ended December 31, 2010 compared to approximately $24.9 million for the fiscal year ended December 31, 2009. The majority of the 2009 cash flows related to the construction of our ethanol plant during 2008 and 2009, and the 2010 cash flows are related to the construction of additional corn storage bins.

Net cash used in investing activities was approximately $24.9 million for the fiscal year ended December 31, 2009 compared to approximately $86.2 million for the fiscal year ended December 31, 2008. The majority of these cash flows related to the construction of our ethanol plant during 2008 and 2009.

Cash Flows From Financing Activities

Net cash from financing activities was approximately $19.3 million for the fiscal year ended December 31, 2010, representing principal payments on the bank loan, and no borrowings. This is compared to approximately $32.2 million for the fiscal year ended December 31, 2009. Borrowings on our construction loan were $39.2 million during the fiscal year ended December 31, 2009. As we converted the construction loan into a term loan during the fiscal year ended December 31, 2009, we made principal payments of $7.0 million on the term loan.

Net cash provided by financing activities was approximately $32.2 million for the fiscal year ended December 31, 2009 compared to approximately $56.0 million for the fiscal year ended December 31, 2008. Borrowings on our construction loan were $39.2 million during the fiscal year ended December 31, 2009. As we converted the construction loan into a term loan during the fiscal year ended December 31, 2009, we made principal payments of $7.0 million on the term loan. Cash provided by financing activities in 2008 related to borrowings on the construction loan.

Credit Facilities

On September 20, 2007, we entered into a loan agreement with First National Bank of Omaha establishing a senior credit facility for the construction of our plant. The credit facility was in the amount of $111,000,000 consisting of a $100,000,000 construction note, a $10,000,000 revolving line of credit and a $1,000,000 letter of credit. In September 2008, we extended the $10,000,000 revolving line of credit to expire in September 2009, subject to certain borrowing base limitations. In September 2009, we extended this revolving line of credit to expire in September 2010. In June 2010, we extended this revolving line of credit to expire on May 31, 2011. At December 31, 2010, there were no outstanding borrowings on the revolving line of credit. We are subject to certain financial covenants under the loan agreement. The most restrictive of which are debt service coverage ratio requirements, net worth requirements and working capital requirements. We are required to maintain a fixed charge coverage ratio of no less than 1.25:1.0 for all periods after July 31, 2009. For the first fiscal quarter after July 31, 2009 our fixed charge coverage ratio was measured on a rolling one quarter basis, for the second fiscal quarter after July 31, 2009, our fixed charge coverage ratio was measured on a rolling two quarter basis, and for the third fiscal quarter after July 31, 2009 our fixed charge coverage ratio is measured on a rolling three quarter basis. Thereafter, our fixed charge coverage ratio is measured on a rolling four quarter basis. Our fixed charge coverage ratio is calculated by comparing our “adjusted” EBITDA, meaning EBITDA less taxes, capital expenditures and allowable distributions, to our scheduled payments of the principal and interest on our obligations to our lender, other than principal repaid on our revolving loan and long term revolving note. For the periods ended December 31, 2010 and 2009, our fixed charge coverage ratios were 2.52:1.0 and 3.67:1.0 respectively.

We are also required to maintain a minimum net worth of approximately $56.3 million. It shall be measured annually at the end of each fiscal year. In subsequent years, our minimum net worth requirement will increase by the greater of $500,000 or the amount of undistributed earnings accumulated during the prior fiscal year. Accordingly, our minimum net worth requirement for 2010 was $67.5 million. At December 31, 2010 and 2009, our net worth was approximately $93.0 and $69.8 million, respectively.

We are also required to maintain a minimum amount of working capital, which is calculated as our current assets plus the amount available for drawing under our Long Term Revolving Note, less current liabilities and prepaid expenses. From November 1, 2009 through February 28, 2010, our minimum working capital requirement was $4,000,000. Beginning March 1, 2010 through July 31, 2010, our minimum working capital requirement was $7,000,000. After August 1, 2010, our minimum working capital is $10,000,000. At December 31, 2010 and 2009, our working capital was approximately $29.7 and $22.7 million, respectively.

The Company also has access to a secondary line of credit of up to $10,000,000 with the Bank, established as part of the original $100,000,000 term loan and made accessible as a revolving line of credit as term loan payments were made. The amount available is reduced by $250,000 on a quarterly basis. At December 31, 2010 and 2009, the Company had $8,750,000 and $10,000,000 on the secondary line of credit, respectively, available on this revolving line of credit. The Company has no outstanding borrowings as of December 31, 2010 and 2009.

Outlook

We believe we have sufficient working capital and credit availability to fund our commitments and to maintain our operations at their current levels for the next twelve months and foreseeable future. We have been constructing two corn silos at our plant during 2010, and have used cash from operations to pay for these capital expenditures, which have cost approximately $4.8 million as of December 31, 2010. These silos will become operational in the second quarter of 2011.

Off-Balance Sheet Arrangements

None

Tabular Disclosure of Contractual Obligations

In the ordinary course of business, we enter into agreements under which we are obligated to make legally enforceable future cash payments. These agreements include obligations related to purchasing inventory, incurring indebtedness, interest rate management and utility agreements.

The following table summarizes by category expected future cash outflows associated with contractual obligations in effect as of December 31, 2010 (amounts in thousands):

		Payment due by period
						Less
						than 1				1-3				3-5				More than
Contractual Obligations		Total				Year				Years				Years				5 Years
Lease obligations (a)		$	39			$	20			$	19			$	—			$	—
Long-term debt obligations			78,721				9,672				69,049								—
Interest on variable rate debt (b)			8,037				2,537				5,500								—
Corn contracts			30,064				30,064
Other (c)			4,297				1,186				3,112				—				—
Total (d)		$	121,158			$	43,479			$	77,680			$	—			$	—

Seasonality of Ethanol Sales

We experience some seasonality of demand for our ethanol. Since ethanol is predominantly blended with conventional 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. In addition, we experience some increased ethanol demand during holiday seasons related to increased gasoline demand.

Impact of Inflation

The impact of inflation has not been material to our results of operations for the past three fiscal years.

We are exposed to the impact of market fluctuations associated with interest rates and commodity prices as discussed below.

Interest Rate Risk

We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding term and revolving loans that bear variable interest rates. Specifically, we have approximately $78.7 million outstanding in debt as of December 31, 2010, all of which is variable-rate. Interest rates on our variable-rate debt are determined based upon the market interest rate of LIBOR plus 300 to 310 basis points. A 10% adverse change (for example from 4.0% to 4.4%) in market interest rates would affect our interest cost on such debt by approximately $0.3 million per year in the aggregate.

We entered into two forward interest rate swaps in the notional amounts of $50.0 million and $25.0 million with the First national Bank of Omaha during the fiscal years ended December 31, 2008 and 2007. The $50.0 million swap fixed the variable interest rate of a portion of our term loan at 7.9%, while the $25.0 million swap fixed the variable interest rate of a portion of our term loan at 5.49%. The swap settlements commenced on July 31, 2009; the $50.0 million swap terminates on July 8, 2014 and the $25.0 million swap terminates on July 31, 2011. A hypothetical 10% change (for example, from 4.0% to 3.6%) in market interest rates at December 31, 2010 would change the fair value of the interest rate swaps by approximately $0.5 million.

Commodity Price Risk

We do not employ derivative instruments such as futures and options to hedge our commodity price risk. Our strategy is to “flat price” a portion of our electricity and natural gas requirements, and to purchase the remainder on a floating index. We purchase all of our corn through Alliance Grain.

A sensitivity analysis has been prepared to estimate our exposure to ethanol, corn and natural gas 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 natural gas prices and average ethanol price as of December 31, 2010. The volumes are based on our actual use and sale of these commodities for the year ended December 31, 2010. The results of this analysis are as follows:

										Hypothetical				Approximate
		Volume for the year ended								Adverse Change in				Adverse Change to
		December 31. 2010				Unit of Measure				Price				Income
Natural Gas			3,064,373			MMBtu					10	%		$	1,413,902
Ethanol			107,950,227			Gallons					10	%		$	19,485,016
Corn			38,694,596			Bushels					10	%		$	15,916,635
Distillers Grains			314,956			Tons					10	%		$	3,942,934

ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of One Earth Energy, LLC
Gibson City, Illinois

We have audited the accompanying balance sheets of One Earth Energy, LLC (the “Company”) as of December 31, 2010 and 2009, and the related statements of operations, changes in members’ equity, and cash flows for each of the three years in the 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 purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, such financial statements present fairly, in all material respects, the financial position of One Earth Energy, LLC at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP   Cincinnati, Ohio
March 31, 2011

ONE EARTH ENERGY, LLC

BALANCE SHEETS
(Amounts in Thousands)

		December 31,				December 31,
		2010				2009
Assets
Current assets:
Cash and cash equivalents		$	18,343			$	12,099
Accounts receivable			9,415				5,457
Inventory			7,819				6,290
Prepaid expenses			1,335				1,579
Other current assets			1,434				1,276
Total current assets			38,346				26,701
Property and equipment, net			144,131				148,709
Deferred financing costs, net			979				1,259
Restricted cash			20				20
Other assets			1,841				595
Total assets		$	185,317			$	177,284
Liabilities and equity:
Current liabilities:
Accounts payable, trade			2,476			$	1,016
Current portion of long-term debt			9,672				8,089
Accrued real estate taxes			1,934				1,930
Derivative financial instruments			1,835				1,413
Other current liabilities			1,501				1,332
Total current liabilities			17,418				13,780
Long-term liabilities:
Deferred income taxes			101
Long-term debt			69,049				89,910
Derivative financial instruments			3,688				3,818
Total long-term liabilities			72,838				93,728
Commitments and contingencies
Members’ equity:
Members’ capital (13,781 units issued and outstanding in 2010 and 2009 )			65,215				65,215
Retained earnings			29,846				4,561
Total members’ equity			95,061				69,776
Total liabilities and equity		$	185,317			$	177,284

See notes to financial statements.

ONE EARTH ENERGY, LLC

STATEMENTS OF OPERATIONS
(Amounts in Thousands, Except Per Unit Amounts)

		Years Ended December 31,
		2010				2009				2008
Revenues		$	234,545			$	98,190			$	—
Cost of sales			200,587				84,057				—
Gross profit			33,958				14,133				—
Selling, general and administrative expenses			(2,817	)			(903	)			(336	)
Operating income (loss)			31,141				13,230				( 336	)
Interest and other income			114				105				213
Interest expense			(2,808	)			(1,886	)			—
Losses on derivative financial instruments			(3,018	)			(219	)			(4,704	)
Income before provision for income taxes			25,429				11,230				(4,827	)
Provision for income taxes			144				—				—
Net income (loss)		$	25,285			$	11,230			$	(4,827	)
Weighted average units outstanding — basic and diluted			14				14				14
Basic and diluted net income (loss) per unit		$	1,834.77			$	802.14			$	(344.79	)

See notes to financial statements.

ONE EARTH ENERGY, LLC
STATEMENTS OF CHANGES IN MEMBERS’ EQUITY
(Amounts in thousands)

		Member’s				Accumulated
		Capital				Earnings (Deficit)				Total
Balance, December 31, 2007		$	65,215			$	(1,842	)		$	63,373
Net loss			—				(4,827	)			(4,827	)
Offering costs			—				—				—
Balance, December 31, 2008			65,215				(6,669	)			58,546
Net income			—				11,230				11,230
Balance, December 31, 2009			65,215				4,561				69,776
Net income			—				25,285				25,285
Balance, December 31, 2010		$	65,215			$	29,846			$	95,061

See notes to financial statements.

ONE EARTH ENERGY, LLC
STATEMENTS OF CASH FLOWS
(Amounts in Thousands)

		Years Ended December 31,
		2010				2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	25,285			$	11,230			$	(4,827	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization			9,816				4,949				18
Derivative financial instruments			292				(332	)			4,704
Changes in operating assets and liabilities:
Accounts receivable			(3,958	)			(5,457	)			(4	)
Inventory			(1,529	)			(6,290	)			—
Prepaid expenses			244				(1,525	)			11
Accounts payable, trade			1,358				1,009				(12	)
Other current assets			(158	)			(1,276	)			—
Other assets			(1,246	)			(580	)			—
Deferred taxes			101				—				—
Accrued and other current liabilities			173				3,061				(4	)
Net cash provided by (used in) operating activities			30,378				4,789				(114	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Restricted cash			—				—				(20	)
Capital expenditures			(4,856	)			(24,879	)			(86,143	)
Net cash used in investing activities			(4,856	)			(24,879	)			(86,163	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments for financing costs			—				(35	)			—
Proceeds from long-term debt			—				39,208				56,042
Payments of long-term debt			(19,278	)			(7,000	)			—
Net cash (used in) provided by financing activities			(19,278	)			32,173				56,042
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			6,244				12,083				(30,235	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			12,099				16				30,251
CASH AND CASH EQUIVALENTS, END OF YEAR		$	18,343			$	12,099			$	16
Non cash activities — Accrued capital expenditures		$	102			$	3			$	—
Non cash activities — Payable related to plant construction refinanced to long-term debt		$	—			$	—			$	9,750
SUPPLEMENTAL INFORMATION:
Cash paid during the year for interest		$	2,987			$	3,082			$	892

See notes to financial statements.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

One Earth Energy, LLC (the “Company”), was organized on November 28, 2005, as an Illinois limited liability company. The Company is a majority-owned subsidiary of Farmers Energy One Earth, LLC (“Farmers Energy”), which is an indirect, wholly owned, subsidiary of REX American Resources Corporation. The Company was formed to construct, own, and operate a 100 million gallon design capacity ethanol production facility located near Gibson City, Illinois. The Company financed construction of the facility through member equity contributions and from bank financing. The Company exited the development stage and began production of fuel ethanol and other ethanol co-products in late June 2009. The Company operates in one reportable segment, alternative energy.

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Concentration of Credit Risk

The Company maintains cash and cash equivalents in accounts with financial institutions, which, at times, exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company does not believe there is significant credit risk associated with its cash and cash equivalents.

Four customers accounted for approximately 84% of the Company’s sales during 2010. At December 31, 2010, four customers comprised approximately 91% of the Company’s accounts receivable balance.

Three customers accounted for approximately 86% of the Company’s sales during 2009. At December 31, 2009, three customers comprised approximately 83% of the Company’s accounts receivable balance.

Cash Equivalents

All highly liquid investments with a maturity of three months or less at the time of purchase are considered to be cash equivalents.

Property and Equipment

Property and equipment are stated at cost, less accumulated depreciation and amortization. Depreciation is determined using the straight-line method for financial reporting purposes over the estimated useful lives of the assets ranging from five to 40 years. The Company capitalizes interest on its construction in progress activities. The Company capitalized $1,530,126 of interest during the year ended December 31, 2009. The Company did not capitalize any interest during 2010.

The Company evaluates the recoverability of the carrying amount of long-lived assets (including property and equipment) whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. The Company evaluates events or changes in circumstances based on historical operating results, business plans, general and industry trends and forecasted cash flows. Impairment is assessed when the undiscounted expected future cash flows derived from an asset are less than its carrying amount. Impairment losses are measured as the amount by which the carrying value of an asset exceeds its fair value. No long-lived asset impairment charges were recorded during 2010, 2009 or 2008.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Interest Rate Swap

The interest rate swaps are recorded at fair value and are included in the accompanying balance sheets as “Derivative financial instruments.” Changes in the fair value of the interest rate swap (net of settlements) are reported in current period earnings since the interest rate swap was not designated as a cash flow hedge (see Note 5).

Deferred Financing Costs

Costs incurred in connection with the acquisition of financing for the facility were deferred and amortized over the term of the respective financing using the effective interest method. Accumulated amortization was approximately $419,000 and $139,000 at December 31, 2010 and 2009, respectively. Future amortization of deferred financing costs is as follows (amounts in thousands):

Years Ended December 31,		Amortization
2011		$	309
2012			277
2013			239
2014			154
Total		$	979

Inventory

Inventories are stated at the lower of cost or market using the first-in, first-out method. Inventory includes direct production costs and certain overhead costs, such as depreciation, property taxes, and utilities related to producing ethanol and related by-products. Reserves are established, if necessary, for obsolescence and estimated net realizable value based upon recent commodity prices. No reserves were recorded at December 31, 2010 and 2009. The components of inventory are as follows (amounts in thousands):

		December 31,				December 31,
		2010				2009
Ethanol and other finished goods		$	2,347			$	1,558
Work in process			1,705				1,235
Grain and other raw materials			3,767				3,497
Total		$	7,819			$	6,290

Revenue Recognition

The Company recognizes sales from the production of ethanol and distillers grains when title transfers to customers, upon shipment from the Company’s plant. Shipping and handling charges to ethanol customers are included in revenues. Revenues by product are as follows (amounts in thousands):

		Year Ended December 31,				Year Ended December 31,
		2010				2009
Ethanol		$	194,860			$	83,402
Dried distillers grains			39,429				14,705
Other			256				83
Total		$	234,545			$	98,190

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Cost of Sales

Cost of sales includes depreciation, costs of raw materials, inbound freight charges, purchasing and receiving costs, inspection costs, shipping costs, other distribution expenses, warehousing costs, plant management, certain compensations costs and general facility overhead charges.

Selling, General and Administrative Expenses

The Company includes non-production related costs such as professional fees and certain payroll in selling, general and administrative expenses.

Income Taxes

The Company is organized as a limited liability company. This provides that in lieu of corporation income taxes, the members are to account separately for their proportionate share of the Company’s items of income, deductions, losses, and credits. Therefore, these financial statements do not include a provision for federal income taxes.

The Company is required to file and pay Illinois taxes at a rate of 1.5% of adjusted taxable income, which approximates federal taxable income. This tax is not passed on to members. No income taxes were paid during 2010, 2009 or 2008.

Impact of New Accounting Pronouncements

Effective July 1, 2009, the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) became the single official source of authoritative, nongovernmental accounting principles generally accepted in the United States of America (GAAP). The historical GAAP hierarchy was eliminated and the ASC became the only level of authoritative GAAP. The Company’s accounting policies were not affected by the conversion to ASC.

In September 2006, the FASB issued a new accounting standard regarding the accounting for fair value measurements and disclosures. This standard defines the fair value of financial and nonfinancial assets and liabilities, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This standard applies to fair value measurements that are already required or permitted by existing standards except for measurements of share-based payments and measurements that are similar to, but not intended to be, fair value and eliminates the Emerging Issues Task Force guidance that prohibited recognition of gains or losses at the inception of derivative financial instrument transactions whose fair value is estimated by applying a model. This standard clarifies that fair value is the amount that would be exchanged to sell an asset or transfer a liability, in an orderly transaction between market participants. This standard is effective for the Company’s year ended December 31, 2008. On November 14, 2007, the FASB approved to defer the effective date for all nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008. The Company adopted this guidance, as it relates to nonfinancial assets and liabilities as of January 1, 2009 (see Note 6).

In March 2008, the FASB issued a new accounting standard regarding the accounting for derivatives and hedging. This standard requires, among other things, enhanced disclosure about the volume and nature of derivative and hedging activities and a tabular summary showing the fair value of derivative instruments included in the statement of financial position and statement of operations. This standard also requires expanded disclosure of contingencies included in derivative instruments related to credit risk. This guidance is effective for the Company’s year ended December 31, 2009. The adoption of this standard did not have a material effect on the Company’s financial statements other than providing certain enhanced disclosures (see Note 5).

Net Income or Loss per Unit

Basic net income or loss per unit is computed by dividing net income or loss by the weighted average number of members’ units outstanding during the period. Diluted net income or loss per unit is computed by dividing net income or loss by the weighted average number of members’ units and members’ unit equivalents outstanding during the period. There were no member unit equivalents outstanding during the periods presented; accordingly, the Company’s basic and diluted net income or loss per unit are the same.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Comprehensive Income (Loss)

For all periods presented, net income (loss) equals comprehensive income (loss) as the Company had no income or expense items that were not reported on the statements of operations.

2. PROPERTY AND EQUIPMENT

In May 2007, the Company entered into an agreement with Fagen, Inc. (“Fagen”), the designer/builder of the Company’s fuel ethanol plant (the “Plant”). Fagen was responsible for all engineering, labor, materials, and equipment to design, construct, startup, and achieve guaranteed performance criteria of the Plant. The contract price was $120 million, subject to adjustments as provided by the general conditions of the agreement. Construction of the plant began in October 2007, and was substantially completed in July 2009. See Note 7 for a discussion of related-party transactions. A summary of property and equipment at December 31, 2010 and 2009, is as follows (amounts in thousands):

		2010				2009
Land and land improvements		$	14,502			$	14,317
Plant and equipment			117,631				117,442
Buildings			21,251				21,237
Office equipment			593				519
Construction in process			4,520				24
Gross property and equipment			158,497				153,539
Less: accumulated depreciation			(14,366	)			(4,830	)
Net property and equipment		$	144,131			$	148,709

3. MEMBERS’ EQUITY

The Company has one class of membership units, which include certain transfer restrictions as specified in the operating agreement and pursuant to applicable tax and securities laws. Income and losses are allocated to all members based upon their respective percentage of units held. In February 2006, the Company raised $1,425,000 from five seed capital investors in exchange for 855 Class A units. The Company filed a Form SB-2 Registration Statement with the Securities and Exchange Commission (“SEC”). The original offering was for a minimum of 6,020 Class B units and up to 12,020 Class B units at $5,000 per unit for minimum offering proceeds of $30,100,000 and maximum offering proceeds of $60,100,000, before any costs of raising capital. The registration became effective November 7, 2006.

In June 2007, the Company filed an amendment to its Form SB-2 Registration Statement with the SEC. The new offering was for a minimum of 12,891 units and up to 14,000 units at $5,000 per unit for minimum offering proceeds of $64,455,000 and maximum offering proceeds of $70,000,000, before any costs of raising capital. As a result of the amendments to the amended and restated operating agreement as required by the Farmers Energy agreement (discussed below), the separate classes of units were eliminated and the Company now has one class of units.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

In May 2007, the Company entered into an agreement with Farmers Energy, a subsidiary of REX American Resources Corporation, whereby Farmers Energy agreed to purchase a minimum of 7,011 units for a minimum purchase price of $35,055,000 and a maximum of 12,491 units for a maximum purchase price of $62,455,000. The actual number of units purchased by Farmers Energy was dependent upon the number and amount of rescissions resulting from a rescission offer, as described below, and the total number of new subscribers. Farmers Energy has the right to appoint a majority of the board members of the Company and has the majority vote regardless of the number of board members.

In July 2007, The Company conducted a rescission offer with the current subscribers due to the Company changing the terms of the initial public offering. A total of 171 subscribers with 2,602 units chose to withdraw their subscriptions and have their deposits returned totaling $1,330,500, plus interest. On October 31, 2007, after meeting the terms of the escrow agreement, the Company terminated its escrow account and the offering proceeds were released to the Company. The Company closed the public offering on November 7, 2007. As of December 31, 2010 and 2009, the Company had issued 13,781 units totaling $66,055,000 ($65,214,000 net of issuance costs). Through December 31, 2010, the Company had not made any distributions to members for income tax payments or other purposes.

4. LONG-TERM DEBT

In September 2007, the Company entered into an $111,000,000 financing agreement consisting of a construction loan agreement for $100,000,000 together with a $10,000,000 revolving loan and a $1,000,000 letter of credit with First National Bank of Omaha (the “Bank”). The construction loan was converted into a term loan on July 31, 2009, and bears interest at rates ranging from London InterBank Offered Rate (LIBOR), plus 300 basis points to LIBOR, plus 310 basis points. The term loan is secured by all of the Company’s assets. Pursuant to the terms of the loan agreement with the Bank, the Company has certain restrictions on its distributions to members based upon taxable income and net income in a given period. The Company’s restricted net assets total approximately $81.2 million and $66.0 million at December 31, 2010 and 2009, respectively. Such net assets may not be paid in the form of dividends or advances to members per the terms of the loan agreement with the Bank.

Beginning with the first quarterly payment on October 8, 2009, payments are due in 19 equal quarterly payments of principal and accrued interest, with the principal portion calculated based on a 120-month amortization schedule. One final installment will be required on the maturity date, July 8, 2014, for the remaining unpaid principal balance with accrued interest.

The term loan is secured by all property of the Company, regardless of date acquired. As of December 31, 2010 and 2009, approximately $78,700,000 and $98,000,000, respectively, was outstanding on the term loan. The Company is also subject to certain financial covenants under the loan agreement, including required levels of Earnings Before Interest, Taxes, Depreciation, and Amortization, debt service coverage ratio requirements, net worth requirements, and other common covenants. The Company was in compliance with all covenants at December 31, 2010 and 2009.

The Company paid approximately $1,398,717 to the Bank and other parties since inception for various fees associated with the construction and term loan commitment. These amounts were recorded as deferred financing costs by the Company in the accompanying balance sheets; such amounts are amortized using the effective interest method, beginning with the first payment on the term loan and ending with the term loan maturity date. The carrying values of the construction loan and term loan approximate fair value at December 31, 2010 and 2009. In accordance with the agreement, the Company entered into an interest rate swap contract to minimize its interest risk exposure (see Note 5).

Annual expected maturities on notes payable at December 31, 2010, are as follows (amounts in thousands):

Years Ended December 31,		Maturities
2011		$	9,672
2012			10,847
2013			11,312
2014			46,890
Total		$	78,721

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

The Company has no outstanding borrowings on the $10,000,000 revolving loan as of December 31, 2010 and 2009.

The Company has issued letters of credit that total approximately $280,000 and $543,000 as of December 31, 2010 and 2009, respectively. The maximum amount borrowed under the revolving loan in 2009 was $2,000,000. The Company did not borrow any funds under the revolving loan in 2010.

The Company also has access to a secondary line of credit of up to $10,000,000 with the Bank, established as part of the original $100,000,000 term loan and made accessible as a revolving line of credit as term loan payments were made. The amount available is reduced by $250,000 on a quarterly basis. At December 31, 2010 and 2009, the Company had $8,750,000 and $10,000,000, respectively, available on this revolving line of credit. The Company has no outstanding borrowings on the secondary line of credit as of December 31, 2010 and 2009.

5. FINANCIAL INSTRUMENTS

The Company uses derivative financial instruments to manage the balance of fixed- and variable-rate debt. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Interest rate swap agreements involve the exchange of fixed- and variable-rate interest payments and do not represent an actual exchange of the notional amounts between the parties. The swap agreements were not designated for hedge accounting pursuant to accounting standards.

The Company entered into a forward interest rate swap with First National Bank of Omaha in the notional amount of $50 million during 2007 and in the notional amount of $25 million during 2008. The swaps fixed the interest rate on $50 million and $25 million of the term loan at 7.9% and 5.49%, respectively. The 2007 swap was effective as of December 11, 2007, swap settlements commenced as of July 31, 2009, and the termination date is July 8, 2014. The 2008 swap was effective as of December 11, 2008, swap settlements commenced as of July 31, 2009, and the termination date is July 31, 2011. During 2010 and 2009, swap settlement payments to the counterparty totaled approximately $2,726,000 and $551,000, respectively.

At December 31, 2010 and 2009, the Company recorded a liability of approximately $5.5 million and approximately $5.2 million, respectively, related to the fair value of the swaps. The Company believes the risk of nonperformance by the counterparty with this agreement is not material to the financial statements.

The notional amounts and fair values of derivatives, all of which are not designated as cash flow hedges at December 31, 2010 and 2009 are summarized in the table below (amounts in thousands):

		Notional Amount				Fair Value Liability
Interest rate swaps - 2010		$	68,138			$	5,523
Interest rate swaps - 2009		$	73,649			$	5,231

As the interest rate swaps are not designated as cash flow hedges, the unrealized gain and loss on the derivatives is reported in current earnings and is included in gains or losses on derivative financial instruments. The Company reported losses of approximately $3,018,000, $219,000, and $4,704,000 in 2010, 2009, and 2008, respectively.

6. FAIR VALUE

The Company applies the accounting standard which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

The Company determines the fair market values of its financial instruments based on the fair value hierarchy established in the accounting standards which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standards describe three levels of inputs that may be used to measure fair values which are provided below. The Company carries derivative liabilities at fair value.

Level 1 — Quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities include debt and equity securities and derivative contracts that are traded in an active exchange market, as well as certain U.S. Treasury securities that are highly liquid and are actively traded in over-the-counter markets.

Level 2 — Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Level 2 assets and liabilities include derivative contracts whose value is determined using a pricing model with inputs that are observable in the market or can be derived principally or corroborated by observable market data.

Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methods, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation. Unobservable inputs shall be developed based on the best information available, which may include the Company’s own data.

The fair values of derivative assets and liabilities traded in the over-the-counter market are determined using quantitative models that require the use of multiple market inputs, including interest rates, prices, and indices to generate pricing and volatility factors, which are used to value the position. The predominance of market inputs are actively quoted and can be validated through external sources, including brokers, market transactions, and third-party pricing services. Estimation risk is greater for derivative asset and liability positions that are either option based or have longer maturity dates where observable market inputs are less readily available or are unobservable, in which case interest rate, price, or index scenarios are extrapolated in order to determine the fair value. The fair values of derivative assets and liabilities include adjustments for market liquidity, counterparty credit quality, the Company’s own credit standing, and other specific factors, where appropriate. Financial liabilities measured at fair value at December 31, 2010, on a recurring basis are summarized below (amounts in thousands):

														Total Fair
		Level 1				Level 2				Level 3				Value
Derivative liabilities		$	—			$	5,523			$	—			$	5,523

Financial liabilities measured at fair value on a recurring basis at December 31, 2009 are summarized below (amounts in thousands):

														Total Fair
		Level 1				Level 2				Level 3				Value
Derivative liabilities		$	—			$	5,231			$	—			$	5,231

No other financial instruments or non-financial assets or liabilities were measured at fair value in accordance with the accounting standards.

7. RELATED-PARTY TRANSACTIONS

The Company entered into a design-build contract with Fagen, an equity investor in the Company, for the design and construction of the ethanol plant. The Company paid approximately $120.2 million through December 31, 2009, to Fagen for the design-build contract. Additionally, the Company paid Fagen approximately $7.9 million for the year ended December 31, 2009, for additional projects related to the construction of the plant.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

During 2010 and 2009, the Company purchased approximately $157.4 and $69.2 million, respectively, of corn from the Alliance Grain Elevator (“Alliance Grain”), an equity investor.

The Company leases land from a related party on which it has constructed water wells. The lease allows the Company to use the land for 99 years. Annual payments of $20,000 are due the first day of each calendar year through January 1, 2011. One final payment of $19,000 is due January 1, 2012.

During 2010 and 2009, the Company used the services of the Bloomer Line to move railcars to ship ethanol. An officer of the Company is the acting general manager of the Bloomer Line. The Company paid the Bloomer Line approximately $340,000 and approximately $104,000 for such services in 2010 and 2009, respectively.

8. COMMITMENTS AND CONTINGENCIES

The Company has forward purchase contracts for 4.9 million bushels of corn, the principal raw material for its ethanol plant. The Company expects to take delivery of the corn by March and April 2011.

The Company has sales commitments for 6,282,000 gallons of ethanol and 29,186 tons of distillers grains. The Company expects to deliver the ethanol and the distillers grains by March 2011.

Forward grain purchase, ethanol and distillers grains sale contracts are accounted for under the “normal purchases and normal sales” scope exemption of the accounting standards because these arrangements are for purchases of grain and sales of ethanol and distillers grains that will be delivered in quantities expected to be used by the Company over a reasonable period of time in the normal course of business.

The Company entered into an agreement with an unrelated party for the construction of a substation and ancillary equipment necessary to provide electric distribution service. The Company paid $1,150,000 at the signing of the agreement on January 18, 2008, and pays monthly payments of no less than $6,800 which are included in the invoice as delivery service. The agreement is secured by an irrevocable standby letter of credit, which may be reduced annually by the actual or calculated delivery service payments.

The Company has entered into an agreement with an unrelated party for the use of a portion of the party’s natural gas pipeline. The term of the agreement is 10 years, and the amount is $4,380,000, which is spread over 120 equal payments of $36,500. Payments began in February 2009.

The Company has entered into an agreement with an unrelated party for the lease of railcars that will be used to ship ethanol. The lease is set to expire on May 31, 2012, with an automatic 36-month extension, unless either party notifies the other in writing 60 days prior to the initial expiration date. The Company pays a monthly lease amount per railcar. The Company paid approximately $662,000 and $344,000 pursuant to the lease in 2010 and 2009, respectively.

The Company has a nonexclusive contract with an unrelated party (“Ethanol Marketer”) for ethanol marketing services. Under the terms of the contract, the Ethanol Marketer will purchase some of the Company’s ethanol production during the term of the contract. Additionally, the Ethanol Marketer is also required to share with the Company the additional profits derived from the Ethanol Marketer’s gains on swaps and exchanges. The contract initial term ends December 1, 2012, with automatic renewals for one year, unless the Company provides written notice of at least 90 days prior to the end of the initial term.

The Company has a contract with an unrelated party (“Distillers Grains Marketer”) for distillers grains marketing services. Under the terms of the contract, the Distillers Grains Marketer will purchase all of the Company’s distillers grain production during the term of the contract. The contract called for the Company to pay a fee per ton of distillers grains for the Distillers Grains Marketer’s services. The contract was amended on December 6, 2010, to reduce the fee for dried distillers grains, and the termination date was extended to July 1, 2014. The Company paid approximately $905,000 and $408,000 in 2010 and 2009, respectively, for these marketing services.

ONE EARTH ENERGY, LLC
NOTES TO AUDITED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

The Company has a grain origination agreement with Alliance Grain, under which it purchased 100% of its grain during 2010. The Company pays to Alliance Grain a certain amount per bushel for procurement fees. The term of the agreement is for two years from the first grind date, and shall renew automatically for additional one year terms, unless either party sends notice to the other party of its intent to terminate the agreement at least sixty days prior to the expiration of the then current term of the agreement.

The Company is involved in various legal actions arising in the normal course of business. After taking into consideration legal counsel’s evaluation of such actions, management is of the opinion that their outcome will not have a material effect on the Company’s financial statements.

9. SUBSEQUENT EVENTS

On February 8, 2011, the Company filed a Schedule 13E-3 pursuant to which, the Company offered to purchase from certain of its members up to 86 units of its common equity for a price of $5,525 per unit. As of March 30, 2011, we received acceptances for the purchase of 30 units from members under the offering.

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

None.

ITEM 9A.		CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Management of One Earth Energy is responsible for maintaining disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. In addition, the disclosure controls and procedures must ensure that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial and other required disclosures.

At the end of the period covered by this report, an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was carried out under the supervision and with the participation of our Principal Executive Officer, Steve Kelly, and our Chief Financial Officer, Larry Brees. Based on their evaluation of our disclosure controls and procedures, they have concluded that during the period covered by this report, such disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance to our management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our 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 our transactions; (ii) provide reasonable assurance that transactions are recorded as necessary for preparation of our financial statements; (iii) provide reasonable assurance that receipts and expenditures of company assets are made in accordance with management authorization; and (iv) provide reasonable assurance that unauthorized acquisition, use or disposition of company assets that could have a material effect on our financial statements would be prevented or detected on a timely basis.

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

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. This assessment is based on the criteria for effective internal control described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, management concluded that our internal control procedures over financial reporting as of December 31, 2010 were effective.

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.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2010, we made changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. These changes have allowed us to remediate the previously disclosed material weakness described within our 2009 Form 10-K. Therein, we concluded that a material weakness existed due to the lack of a proper and timely review and reconciliation of transfers of member (investor) shares by the appropriate level of management. The Company exceeded the maximum number of investors allowable in order to continue suspension of its reporting requirements with the Securities and Exchange Commission (“SEC”). Consequently, we have implemented procedures to maintain complete and accurate documentation of the number of outstanding units owned by the Company’s investors, to perform appropriate reconciliations of all member unit activity, and to file timely periodic reports with the SEC. No other change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2010.

ITEM 9B.		OTHER INFORMATION

On December 6, 2010, we amended our distillers grain marketing agreement with UBEI, which was effective with shipments on the first day of January 2011. The amendment reduces the price UBEI will pay to One Earth for all DDGS shipped to its customers, with upper and lower limits. UBEI shall no longer give One Earth a monthly credit, and UBEI shall not be required to locate a merchandiser at One Earth’s facility. The termination date of the agreement was extended to July 1, 2014.

PART III

ITEM 10.		DIRECTORS; EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Identification of Directors, Executive Officers and Significant Employees

The following table shows the directors and officers of One Earth Energy, as of December 31, 2010:

Name		Age				Position		Address
Scott Docherty			48			Chairman/ Director		9 Fir Court Monticello, IL 61856
Joseph Thompson			51			Vice President/ Director		49 Deer Run Place Monticello, IL 61856
Jack Murray			54			Secretary / Treasurer / Director		2607 County Rd 1000E Champaign, IL 61822
Bruce Bastert			53			Director		110 Mohican Lane Loda, IL 60948
Roger Miller			57			Director		804 East Boone Street Tolono, IL 61880
Zafar Rizvi			61			Director		2875 Needmore Road Dayton, Ohio 45414
Steve Kelly			54			President/General Manager		225 E. 700 N. Road Gibson City, IL 60936

Business Experience of Directors and Officers

The following is a brief description of the business experience and background of our officers and directors, as of December 31, 2010.

Scott Docherty, Chairman and Director, Age 48. Mr. Docherty is the general manager of Topflight Grain Coop and has been since June 2004. Topflight Grain Coop is farmer-owned, with 10 facilities in 4 counties. Prior to accepting the general manager position, he was a merchandiser for Topflight Grain Coop. from 1998 until May 2004. Mr. Docherty has served as a director since our inception in 2006. Mr. Docherty’s experience as the general manager provides him with unique insights into strategic planning and the ability to identify opportunities for organizational growth.

Joseph Thompson, Vice President and Director, Age 51. Mr. Thompson has been the general manager of Alliance Grain Company, a 13 facility grain cooperative with annual net sales of approximately $260 million, since September 1, 2007. As general manager, Mr. Thompson supervises the day-to-day operations of the cooperative facilities. From June 1999 to September 1, 2007, Mr. Thompson served as Alliance’s controller and was responsible for monthly management financial statements presentations, reconciliation of general ledger accounts and implementation of general financial recording practices. He was the Ag Finance Manager for Piatt Service from May 1995 to June 1999. Mr. Thompson’s experience with Alliance provides invaluable insight into the grain industry and guidance for the board’s understanding and implementation of sound financial reporting and practices. Mr. Thompson has also served as a director of Bloomer Shipper Railway Redevelopment League from September 2007 to the present. Mr. Thompson received his bachelor of science in accounting from Illinois College in Jacksonville, Illinois. Mr. Thompson has served as a Company director since January 2008.

Jack Murray, Secretary / Treasurer and Director, Age 54. Mr. Murray has run Murray Farms, Inc., a farming operation in Champaign, IL, and has done so since May of 1976, serving as the company’s president. Since August 2009, Mr. Murray has served as Premier Cooperative, Inc.’s president. He previously served as president of the Fisher Farmers Grain & Coal Co., having served on that board for a total of nineteen years. Mr. Murray has served as a Company director since our inception. Mr. Murray’s knowledge of the local agricultural economy and experience as an entrepreneur brings a valuable perspective to the Board.

Bruce Bastert, Director, Age 53. Mr. Bastert is the general manager of Ludlow Cooperative Elevator Company, a cooperative grain company with 11 facilities in Buckley, Clarence, Danforth, Del Rey, Gilman, La Hogue, Loda, Ludlow, Paxton, Purdueville, and Piper City, Illinois. Before his appointment as Ludlow’s general manager in March 2006, Mr. Bastert was general manager of Williamsville Farmers Cooperative from May 1999 through February 2006. In both positions, Mr. Bastert performed chief executive functions associated with grain handling operations and hedging functions for customer accounts. Previously he has worked in the grain industry as general manager, commodity risk management consultant, terminal manager, merchandiser and in corn origination, risk management, logistics, and co-product sales. His knowledge of commodity risk and merchandising make him a valuable addition to the Board. Mr. Bastert is an Agricultural Industries graduate of the University of Illinois. Mr. Bastert has been a director since March 2006.

Roger Miller, Director, Age 57. Mr. Miller has served as general manager of Premier Cooperative, Inc. since 1993. This agricultural business is a licensed grain dealer and warehouse that handles corn, soybeans and wheat in East-Central Illinois. Premier has twenty locations in Champaign and Piatt Counties. At Premier, Mr. Miller is responsible for the operational direction of Premier’s twenty facilities and supervision of 72 full-time employees. His knowledge of the local agricultural community combined with his experience in managing multiple locations adds much value to the Board. Mr. Miller has served as a director of the Company since February 2006.

Zafar Rizvi, Director, Age 61. Zafar Rizvi has served as Vice President of REX American Resources Corporation (NYSE: REX), our parent company, and President of Farmers Energy Incorporated, REX’s alternative energy investment subsidiary, since 2006. From 1991 through 2006, Mr. Rizvi served as REX’s Vice President of Loss Prevention. Prior to such dates, Mr. Rizvi was employed in the video retailing industry in a variety of management positions. Mr. Rizvi also serves on the board of directors of several developmental stage, non-reporting ethanol companies. Mr. Rizvi holds a B.A. in Economics from Punjab University in Pakistan, an H.N.D. in Business Studies from City of London Polytechnic in England and an M.B.A. from the University of Phoenix. His executive experience combined with his knowledge of the ethanol industry make Mr. Rizvi a valuable addition to the Board. Mr. Rizvi has been a director of One Earth Energy, LLC since June 2007.

Business Experience of Significant Employees

Steven Kelly, President/General Manager, Age 54. Mr. Kelly has been employed as our General Manager and President since September 2007. In such capacity, Mr. Kelly is responsible for overseeing and managing the day-to-day operations of the Company’s facility. Mr. Kelly also currently serves as acting general manager of Bloomer Connecting Shippers Railroad Co. Before assuming the Company’s general manager position, Mr. Kelly was the general manager of Alliance Grain Company from January 1988 to September 2007. Alliance is a locally-owned cooperative that has 13 elevators in 12 East-Central Illinois communities. Mr. Kelly served as a director of One Earth Energy from our inception until September 2007 when he was employed by the Company.

Larry Brees, Chief Financial Officer, Age 54. Larry Brees began serving as the Company’s Controller in November 2007. On September 13, 2010, the Board of Directors appointed Larry Brees to the position of Chief Financial Officer of the Registrant. As Chief Financial Officer, Mr. Brees directs the Company’s financial affairs including assumption of accounting and treasury functions alongside our treasurer, Jack Murray. Mr. Brees will continue his duties as Controller in addition to the Chief Financial Officer responsibilities. Previously, Mr. Brees served as the Chief Financial Officer for E Energy Adams and interim Controller for HON Company during 2007, as well as the Controller of Big River Resources from February 2004 through March 2007.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act of 1934 (the “Exchange Act”) requires our directors, executive officers and certain beneficial owners holding 10% or more of the Company’s membership units to file reports of ownership and changes of ownership with the Securities and Exchange Commission (the “SEC”). To our knowledge, and based solely on a review of the copies of such reports furnished to us and written representations from our officers and directors, all Section 16(a) filing requirements were complied with during 2010.

Code of Ethics

Our board of directors has adopted a Code of Ethics that sets forth standards regarding matters such as honest and ethical conduct, compliance with the law, and full, fair, accurate and timely disclosure in reports and documents that we file with the SEC and in other public communications. The Code of Ethics applies to all of our employees, officers and directors, including our President and General Manager, Steve Kelly, and Chief Financial Officer, Larry Brees. The Code of Ethics is available free of charge upon written request to One Earth Energy, LLC, 202 N. Jordan Dr., Gibson City, IL 60936.

Identification of Audit Committee

In January 2008, the board of directors appointed an Audit Committee consisting of our directors Joe Thompson, Jack Murray, Zafar Rizvi and Roger Miller. Joe Thompson is serving as the chairman of the Audit Committee. During our fiscal year ended December 31, 2010, we appointed our remaining directors to the audit committee, such that our entire board now also serves on our audit committee.

The Audit Committee met three times in 2010, in March, August, and September. All of the audit committee members attended at least 75% of the audit committee meetings held during the fiscal year ended December 31, 2010.

Audit Committee Report

The following report of the audit committee shall not be deemed to be incorporated by reference in any previous or future documents filed by the Company with the Securities and Exchange Commission under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates by reference in any such document.

The audit committee (the Committee) reviews the Company’s financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process. The Company’s independent registered public accounting firm reports directly to the Committee. The Committee reviewed and discussed with management the Company’s audited financial statements as of and for the fiscal year ended December 31, 2010. The Committee has discussed with Deloitte & Touche LLP, its independent registered accounting firm, the matters required to be discussed by Statement on Auditing Standards No. 141, as amended, by the Auditing Standards Board of the American Institute of Certified Public Accountants and as adopted by the Public Company Accounting Oversight Board (PCAOB) in Rule 3200T. The Committee has received and reviewed the written disclosures and the letter from Deloitte & Touche LLP as required by the PCAOB, and has discussed with the independent registered public accounting firm their independence. The Committee has considered whether any provision of services by Deloitte & Touche LLP not related to the audit of the financial statements and to the reviews of the interim financial statements included in the Company’s Annual Report on Form 10-K and Quarterly Reports on Form 10-Q are compatible with maintaining Deloitte & Touche LLP’s independence.

Based on the reviews and discussions referred to above, the Committee determined that the audited financial statements referred to above be included in the Form 10-K for the fiscal year ended December 31, 2010.

Audit Committee Financial Expert

Our board of directors has determined that Joe Thompson, who serves as Chairman of the Audit Committee, is an audit committee financial expert by reason of his experience in public accounting and as a controller of Alliance Grain Company. Mr. Thompson is not an independent director, as defined in NASDAQ Rule 5605(a), as discussed further in Item 13 below.

ITEM 11.		EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

The Compensation Committee has responsibility for establishing, implementing and regularly monitoring adherence to the Company’s compensation philosophy and objectives. The Compensation Committee ensures that the total compensation paid to Mr. Kelly, our principal executive officer, and Mr. Brees, our current chief financial officer, is fair, reasonable and competitive. Mr. Thompson, our previous Chief Financial Officer, did not receive any compensation in addition to his director compensation for serving in this position, discussed below in “Compensation of Named Executive Officers and Directors”.

The Compensation Committee:

	(1)		establishes and administers a compensation policy for all of our employees; and
	(2)		reviews and monitors our financial performance as it affects our compensation policies or the administration of those policies.

All of the Committee’s actions are reported to the board of directors and, where appropriate, submitted to the board of directors for ratification. In determining Mr. Brees’ and Mr. Kelly’s compensation, the Committee considers evaluations prepared by the directors. From time to time, the Compensation Committee may delegate to Mr. Kelly the authority to implement certain decisions of the Committee, to set compensation for lower officers and management employees or to fulfill administrative duties.

Compensation Philosophy and Objectives

Our compensation programs are designed to achieve the following objectives:

	(1)		Attract, retain and motivate highly qualified and talented employees who will contribute to the Company’s success by reason of their ability, ingenuity and industry;
	(2)		Link compensation realized to the achievement of the Company’s short and long-term financial and strategic goals;
	(3)		Align management and member interests by encouraging long-term member value creation;
	(4)		Maximize the financial efficiency of the compensation program from tax, accounting, cash flow and dilution perspectives; and
	(5)		Support important corporate governance principles and comply with best practices.

To achieve these objectives, the Compensation Committee implements and maintains compensation plans that tie a portion of Mr. Kelly’s and Mr. Brees’s overall compensation to the Company’s financial performance.

Compensation Committee Procedures

The Compensation Committee is responsible for determining the nature and amount of compensation for the Company’s executive officers. Our entire board of directors serves as our Compensation Committee.

The Compensation Committee receives input from Mr. Kelly on the personal performance achievements of other officers and management employees who report to him. This individual performance assessment determines a portion of the annual compensation for each officer and employee. In addition, Mr. Kelly provides input on salary increases, incentive compensation opportunities and long-term incentive grants for the officers and management employees who report to him, which the Committee considers when making compensation decisions.

The Compensation Committee annually evaluates Mr. Kelly’s and Mr. Brees’s performance in light of the goals and objectives of the Company’s compensation plans and determines and approves Mr. Kelly’s and Mr. Brees’s compensation level based on this evaluation. In determining the long-term incentive components of Mr. Kelly’s and Mr. Brees’s compensation, the Compensation Committee will consider all relevant factors, including the Company’s performance, the value of similar awards to similar officers of comparable companies and the awards given to Mr. Kelly and Mr. Brees in past years. Mr. Kelly and Mr. Brees are not present at Compensation Committee or board-level deliberations concerning their compensation.

Compensation Components

Base Salary

Base salaries for our executive officers and employees are established based on the scope of their roles, responsibilities, experience levels and performance, and taking into account competitive market compensation paid by comparable companies for similar positions. Base salaries are reviewed approximately annually, and may be adjusted from time to time to realign salaries with market levels after taking into account individual performance and experience. Following the end of our 2009 fiscal year, due to conditions in the ethanol industry and the United States economy generally, the board of directors increased Mr. Kelly’s and Mr. Brees’s base salaries to $175,000 and $81,000 respectively.

Cash Bonus

In addition to the base salaries, our Committee and board of directors approved bonuses payable to Mr. Kelly and Mr. Brees for the 2010 fiscal year. The total amount of the cash bonus for Mr. Kelly was $81,579. This was composed of the regular monthly performance bonus of $31,579, and a one-time bonus of $50,000. For our 2009 fiscal year, the total cash bonus paid to Mr. Kelly was $6,427. The increase paid in 2010 relates to the Company’s increased production and stronger financial performance. The maximum bonus amount for 2009 and 2010 was 12% and, if approved by the board, was awarded based on the number of points earned, out of a total 100 points, during any given month of operation. The number of points earned is based on the achievement of certain production/plant thresholds. The monthly points earned are then multiplied by an employee’s base wage/salary pool, with each employee earning an amount equal to the ratio of his salary to total salaries paid by the Company. Mr. Kelly is also eligible for an additional bonus of .5% to 1% of the Company’s monthly net income, as determined by our unaudited, monthly financial statements, prorated based on the ratio of his pay to total management payroll.

The total amount of the cash bonus for Mr. Brees for 2010 was $39,484, composed of the regular monthly performance bonus of $14,484, and a one-time bonus of $25,000.

All bonuses are presented to the board of directors for approval before being paid. The Company believes that the above bonuses are reasonable as they tie the bonus paid to the Company’s financial success and are easily quantified by the Company. Specifically, the cash bonuses align the goals of the members and the management employees and executive officers, as each group benefits from the Company’s financial success. Further, the net income bonus aligns the goals of management with the long- and short-term financial goals of the Company, namely to maximize net income.

Other Compensation

In addition to his salary and cash bonus for the fiscal year ending December 31, 2010, Mr. Kelly received additional compensation and perquisites which include expense reimbursement for travel, office supplies and plant equipment as well as the payment of $8,181.42 in health insurance benefits. Mr. Brees also received additional compensation and perquisites, as well as $8,181.42 in health insurance benefits.

No Pension Benefit Plan, Deferred Compensation Plan or Change of Control or Severance Agreements

We offer no pension benefit or deferred compensation plans to Mr. Kelly or Mr. Brees. Mr. Kelly and Mr. Brees do not have change of control or severance agreements, which means our board of directors retains discretion over severance arrangements if it decides to terminate Mr. Brees or Mr. Kelly.

Accounting and Tax Treatment of Awards

Neither Mr. Kelly, Mr. Brees, nor any of our officers, directors or employees receives compensation in excess of $1,000,000. Therefore the entire amount of their compensation is deductible by the Company as a business expense. Certain large executive compensation awards are not tax deductible by companies making such awards. None of our compensation arrangements are likely to reach this cap in the foreseeable future.

Executive Compensation Committee Report

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based upon this review and discussion, the Compensation Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report.

Compensation Committee
     Scott Docherty, Chairman
     Jack Murray
     Joe Thompson
     Bruce Bastert
     Roger Miller
     Zafar Rizvi

Compensation Committee Interlocks and Insider Participation

None of the members of the Compensation Committee is or has been an employee of the Company. There are no interlocking relationships between our Company and other entities that might affect the determination of the compensation of our executive officers.

Compensation of Named Executive Officers and Directors

Scott Docherty is currently serving as our chairman. Joe Thompson is serving as our Vice President and Jack Murray is our Treasurer and Secretary. Mr. Kelly is serving as our President/General Manager on a full-time basis. On September 1, 2007, we entered into an employment arrangement with Mr. Kelly related to his services as our President/General Manager. As of December 31, 2010, we paid Mr. Kelly a total of $264,337 for such services. Mr. Brees is serving as our Chief Financial Officer on a full-time basis. As of December 31, 2010, we paid Mr. Brees a total of $129,194 for such services. As of December 31, 2010, none of our directors or any officer received any stock awards, options, warrants, or other similar rights to purchase securities of the Company. No other officers received a salary or operated under an employment agreement or other compensation arrangement.

Summary Compensation Table. The following table sets forth all compensation paid or payable by the Company during the last two fiscal years to Mr. Kelly, our president and general manager, and to Larry Brees, who was appointed our chief financial officer in 2010.

Name and														All Other
Principal Position		Year				Salary				Bonus				Compensation				Total
Steve Kelly, President and General Manager			2010			$	174,577			$	81,579			$	8,181			$	264,337
Steve Kelly			2009			$	172,907			$	6,427			$	11,456			$	190,790
Larry Brees, Chief Financial Officer			2010			$	79,154			$	39,484			$	10,556			$	129,194

The following table sets forth all compensation paid or payable by the Company during the last fiscal year to our directors.

		Fees Earned or Paid				All Other
Name		in Cash				Compensation				Total
Scott Docherty		$	1,300	(1)		$	0			$	1,300
Joe Thompson		$	1,400	(2)		$	0			$	1,400
Jack Murray		$	1,000			$	0			$	1,000
Bruce Bastert		$	1,200	(3)		$	0			$	1,200
Roger Miller		$	1,300	(4)		$	0			$	1,300
Zafar Rizvi		$	1,400	(5)		$	0			$	1,400

Director Compensation Arrangements

We compensate our directors $100 per regular monthly and special board meetings they attend. We will not pay the fee if the director does not attend the regular monthly or special meeting, committee meeting or pre-approved industry and other meetings and conferences. We will also pay for mileage to and from such board functions at the standard mileage rate established from time to time by the IRS. We will continue to reimburse our officers and directors for reasonable out-of-pocket expenses incurred relating to services rendered on our behalf.

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

Security Ownership of Certain Beneficial Owners

As of December 31, 2010 we had the following persons or entities known by us to be the beneficial owners of more than 5% of the outstanding units:

Amount and Nature of

Title of Class

Name (1)

Beneficial Owner

Percent of Class

Membership Units

Farmers Energy Incorporated

10,153 units

73.67

%

Security Ownership of Management

As of December 31, 2010, our directors and officers owned membership units as follows:

				Amount and
				Nature of
		Name and Address of		Beneficial		Percent of
Title of Class		Beneficial Owner(1)		Ownership		Class
Membership Units		Steve Kelly(2)		10 units		0.07	%
Membership Units		Jack Murray(3)		226 units		1.64	%
Membership Units		Bruce Bastert		6 units		1.28	%
Membership Units		Roger Miller		5 units		0.04	%
Membership Units		Zafar Rizvi(4)		10,153 units		73.67	%
All Directors and Officers as a Group:				10,400 Units		76.70	%

We do not have any securities authorized for issuance under equity compensation plans.

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

Certain Relationships and Related Transactions

The Company’s board of directors reviews all transactions with related parties, as that term is defined in Item 404 of SEC Regulation S-K, or any transaction in which related persons have an indirect interest. The Company’s Second Amended and Restated Operating Agreement (the or our “Operating Agreement”) includes a written policy that requires that any such related party transaction be made on terms and conditions which are no less favorable to the Company than if the transaction had been made with an independent third party. Further, our Operating Agreement requires our directors to disclose any potential financial interest in any transaction being considered by the board of directors prior to voting on such matter. Since our inception, we have engaged in transactions with seven related parties. Should we engage in any such transactions in the future, all such arrangements will be analyzed and approved in accordance with the above-referenced written policies.

Alliance Grain Company

Alliance Grain Company is one of our seed capital members and pursuant to our Operating Agreement has the right to appoint one member of our board of directors. On June 27, 2007, we entered into an exchange agreement with Alliance Grain Company. Pursuant to this agreement, we exchanged approximately $2,000 and 5.0 acres of real estate located in Ford County, Illinois, for approximately 5.4 acres of real estate owned by Alliance Grain Company valued at approximately $34,000 located near our site in Ford County, Illinois.

In addition, we entered into a Grain Handling Agreement with Alliance Grain Company on February 15, 2008. Under this Agreement, Alliance has agreed to provide the Company with its annual corn requirements for the term of the Agreement. Alliance will acquire corn on the Company’s behalf on pricing terms, as determined in separate written contracts customary in the grain industry, including, without limitation, cash forward pricing arrangements. The initial term of the Agreement expired two (2) years from the effective date of the Agreement. The Agreement, however, automatically renews for one (1) year terms until (i) the Company or Alliance provides written notice to the other stating its intent to terminate (such written notice to be received no less than 60 days before the expiration of the current term); (ii) either party remains in default following its receipt of a written notice of default and the expiration of a 10-day cure period; (iii) the bankruptcy of or appointment of receivership for either party; or (iv) the mutual agreement of the parties to terminate.

If Alliance fails to deliver the corn required by the Agreement, the Company may purchase substitute corn, seek an injunction or specific enforcement, offset amounts owed to Alliance against the additional cost of substituted corn requirements and/or terminate the Agreement. Alliance may recover payments, cease delivery of corn requirements, seek an injunction or specific enforcement and/or terminate the Agreement if the Company fails to perform as required. The parties have agreed to alternative resolution of all disputes arising under the Agreement, specifically submitting to arbitration with the National Grain and Food Association, or if unavailable, the American Arbitration Association.

Farmers Energy Incorporated (FEI)

FEI is our majority member. In addition, FEI has the right to appoint up to six (6) members of our board of directors. However, regardless of the number of directors actually appointed by it, FEI has the right to a majority of the available director votes so long as it holds a majority of our membership units. FEI currently has appointed Zafar Rizvi to our board, and he has six votes as a director.

Topflight Grain Cooperative, Inc., Premier Cooperative, and Ludlow Cooperative Elevator Company.

Jack Murray, our director is a principal of Premiere Cooperative, which is a merger of the former Fisher Farmers Grain & Coal Company and Grand Prairie Coop, Inc. Additionally, our director Bruce Bastert is an owner in Topflight Grain Cooperative, Inc. and general manager of Ludlow Cooperative Elevator Company. We purchase corn from these cooperatives through our agreement with Alliances as discussed above.

Bloomer Connecting Shippers Railroad Co.

Our general manager/president, Steve Kelly, is acting general manager for Bloomer Connecting Shippers Railroad Co. On January 15, 2008, we entered into a Switching Agreement with Bloomer, granting it the non-exclusive right to perform switching services for railcars entering and exiting our Facility on the Norfolk Southern Railway and the Bloomer Shippers Railway Redevelopment League industry lead tracks. Bloomer has agreed to provide the workforce and locomotives necessary for the switching services. In consideration of these services, we have agreed to pay a fee based on a per car amount set in the Agreement and based on industry practice. We have also agreed to pay Bloomer an additional fee, to be later agreed on by the parties, for services incidental to the switching services and related to the storing of railcars at Bloomer’s Gibson City Yard for a period exceeding two weeks. Each party has agreed to indemnify the other for losses or injuries related to its own negligence and to share in any loss arising from the negligence of both parties.

The Agreement has an indefinite term, commencing on January 15, 2008 and ending upon termination, which can occur no earlier than the one (1) year anniversary of Facility operations. Thereafter, either party may terminate the Agreement with ninety (90) days’ written notice if (i) either party is in default and continues in default after thirty (30) days from the receipt of a notice of default; or (ii) Norfolk Southern Railway notifies us that Bloomer’s charges are detrimental to Norfolk’s haul business. All disputes arising under the Agreement must be submitted to the American Arbitration Association, subject to the Commercial Arbitration Rules, with the arbitrator’s decision to be final and conclusive on the parties. The expense of the arbitrator is to be shared equally by the parties, with the parties otherwise responsible for their own related costs and expenses.

Under this Agreement, the Company expended approximately $340,000 during the 2010 fiscal year. Mr. Kelly does not receive any direct financial interest from the Company’s and/or Bloomer’s participation in the Switching Agreement. However, any money paid to Bloomer under the Agreement would directly affect Bloomer’s net income and may indirectly affect Mr. Kelly’s compensation for his services as Bloomer’s general manager.

Director Independence

Our independent directors are Bruce Bastert and Roger Miller. Our directors that are not independent are Joe Thompson, Scott Docherty, Jack Murray and Zafar Rizvi. The determination of independence is made by reference to NASDAQ Rule 5605(a)(2). Under such Rule, a director is not independent if he is an executive officer or employee of the Company or otherwise has a relationship, which in the board of director’s opinion, would interfere with the ability to independently conduct his corporate responsibilities. Joe Thompson, Scott Docherty and Jack Murray are not considered independent because they are serving as our executive officers. Zafar Rizvi is not considered independent because he is a principal of our majority member FEI. While a majority of our board of directors is not independent, thereby failing the majority independence requirement of NASDAQ Rule 5605(b), the Company is not required to comply with such requirement, and instead only references these NASDAQ Rules for the sole purpose of defining independence. In making these determinations of independence, and the related determinations set forth below, the board of directors considered the related-party transactions discussed above.

Audit Committee

Our board of directors appointed an Audit Committee consisting of Bruce Bastert, Scott Docherty, Joe Thompson, Jack Murray, Zafar Rizvi and Roger Miller. The Audit Committee is exempt from independence listing standards because our securities are not listed on a national securities exchange or listed in an automated inter-dealer quotation system of a national securities association or to issuers of such securities. Nevertheless, Roger Miller and Bruce Bastert are independent within the definition of independence provided by NASDAQ Rule 5605(c)(2), which adopts the Rule 5605(a)(2) definition of independence and further requires a member to meet the criteria of independence under Exchange Act Rule 10A-3(b)(1). Roger Miller is independent under NASDAQ Rule 5605(a)(2). Further, because Roger Miller and Bruce Bastert have not accepted any consulting, advisory or other compensatory fee from the Company, or any of its subsidiaries, and is not an affiliate, he is also independent under the heightened standards of Exchange Act Rule 10A-3(b)(1). For the reasons set forth above, Jack Murray, Joe Thompson and Zafar Rizvi are not considered independent.

Compensation Committee

Jack Murray, Bruce Bastert, Roger Miller, Zafar Rizvi, Scott Docherty and Joe Thompson serve as our Compensation Committee. Bruce Bastert and Roger Miller are considered independent within the definition of independence provided by NASDAQ Rule 5605(a)(2). For the reasons set forth above, Jack Murray, Joe Thompson, Scott Docherty and Zafar Rizvi are not considered independent.

ITEM 14.		PRINCIPAL ACCOUNTANT FEES AND SERVICES

Independent Registered Public Accounting Firm

Deloitte & Touche LLP serves as our independent registered public accounting firm.

Our board of directors annually appoints the independent registered public accounting firm for the Company after receiving the Audit Committee’s recommendations, typically following the Annual Meeting. The Audit Committee has again appointed Deloitte & Touche LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2011.

Audit Fees

The aggregate fees billed by the independent registered public accounting firm to the Company for the last two fiscal years are as follows:

Category		Fiscal Year				Fees
Audit Fees(1)			2010			$	115,000
			2009			$	90,000
Tax Fees			2010			$	0
			2009			$	0