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EXCEL - IDEA: XBRL DOCUMENT - Cardinal Ethanol LLCFinancial_Report.xls
EX-32.2 - CERTIFICATION - Cardinal Ethanol LLCa322certification93011.htm
EX-32.1 - CERTIFICATION - Cardinal Ethanol LLCa321certification93011.htm
EX-10.36 - EPCO AMENDMENT - Cardinal Ethanol LLCa1036-epcoamendment.htm
EX-10.35 - MUREX AMENDMENT - Cardinal Ethanol LLCa1035-murexamendment.htm
EX-31.1 - CERTIFICATION - Cardinal Ethanol LLCa311certification93011.htm
EX-31.2 - CERTIFICATION - Cardinal Ethanol LLCa312certification93011.htm
EX-10.34 - 2012 BONUS PLAN - Cardinal Ethanol LLCa1034-2012employeeincentiv.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
x
Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 
 
 
For the fiscal year ended September 30, 2011
 
 
 
OR
 
 
o
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 
 
For the transition period from               to               .
 
 
COMMISSION FILE NUMBER 000-53036
 
CARDINAL ETHANOL, LLC
(Exact name of registrant as specified in its charter)
 
Indiana
 
20-2327916
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
1554 N. County Road 600 E., Union City, IN 47390
(Address of principal executive offices)
 
(765) 964-3137
(Registrant's telephone number, including area code)
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes     x No

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. x


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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:
Large Accelerated Filer o
Accelerated Filer  o
Non-Accelerated Filer x
Smaller Reporting Company o

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

As of March 31, 2011, the aggregate market value of the membership units held by non-affiliates (computed by reference to the most recent offering price of such membership units) was $55,335,000. There is no established public trading market for our membership units. The aggregate market value was computed by reference to the price at which membership units were last sold by the registrant ($5,000 per unit)

As of December 13, 2011, there were 14,606 membership units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
The information required in Part III of this Annual Report is incorporated herein by reference to the Company's definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days of the close of the fiscal year ended September 30, 2011.


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INDEX

 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 


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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains historical information, as well as forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance, or our expected future operations and actions. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,” “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions. These forward-looking statements are only our predictions based 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 or obtain additional equity financing we may require in the future to continue our operations;
Decreases in the price we receive for our ethanol, distiller grains and corn oil;
Our ability to satisfy the financial covenants contained in our credit agreements with our senior lender;
Our ability to profitably operate the ethanol plant and maintain a positive spread between the selling price of our products and our raw material costs;
Negative impacts that our hedging activities may have on our operations;
Ethanol and distiller grains supply exceeding demand and corresponding price reductions;
Our ability to generate free cash flow to invest in our business and service our debt;
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 our products 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;
Competition from alternative fuel additives;
Changes in interest rates or the lack of credit availability;
Changes in legislation including the Renewable Fuel Standard and VEETC;
Our ability to retain key employees and maintain labor relations;
Volatile commodity and financial markets;
Limitations and restrictions contained in the instruments and agreements governing our indebtedness; and
Elimination of the United States tariff on imported ethanol.

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

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

PART I

ITEM 1. BUSINESS

Business Development

Cardinal Ethanol, LLC is an Indiana limited liability company organized on February 7, 2005, for the purpose of raising capital to develop, construct, own and operate a 100 million gallon per year ethanol plant in east central Indiana near Union City,

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Indiana. References to “we,” “us,” “our,” “Cardinal” and the “Company” refer to Cardinal Ethanol, LLC. Since November 1, 2008, we have been engaged in the production of ethanol, distiller's grains and corn oil at the plant.

In August 2010, we obtained a new Title V air permit allowing us to increase our ethanol production to 140 million gallons compared to 110 million gallons under our previous permit. Since obtaining the new permit, we have been steadily increasing production to a level between 111 million gallons and 116 million gallons. We expect we will continue to produce at this level for the next twelve months.

Financial Information

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

The principal products we are producing at the plant are fuel-grade ethanol and distillers grains. In addition, we are extracting corn oil for sale. Raw carbon dioxide gas is another co-product of the ethanol production process. We have entered into an agreement with EPCO Carbon Dioxide Products to capture a portion of the raw carbon dioxide we produce at the plant.

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 ethanol production for operating plants at approximately 14.2 billion gallons as of November 16, 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 northeastern United States.

Approximately 82% of our revenue was derived from the sale of ethanol during our fiscal year ended September 30, 2011.

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.


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Approximately 16% of our revenue was derived from the sale of distiller's grains during our fiscal year ended September 30, 2011.

Corn Oil

In November 2008, we began separating some of the corn oil contained in our distiller's grains for sale. Corn oil sales represented approximately 2% of our revenues for our 2011 fiscal year. We anticipate continuing to fine tune the operation of our corn oil extraction equipment and we expect that it will operate more efficiently in the future. The corn oil that we produce is not food grade corn oil and therefore cannot be used for human consumption without further refining. However, corn oil can be used as the feedstock to produce biodiesel and has other industrial uses.

Carbon Dioxide

We entered into an Agreement with EPCO Carbon Dioxide Products, Inc. (“EPCO”) under which EPCO purchases a portion of the carbon dioxide gas produced at our plant. In addition, we entered into a Site Lease Agreement with EPCO under which EPCO leases a portion of our property, on which it is operating a carbon dioxide liquefaction plant. We supply to EPCO, at the liquefaction plant, carbon dioxide gas meeting certain specifications and at a rate sufficient for EPCO to produce 6.25 tons of liquid carbon dioxide per hour. EPCO pays Cardinal a contractual price per ton of liquid carbon dioxide shipped out of the liquefaction plant by EPCO. The contract rate varies based on volume thresholds.

Subsequent to our fiscal year end of September 30, 2011, we entered into a First Amendment to Carbon Dioxide Purchase and Sale Agreement which amended the EPCO Agreement. The Amendment contemplates the possible expansion of the capacity of the EPCO plant by 250 tons/day. In the event of the expansion, EPCO agrees to increase the take or pay obligation owed to Cardinal to 98,700 tons per contract year. In addition, the daily credit to which EPCO is entitled for certain downtime has been adjusted. Cardinal also agrees to supply to EPCO the additional CO2 Gas that will be required as part of the proposed expansion for $5.00 per ton for all tons supplied.

Ethanol and Distillers Grains Markets      

As described below in "Distribution of Principal Products," we market and distribute our ethanol and distillers grains through third parties. Our ethanol and distillers grains marketers make all decisions, in consultation with management, with regard to where our products are marketed. Our ethanol and distillers grains are predominately sold in the domestic market. Specifically, we ship a substantial portion of the ethanol we produce to the New York harbor. However, as domestic production of ethanol, distillers grains and corn oil continue to expand, we anticipate increased international sales of our products. Currently, the United States ethanol industry exports a significant amount of distillers grains to Mexico, Canada and China. Management anticipates that demand for distillers grains in the Asian market may continue to increase in the future as distillers grains are used in animal feeding operations in China. We anticipate that ethanol exports will remain steady.

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

Distribution of Principal Products

Our ethanol plant is located near Union City, Indiana in Randolph County. We selected the site because of its location to existing ethanol consumption and accessibility to road and rail transportation. Our site is in close proximity to rail and major highways that connect to major population centers such as Indianapolis, Cincinnati, Columbus, Cleveland, Toledo, Detroit, New York and Chicago.

Ethanol Distribution

We entered into an Ethanol Purchase and Sale Agreement with Murex, N.A., Ltd. ("Murex") for the purpose of marketing and distributing all of the ethanol we produce at the plant. The initial term of the agreement is five years commencing on the date of first delivery of ethanol with automatic renewal for one year terms thereafter unless otherwise terminated by either party. During fiscal year 2009, we extended our Agreement with Murex to include an additional three years and the commission was increased from 0.90% to 1.10% of the purchase price, net of all resale costs, in exchange for reducing the payment terms from 20 days to 7 days after shipment. The amended agreement allowed us to revert back to the original payment terms and commission amount. We elected to revert back to the original terms during fiscal year 2010. The agreement may be terminated due to the insolvency or intentional misconduct of either party or upon the default of one of the parties as set forth in the agreement. Under the terms

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of the agreement, Murex markets all of our ethanol unless we choose to sell a portion at a retail fueling station owned by us or one of our affiliates. Murex pays to us the purchase price invoiced to the third-party purchaser less all resale costs, taxes paid by Murex and Murex's commission. Murex has agreed to purchase on its own account and at market price any ethanol which it is unable to sell to a third party purchaser. Murex has promised to use its best efforts to obtain the best purchase price available for our ethanol. In addition, Murex has agreed to promptly notify us of any and all price arbitrage opportunities. Under the agreement, Murex is responsible for all transportation arrangements for the distribution of our ethanol.
Subsequent to our fiscal year end September 30, 2011, we entered into an Amendment No. 2 to the Murex Agreement. In the Amendment, Murex agrees to a maximum commission of $1,750,000 for any one-year period beginning on November 18th and ending on November 17th and to a pro rata calculation of the maximum commission for November 1, 2011 through November 17, 2011. In addition, we agreed to extend the initial term to an eleven year period.
Distillers Grains Distribution
We have entered into an agreement with CHS, Inc. to market all our distillers grains we produce at the plant. CHS, Inc. is a diversified energy, grains and foods company owned by farmers, ranchers and cooperatives. CHS, Inc. provides products and services ranging from grain marketing to food processing to meet the needs of its customers around the world. We receive a percentage of the selling price actually received by CHS, Inc. in marketing our distillers grains to its customers. The initial term of our agreement with CHS, Inc. was for one year commencing as of November 1, 2008. Thereafter, the agreement will remain in effect unless otherwise terminated by either party with 120 days notice. Under the agreement, CHS, Inc. will be responsible for all transportation arrangements for the distribution of our distillers grains.
New Products and Services

As discussed above, we have entered into an Agreement with EPCO Carbon Dioxide Products, Inc. (“EPCO”) under which EPCO purchases the carbon dioxide gas produced at our plant. We supply to EPCO, carbon dioxide gas meeting certain specifications and at a rate sufficient for EPCO to produce 6.25 tons of liquid carbon dioxide per hour. EPCO pays us per ton of liquid carbon dioxide shipped out of the liquefaction plant by EPCO.

Federal Ethanol Supports and Governmental Regulation

Federal Ethanol Supports

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

The RFS for 2011 was approximately 14 billion gallons, of which corn based ethanol could be used to satisfy approximately 12.6 billion gallons. The RFS for 2012 is approximately 15.2 billion gallons, of which corn based ethanol can be used to satisfy approximately 13.2 billion gallons. Current ethanol production capacity exceeds the 2012 RFS requirement which can be satisfied by corn based ethanol.

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

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of a renewable fuel under the RFS program. Our ethanol plant was grandfathered into the RFS due to the fact that it was constructed prior to the effective date of the lifecycle green house gas requirement and is not required to prove compliance with the lifecycle green house gas reductions. Many in the ethanol industry are concerned that certain provisions of RFS2 as adopted may disproportionately benefit ethanol produced from sugarcane. This could make sugarcane based ethanol, which is primarily produced in Brazil, more competitive in the United States ethanol market. If this were to occur, it could reduce demand for the ethanol that we produce.
 
Most ethanol that is used in the United States is sold in a blend called E10. E10 is a blend of 10% ethanol and 90% gasoline. E10 is approved for use in all standard vehicles. Estimates indicate that gasoline demand in the United States is approximately 135 billion gallons per year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.5 billion gallons per year. This is commonly referred to as the “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 being used in the United States and it discounts the possibility of additional ethanol used in higher percentage blends such as E85 used in flex fuel vehicles. Many in the ethanol industry believe that we reached this blending wall in 2011, since the RFS requirement for 2011 is 14 billion gallons, much of which will come from ethanol. The RFS requires that 36 billion gallons of renewable fuels must be used each year by 2022, which equates to approximately 27% renewable fuels used per gallon of gasoline sold. In order to meet the RFS mandate and expand demand for ethanol, management believes higher percentage blends of ethanol must be utilized in standard vehicles.

The United States Environmental Protection Agency allows the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2007 and later. Recently, the EPA allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2007 and later as well as for cars and light duty trucks manufactured in the model years between 2001 and 2006. Management believes that many gasoline retailers will refuse to provide E15 due to the fact that not all standard vehicles will be allowed to use E15 and due to the labeling requirements the EPA may impose. The EPA is considering instituting labeling requirements associated with E15 which may unfairly discourage consumers from purchasing E15. Additionally, according to EPA estimates, flex-fuel vehicles make up only 7.3 million of the 240 million vehicles on the nation's roads and there are only about 2,000 E85 pumps in the United States. As a result, the approval of E15 may not significantly increase demand for ethanol. In addition to E15, the ethanol industry is pushing the use of an intermediate blend of 12% ethanol and 88% gasoline called E12. Management believes that E12 may be more beneficial to the ethanol industry than E15 because many believe that E12 could be approved for use in all standard vehicles. Management believes this will make it easier for retailers to supply E12 compared to E15, unless E15 is approved for use in all standard vehicles. Two lawsuits were filed on November 9, 2010, by representatives of the food industry and the petroleum industry challenging the EPA's approval of E15. It is unclear what effect these lawsuits will have on the implementation of E15 in the United States retail gasoline market.

The ethanol industry is currently impacted by the Volumetric Ethanol Tax Credit (VEETC) which is frequently referred to as the blenders' credit. This blenders' credit provides a tax credit of 45 cents per gallon of ethanol that is blended with gasoline. This incentive is scheduled to expire on December 31, 2011. Management anticipates that VEETC will not be renewed and therefore will not be available starting January 1, 2012. Management believes that the expiration of VEETC will not have a significant effect on ethanol demand provided gasoline prices remain high and the renewable fuels use requirement of the Federal Renewable Fuels Standard (RFS) is maintained. The RFS requires that a certain amount of renewable fuels must be used in the United States each year. However, if the RFS is repealed, ethanol demand may be significantly impacted. Recently, there have been proposals in Congress to reduce or eliminate the RFS. Management does not believe that these proposals will be adopted in the near future. However, if the RFS is reduced or eliminated and the blenders' credit is allowed to expire, the market price and demand for ethanol will likely decrease which could negatively impact our financial performance.

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

United States ethanol production is currently benefited by a 54 cent per gallon tariff imposed on ethanol imported into the United States. However, the 54 cent per gallon tariff is set to expire at the end of the 2011 calendar year. Elimination of the

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tariff could lead to the importation of ethanol produced in other countries, especially in areas of the United States that are easily accessible by international shipping ports. Ethanol imported from other countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably.

Effect of Governmental Regulation

The government's regulation of the environment changes constantly. We are subject to extensive air, water and other environmental regulations and we have been required to obtain a number of environmental permits to construct, expand and operate the plant. It is possible that more stringent federal or state environmental rules or regulations could be adopted, which could increase our operating costs and expenses. It also is possible that federal or state environmental rules or regulations could be adopted that could have an adverse effect on the use of ethanol. For example, changes in the environmental regulations regarding the required oxygen content of automobile emissions could have an adverse effect on the ethanol industry. Plant operations are governed by the Occupational Safety and Health Administration (“OSHA”). OSHA regulations may change such that the costs of operating the plant may increase. Any of these regulatory factors may result in higher costs or other adverse conditions effecting our operations, cash flows and financial performance.

We have obtained all of the necessary permits to operate the plant. In the fiscal year ended September 30, 2011, we incurred costs and expenses of approximately $105,000 complying with environmental laws. Although we have been successful in obtaining all of the permits currently required, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources in complying with such regulations.

Competition

We are in direct competition with numerous ethanol producers, many of whom have greater resources than we do. Following the significant growth during 2005 and 2006, the ethanol industry has grown at a much slower pace. As of November 16, 2011, the Renewable Fuels Association estimates that there are 209 ethanol production facilities in the U.S. with capacity to produce approximately 14.7 billion gallons of ethanol and another 8 plants under expansion or construction with capacity to produce an additional 271 million gallons. However, the Renewable Fuels Association estimates that approximately 3.6% of the ethanol production capacity in the United States is currently idled. This is down from 2009 when the idled capacity may have been as high as 20%. 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. The ethanol industry is continuing to consolidate where a few larger ethanol producers are increasing their production capacities and are controlling a larger portion of the United States ethanol production. The largest ethanol producers include Archer Daniels Midland, Green Plains Renewable Energy, POET and Valero Renewable Fuels each of which are capable of producing significantly more ethanol than we produce.

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

U.S. FUEL ETHANOL PRODUCTION CAPACITY
BY TOP PRODUCERS
Producers of Approximately 400
million gallons per year (mmgy) or more

Company
Current Capacity
(mmgy)

 

Under Construction/
Expansions
(mmgy)
 

Archer Daniels Midland
1,750.0


POET Biorefining
1,629.0


Valero Renewable Fuels
1,130.0


Green Plains Renewable Energy
740.0


Aventine Renewable Energy, LLC
460.0



Updated: November 16, 2011

We also anticipate increased competition from renewable fuels that do not use corn as the feedstock. Many of the current ethanol production incentives are designed to encourage the production of renewable fuels using raw materials other than corn.

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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.

At the end of 2008, VeraSun Energy filed for Chapter 11 Bankruptcy following significant losses it experienced on raw material derivative positions it had in place. VeraSun's ethanol plants were auctioned during the Chapter 11 Bankruptcy process and a significant number of these plants were purchased by Valero Energy Corporation which is a major gasoline refining company. The purchase by Valero Energy represents the first major oil company that has taken a stake in ethanol production infrastructure. Further, now Valero Energy controls its own supply of ethanol that can be used to blend at its gasoline refineries. Should other oil companies become involved in the ethanol industry, it may be increasingly difficult for us to compete. While we believe that we are a low cost producer of ethanol, increased competition in the ethanol industry may make it more difficult to operate the ethanol plant profitably.

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.

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 more than 29 million metric tons of distillers grains in 2009/2010 and will produce an estimated 31 million metric tons in 2010/2011. The amount of distillers grains produced is expected to increase as ethanol production 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

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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 fed locally to livestock or exported for feeding or processing and/or overseas export sales.

We have entered into a Corn Feedstock Supply Agency Agreement with Bunge North America, Inc. (Bunge). The purpose of the agreement is to set out the terms upon which Bunge 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, Bunge provides two grain originators 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. In return for providing these services, Bunge receives an agency fee which is equal to a set monthly amount for the first two years. In the following years, the agency fee shall be equal to an amount per bushel of corn delivered subject to an annual minimum amount. We may also directly procure corn to be used for our feedstock. The initial term of the agreement is for five years to automatically renew for successive three-year periods unless properly terminated by one of the parties. The parties also each have the right to terminate the agreement in certain circumstances, including, but not limited to, material breach by, bankruptcy and insolvency of, or change in control of, the other party.
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.

We may need to truck or rail in some of our corn feedstock, which additional transportation costs may reduce our profit margins.

On November 9, 2011, the United States Department of Agriculture (“USDA”) released its Crop Production report, which estimated the 2011 grain corn crop at 12.3 billion bushels. The November 9, 2011 estimate of the 2011 corn crop is approximately 7% lower than the record set in 2009 of 13.2 billion bushels, but if realized would be the fourth largest production total on record. Corn prices rose slightly in July through September of 2011. We expect continued volatility in the price of corn, which could significantly impact our costs of goods sold.

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.

In an attempt to minimize the effects of the volatility of corn costs on operating profits, we take hedging positions in corn futures markets. Hedging means protecting the price at which we buy corn and the price at which we will sell our products in the future. It is a way to attempt to reduce the risk caused by price fluctuation. The effectiveness of hedging activities is dependent upon, among other things, the cost of corn and our ability to sell sufficient amounts of ethanol and distillers grains to utilize all of the corn subject to the futures contracts. Hedging activities can result in costs to us because price movements in grain contracts are highly volatile and are influenced by many factors beyond our control. These costs may be significant.

Risk Management Services

We entered into a Risk Management Agreement with John Stewart & Associates ("JS&A") under which JS&A provides risk management and related services pertaining to grain hedging, grain pricing information, aid in purchase of grain, and assistance in risk management as it pertains to ethanol and our co-products. In exchange for JS&A's risk management services, we pay JS&A a fee of $1,500 per month. The term of the agreement is for one year and will continue on a month to month basis thereafter. The

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agreement may be terminated by either party at any time upon written notice.

We have also entered into an agreement with Advance Trading to assist us with hedging corn, ethanol and natural gas. We pay them a fee of $1,000 per month for these services. The term of the agreement is a month to month agreement, and may be terminated by either party at any time upon proper notice.

Utilities

We engaged U.S. Energy Services, Inc. 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 is an independent, employee-owned company, with their main office in Minneapolis, Minnesota and branch offices in Kansas City, Kansas and Omaha, Nebraska. 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. Their goal is to develop, implement, and maintain a dynamic strategic plan to manage and reduce their clients' energy costs. A large percentage of U.S. Energy Services' clients are ethanol plants and other renewable energy plants. We pay U.S. Energy Services, Inc. a monthly fee of $3,500 plus pre-approved travel expenses. The monthly fee will increase 4% per year on the anniversary date of the agreement. The agreement is year to year.
Natural Gas. Natural gas is also an important input commodity to our manufacturing process. Our natural gas usage for our fiscal year ended September 30, 2011 was approximately 3,121,000 MMBTU, constituting approximately 4.78% 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 broader livestock markets, including poultry and swine markets in the continental United States.

On March 20, 2007, we entered into a Long-Term Transportation Service Contract for Redelivery of Natural Gas with Ohio Valley. Under the contract, Ohio Valley receives, transports and redelivers natural gas to us for all of our natural gas requirements up to a maximum of 100,000 therms per purchase gas day and our estimated annual natural gas requirements of 34,000,000 therms. For all gas received for and redelivered to us by Ohio Valley, we pay a throughput rate in the amount of $0.0138 per therm for the first five years of the contract term, and $0.0138 increased by the compounded inflation rate as established and determined by the U.S. Consumer Price Index - All Urban Consumers for Transportation for the following five years. In addition, we pay a service charge for all gas received for and redelivered to us by Ohio Valley in the amount of $750 per delivery meter per billing cycle per month for the first five years of the contract term and $750 increased by the compounded inflation rate over the initial rate as established and determined by the U.S. Consumer Price Index - All Urban Consumers for Transportation for the following five years. The initial term of the contract is ten years. Provided neither party terminates the contract, the contract will automatically renew for a series of not more than three consecutive one year periods.

Electricity. We require a significant amount of electrical power to operate the plant. On May 2, 2007, we entered into an agreement with Indiana Michigan Power Company to furnish our electric energy. The initial term of the contract is 30 months from the time service is commenced and continues thereafter unless terminated by either party with 12 months written notice. We pay Indiana Michigan Power Company monthly pursuant to their standard rates.

Water. We require a significant supply of water. Engineering specifications show our plant's water requirements to be approximately 774 gallons per minute, 1.1 million gallons per day, depending on the quality of water. We have assessed our water needs and available supply. Union City Water Works is supplying the water necessary to operate our 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. This will have the long-term effect of lowering wastewater treatment costs. Many new plants today are zero or near zero effluent discharge facilities. Our plant design incorporates the ICM/Phoenix Bio-Methanator wastewater treatment process resulting in a zero discharge of plant process water.

Employees

We currently have 49 full-time employees.


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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 to use certain ethanol production technology necessary to operate our ethanol plant. The cost of the license granted by ICM was included in the amount we paid to Fagen to design and build our ethanol plant.

In addition, we were granted a license by ICM to use certain corn oil technologies necessary to extract corn oil during our plant operations.

Seasonality of Ethanol Sales

We experience some seasonality of demand for 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.

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 is our operations along with our short-term revolving line of credit with our primary lender First National Bank of Omaha. At November 30, 2011, we have approximately $15,000,000 available to draw on the short-term revolving line of credit. We currently have no outstanding borrowings under our short-term revolving line of credit.

Dependence on One or a Few Major Customers

As discussed above, we have entered into a marketing agreement with Murex for the purpose of marketing and distributing our ethanol and have engaged CHS, Inc. for the purpose of marketing and distributing our distillers grains. We rely on Murex for the sale and distribution of our ethanol and CHS, Inc. for the sale and distribution of our distillers grains. Therefore, although there are other marketers in the industry, we are highly dependent on Murex and CHS, Inc. for the successful marketing of our products. Any loss of Murex or CHS, Inc. as our marketing agent for our ethanol and distillers grains respectively could have a significant negative impact on our revenues.
 
Financial Information about Geographic Areas

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

ITEM 1A.    RISK FACTORS.

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

Risks Relating to Our Business
 
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 4.5 cents per gallon of ethanol blended with gasoline at a rate of at least 10%. We expect that the tax credit will expire on December 31, 2011. Although

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we do not believe that the expiration of the credit will have a significant impact on our operations in the immediate future there is no guarantee that if VEETC expires, it will not negatively impact the price we receive for our ethanol and negatively impact our profitability.

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. Although we have significantly reduced our level of debt, the restrictive covenants contained in our financing agreements 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 dividends 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, distiller's grains and corn oil. 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. 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, distiller's 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. We seek to minimize the risks from fluctuations in the prices of corn and natural gas through the use of hedging instruments.  However, these hedging transactions also involve risks to our business.  See “Risks Relating to Our Business - We engage in hedging transactions which involve risks that could harm our business.” 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, the value of our units may be reduced.
 
Declines in the price of ethanol or distiller's grain would significantly reduce our revenues. The sales prices of ethanol and distiller's grains can be volatile as a result of a number of factors such as overall supply and demand, the price of gasoline and corn, levels of government support, and the availability and price of competing products. We are dependent on a favorable spread between the price we receive for our ethanol and distiller's grains and the price we pay for corn and natural gas. Any lowering of ethanol and distiller's 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 distiller's grains to continue to be volatile in our 2012 fiscal year as a result of the net effect of changes in the price of gasoline and corn and increased ethanol supply offset by increased ethanol demand. Declines in the prices we receive for our ethanol and distiller's grains will lead to decreased revenues and may result in our inability to operate the ethanol plant profitably for an extended period of time which could decrease the value of our units.

The price of distillers grains may decline as a result of China's antidumping investigation of distillers grains originating in the United Sates. Estimates indicate that as much as 10 to 15 percent of the distillers 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 distillers grains are subjected to trade barriers when selling distillers grains to Chinese customers there may be a reduction in the price of distillers grains in the United States. Declines in the price we receive for our distillers grains will lead to decreased revenues and may result in our inability to operate the ethanol plant profitably.

We may violate the terms of our credit agreements and financial covenants which could result in our lender demanding immediate repayment of our loans. We are currently in compliance with all our financial covenants. Current management projections indicate that we will be in compliance with our loan covenants. However, 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

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

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. While we do not currently require more financing than we have, in the future we may need additional financing. If we require financing in the future and we are unable to secure such financing, or we are unable to secure the financing we require on reasonable terms, it may have a negative impact on our liquidity. This could negatively impact the value of our units.

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 approximately 14.7 billion gallons in 2011. This rapid growth has resulted in significant shifts in supply and demand of ethanol over a very short period of time. As a result, past performance by the ethanol plant or the ethanol industry generally might not be indicative of future performance. We may experience a rapid shift in the economic conditions in the ethanol industry which may make it difficult to operate the ethanol plant profitably. If changes occur in the ethanol industry that make it difficult for us to operate the ethanol plant profitably, it could result in the reduction in the value of our units.
 
We engage in hedging transactions which involve risks that could harm our business.  We are exposed to market risk from changes in commodity prices.  Exposure to commodity price risk results from our dependence on corn 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 through the use of hedging instruments.  The effectiveness of our hedging strategies is dependent on the price of corn, natural gas and ethanol and our ability to sell sufficient products to use all of the corn and natural gas for which we have futures contracts.  Our hedging activities may not successfully reduce the risk caused by price fluctuation which may leave us vulnerable to high corn and natural gas prices. Alternatively, we may choose not to engage in hedging transactions in the future and our operations and financial conditions may be adversely affected during periods in which corn and/or natural gas prices increase. Utilizing cash for margin calls has an impact on the cash we have available for our operations which could result in liquidity problems during times when corn prices rise or fall significantly.
 
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 derivative instruments are 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 the derivatives instruments with delivery dates nearest the current cash price.  We may incur such costs and they may be significant which could impact our ability to profitably operate the plant and may reduce the value of our units.
 
Our business is not diversified.  Our success depends 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, distiller's grains and corn oil.  If economic or political factors adversely affect the market for ethanol, distiller's grains or corn oil, we have no other line of business to fall back on. Our business would also be significantly harmed if the ethanol plant could not operate at full capacity for any extended period of time.
  
We depend on our management and key employees, and the loss of these relationships could negatively impact our ability to operate profitably. We are highly dependent on our management team to operate our ethanol plant. We may not be able to replace these individuals should they decide to cease their employment with us, or if they become unavailable for any other reason. While we seek to compensate our management and key employees in a manner that will encourage them to continue their employment with us, they may choose to seek other employment. Any loss of these officers and key employees may prevent us from operating the ethanol plant profitably and could decrease the value of our units.

Changes and advances in ethanol production technology could require us to incur costs to update our plant or could otherwise hinder our ability to compete in the ethanol industry or operate profitably.  Advances and changes in the technology of ethanol production are expected to occur.  Such advances and changes may make the ethanol production technology installed in our plant less desirable or obsolete.  These advances could also allow our competitors to produce ethanol at a lower cost than we are able.  If we are unable to adopt or incorporate technological advances, our ethanol production methods and processes could be less efficient than our competitors, which could cause our plant to become uncompetitive or completely obsolete.  If our competitors develop, obtain or license technology that is superior to ours or that makes our technology obsolete, we may be required to incur significant costs to enhance or acquire new technology so that our ethanol production remains competitive.  Alternatively, we may be required to seek third-party licenses, which could also result in significant expenditures.  These third-party licenses may not be available or, once obtained, they may not continue to be available on commercially reasonable terms. 

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These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income.

We are subject to litigation involving our corn oil extraction technology. We have been sued by GS CleanTech Corporation asserting its intellectual property rights to certain corn oil extraction processes we obtained from ICM, Inc. in August 2008. GS CleanTech is seeking to enforce its patent rights against ICM and the Company. According to information available through the U.S. Patent and Trademark Office, certain patents have been issued and other patents will be issued to GS CleanTech. If GS CleanTech is successful in its infringement action against the Company, we may be forced to pay damages to GS CleanTech as a result of our use of such technology and cease our production of corn oil.
 
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 has reached 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. Recently, the EPA allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2007 and later as well as for cars and light duty trucks manufactured in the model years between 2001 and 2006. Management believes that many gasoline retailers will refuse to provide E15 due to the fact that not all standard vehicles will be allowed to use E15 and due to the labeling requirements the EPA may impose. The EPA is considering instituting labeling requirements associated with E15 which may unfairly discourage consumers from purchasing E15. Additionally, according to EPA estimates, flex-fuel vehicles make up only 7.3 million of the 240 million vehicles on the nation's roads and there are only about 2,000 E85 pumps in the United States. As a result, the approval of E15 may not significantly increase demand for ethanol. In addition to E15, the ethanol industry is pushing the use of an intermediate blend of 12% ethanol and 88% gasoline called E12. Management believes that E12 may be more beneficial to the ethanol industry than E15 because many believe that E12 could be approved for use in all standard vehicles. Management believes this will make it easier for retailers to supply E12 compared to E15, unless E15 is approved for use in all standard vehicles. Two lawsuits were filed on November 9, 2010, by representatives of the food industry and the petroleum industry challenging the EPA's approval of E15. It is unclear what effect these lawsuits will have on the implementation of E15 in the United States retail gasoline market.

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.

Decreasing gasoline prices may negatively impact the selling price of ethanol which could reduce our ability to operate profitably. The price of ethanol tends to change in relation to the price of gasoline. Recently, as a result of a number of factors including the current world economy, the price of gasoline has decreased. In correlation to the decrease in the price of gasoline, the price of ethanol has also decreased. Decreases in the price of ethanol reduce our revenue. Our profitability depends on a favorable spread between our corn and natural gas costs and the price we receive for our ethanol. If ethanol prices fall during times when corn and/or natural gas prices are high, we may not be able to operate our ethanol plant profitably.

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

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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, we expect that VEETC will expire at the end of the 2011 calendar year. 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. The tariff that protects the United States ethanol industry expires at the end of 2011 which could lead to increase of ethanol supplies and decreased ethanol prices.

Changes in environmental regulations or violations of these regulations could be expensive and reduce our profitability.  We are subject to extensive air, water and other environmental laws and regulations.  In addition, some of these laws require our plant to operate under a number of environmental permits. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.  A violation of these laws and regulations or permit conditions can result in substantial fines, damages, criminal sanctions, permit revocations and/or plant

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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. While there are currently no regulations applicable to us concerning carbon dioxide, if the EPA or the State of Indiana were to regulate carbon dioxide emissions by plants such as ours, we may have to apply for additional permits or we may be required to install carbon dioxide mitigation equipment or take other as yet unknown steps to comply with these potential regulations. Compliance with any future regulation of carbon dioxide, if it occurs, could be costly and may prevent us from operating the ethanol plant profitably which could decrease or eliminate the value of our units.

ITEM 2. PROPERTIES

Our plant site is made up of two adjacent parcels which together total approximately 295 acres in east central Indiana near Union City, Indiana. The address of our plant is 1554 N. County Road 600 E., Union City, Indiana 47390. In November 2008, 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; and
An administration building.

Our plant is in excellent condition and is capable of functioning at over 100% of its nameplate 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."

ITEM 3. LEGAL PROCEEDINGS

Patent Infringement

On June 27, 2008, we entered into a Tricanter Purchase and Installation Agreement with ICM, Inc. for the construction and installation of a Tricanter Oil Separation System. On February 12, 2010, GS CleanTech Corporation filed a lawsuit in the United States District Court for the Southern District of Indiana, claiming that the Company's operation of the oil recovery system manufactured and installed by ICM, Inc. infringes a patent claimed by GS CleanTech Corporation. GS CleanTech Corporation sought a preliminary injunction, which was denied, and seeks royalties and damages associated with the alleged infringement, as well as attorney's fees from the Company. On February 16, 2010, ICM, Inc. agreed to indemnify, at ICM's expense, the Company from and against all claims, demands, liabilities, actions, litigations, losses, damages, costs and expenses, including reasonable attorney's fees arising out of any claim of infringement of patents, copyrights or other intellectual property rights by reason of the Company's purchase and use of the oil recovery system.

GS CleanTech Corporation subsequently filed actions against at least fourteen other ethanol producing companies for infringement of its patent rights. Several of the other defendants also use equipment and processes provided by ICM, Inc. GS CleanTech Corporation then petitioned for the cases to be joined in a multi-district litigation ("MDL"). This petition was granted and the MDL was assigned to the United States District Court for the Southern District of Indiana (Case No. 1:10-ml-02181). The Company has since answered and counterclaimed that the patent claims at issue are invalid and that the Company is not infringing. The Company anticipates that once the issues common to all of the defendants have been determined in the MDL, the cases will proceed in the respective districts in which they were originally filed.


18


The Company is not currently able to predict the outcome of this litigation with any degree of certainty. ICM, Inc. has, and the Company expects it will continue, to vigorously defend itself and the Company in these lawsuits. The Company estimates that damages sought in this litigation if awarded would be based on a reasonable royalty to, or lost profits of, GS CleanTech Corporation. If the court deems the case exceptional, attorney's fees may be awarded and are likely to be $1,000,000 or more. ICM, Inc. has also agreed to indemnify the Company. However, in the event that damages are awarded, if ICM, Inc. is unable to fully indemnify the Company for any reason, the Company could be liable. In addition, the Company may need to cease use of its current oil separation process and seek out a replacement or cease oil production altogether.

Air Emissions Permit

In January of 2010 we applied for a Title V Operating Permit for air emissions from the Indiana Department of Environmental Management ("IDEM"). IDEM issued the permit on August 5, 2010. This permit increased our operating capacity and emission limits. The new permit increased Cardinal's potential to emit criteria pollutants, which includes particulate matter. Each criteria pollutant must be less than 250 tons per consecutive twelve month period. This provision was based on a rule change issued by the Environmental Protection Agency ("EPA") on May 1, 2007, which allowed ethanol plants to emit up to 250 tons per criteria pollutant, excluding fugitive dust, instead of only 100 tons per criteria pollutant, including fugitive dust.

On September 8, 2010, the National Resource Defense Council ("NRDC") filed an administrative appeal of Cardinal's Title V Operating Permit challenging IDEM's authority to grant the Title V Operating Permit. NRDC is arguing the IDEM failed to incorporate the May 1, 2007 EPA rule change into the EPA - approved State Implementation Plan ("SIP") and that as a result, the Permit was improperly issued as the existing SIP still limited ethanol plants to 100 tons of particulate matter. The NRDC appeal regarding our Title V Operating Permit has been stayed pending resolution of similar administrative appeals filed by NRDC against other ethanol plants in Indiana.

NRDC was recently successful in one of its administrative appeals, resulting in a January 11, 2011 ruling by an administrative law judge that IDEM cannot change its interpretation of Indiana's rules to match the EPA's rules without first revising the Indiana SIP. Although we intend to vigorously defend our Title V Operating Permit and believe we have legal arguments not available to the other ethanol plants whose permits have been appealed, should NRDC's challenge of our Permit be successful, we would be limited to our original operating permit parameters which would in turn decrease our production of ethanol and distillers grains.

ITEM 4. (REMOVED AND RESERVED)

PART II.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
    
As of September 30, 2011 we had approximately 14,606 membership units outstanding and approximately 1,187 unit holders of record. There is no public trading market for our units.

However, we have established through Alerus Securities a Unit Trading Bulletin Board, a private online matching service, in order to facilitate trading among our members.  The Unit Trading Bulletin Board has been designed to comply with federal tax laws and IRS regulations establishing an “alternative trading service,” as well as state and federal securities laws.  Our Unit Trading Bulletin Board consists of an electronic bulletin board that provides a list of interested buyers with a list of interested sellers, along with their non-firm price quotes.  The Unit Trading Bulletin Board does not automatically affect matches between potential sellers and buyers and it is the sole responsibility of sellers and buyers to contact each other to make a determination as to whether an agreement to transfer units may be reached.  We do not become involved in any purchase or sale negotiations arising from our Unit Trading Bulletin Board and have no role in effecting the transactions beyond approval, as required under our operating agreement, and the issuance of new certificates.  We do not give advice regarding the merits or shortcomings of any particular transaction.  We do not receive, transfer or hold funds or securities as an incident of operating the Unit Trading Bulletin Board.  We do not receive any compensation for creating or maintaining the Unit Trading Bulletin Board.  In advertising our alternative trading service, we do not characterize Cardinal Ethanol as being a broker or dealer or an exchange.  We do not use the Unit Trading Bulletin Board to offer to buy or sell securities other than in compliance with the securities laws, including any applicable registration requirements.
 
There are detailed timelines that must be followed under the Unit Trading Bulletin Board Rules and Procedures with respect to offers and sales of membership units.  All transactions must comply with the Unit Trading Bulletin Board Rules, our operating agreement, and are subject to approval by our board of directors.

19



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 the Company to be deemed a publicly traded partnership.

The following table contains historical information by fiscal quarter for the past two fiscal years regarding the actual unit transactions that were completed by our unit-holders during the periods specified. We believe this most accurately represents the current trading value of the Company's units. The information was compiled by reviewing the completed unit transfers that occurred on our qualified matching service bulletin board during the quarters indicated.

Quarter
 
Low Price
 
High Price
 
Average Price
 
# of
Units Traded
2010 1st 
 
$
2,250

 
$
2,700

 
$
2,557.29

 
24

2010 2nd 
 
$
2,650

 
$
3,400

 
$
2,817.50

 
80

2010 3rd 
 
$
3,100

 
$
3,400

 
$
3,217.25

 
20

2010 4th 
 
$
3,400

 
$
3,500

 
$
3,416.13

 
62

2011 1st 
 
$
3,350

 
$
3,650

 
$
3,540.98

 
26

2011 2nd 
 
$
3,500

 
$
3,800

 
$
3,572.05

 
39

2011 3rd 
 
$
3,110

 
$
3,600

 
$
3,447.36

 
53

2011 4th 
 
$
3,500

 
$
4,000

 
$
3,905.84

 
77

 
The following table contains the bid and asked prices that were posted on the Company's alternative trading service bulletin board and includes some transactions that were not completed. The Company believes the table above more accurately describes the trading value of its units as the bid and asked prices below include some offers that never resulted in completed transactions. The information was compiled by reviewing postings that were made on the Company's alternative trading service bulletin board.
Sellers Quarter
 
Low Price
 
High Price
 
Average Price
 
# of
Units Listed
2010 1st 
 
$
2,250

 
$
2,700

 
$
2,557.29

 
24

2010 2nd 
 
$
2,650

 
$
3,800

 
$
2,841.46

 
82

2010 3rd 
 
$
3,100

 
$
3,400

 
$
3,217.25

 
20

2010 4th 
 
$
3,400

 
$
3,500

 
$
3,558.54

 
82

2011 1st 
 
$
3,450

 
$
3,650

 
$
3,503.98

 
211

2011 2nd 
 
$
3,500

 
$
3,800

 
$
3,587.73

 
44

2011 3rd 
 
$
3,110

 
$
5,100

 
$
3,777.76

 
67

2011 4th 
 
$
3,500

 
$
5,200

 
$
4,106.25

 
120

 
We did not make any distributions to our members during our fiscal year ended September 30, 2011.

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."

Performance Graph

The following graph shows a comparison of cumulative total member return since September 30, 2006, calculated on a dividend reinvested basis, for the Company, the NASDAQ Composite Index (the “NASDAQ”) and an index of other companies that have the same SIC code as the Company (the “Industry Index”). The graph assumes $100 was invested in each of our units, the NASDAQ, and the Industry Index on September 30, 2006. Data points on the graph are annual. Note that historic stock price performance is not necessarily indicative of future unit price performance.

20





Pursuant to the rules and regulations of the Securities and Exchange Commission, the performance graph and the information set forth therein shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, and shall not be deemed to be incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

ITEM 6. SELECTED FINANCIAL DATA

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


21


Statement of Operations Data:
 
2011
 
2010
 
2009
 
2008
 
2007
Revenues
$
337,019,930

$
224,807,338

$
167,738,057

$

$

 
 
 
 
 
 
 
 
 
 
 
Cost Goods Sold
 
302,690,475

 
195,880,762

 
160,674,617

 

 

 
 
 
 
 
 
 
 
 
 
 
Gross Profit
 
34,329,455

 
28,926,576

 
7,063,440

 

 

 
 
 
 
 
 
 
 
 
 
 
Operating Expenses
 
4,250,752

 
3,735,530

 
3,726,051

 
1,266,368

 
875,080

 
 
 
 
 
 
 
 
 
 
 
Operating Income (Loss)
 
30,078,703

 
25,191,046

 
3,337,389

 
(1,266,368
)
 
(875,080
)
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense)
 
(4,569,566
)
 
(4,740,467
)
 
(4,288,574
)
 
258,114

 
3,130,461

 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
$
25,509,137

$
20,450,579

$
(951,185
)
$
(1,008,254
)
$
2,255,381

 
 
 
 
 
 
 
 
 
 
 
Weighted Average Units Outstanding
 
14,606

 
14,606

 
14,606

 
14,606

 
12,026

 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss) Per Unit
$
1,746.48

$
1,400.15

$
(65.12
)
$
(69.03
)
$
187.54

 
 
 
 
 
 
 
 
 
 
 
Cash Distributions Per Unit
$

$
60

$

$

$

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data:
 
2011
 
2010
 
2009
 
2008
 
2007
Current Assets
$
49,830,340

$
31,898,901

$
22,049,914

$
741,508

$
21,285,458

 
 
 
 
 
 
 
 
 
 
 
Net Property and Equipment
 
125,169,711

 
132,780,346

 
137,209,571

 
140,285,656

 
63,371,362

 
 
 
 
 
 
 
 
 
 
 
Other Assets
 
876,699

 
851,732

 
1,068,767

 
2,397,795

 
1,427,895

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
175,876,750

 
165,530,979

 
160,328,252

 
143,424,959

 
86,084,715

 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
18,628,361

 
20,562,149

 
13,036,275

 
11,682,082

 
13,621,236

 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
 
42,960,017

 
56,188,380

 
77,427,000

 
61,818,344

 

 
 
 
 
 
 
 
 
 
 
 
Other Liabilities
 
1,961,239

 
3,130,402

 
3,269,980

 

 

 
 
 
 
 
 
 
 
 
 
 
Members' Equity
 
112,327,133

 
85,650,048

 
66,594,997

 
69,924,533

 
72,463,479


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

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

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

22


Overview

Cardinal Ethanol, LLC is an Indiana limited liability company. It was formed on February 7, 2005 with the name of Indiana Ethanol, LLC. On September 27, 2005, we changed our name to Cardinal Ethanol, LLC. 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 Indiana near Union City, Indiana. We began producing ethanol and distillers grains at the plant in November 2008. We are currently operating at above nameplate capacity. During fiscal 2011, the ethanol plant processed approximately 39 million bushels of corn per year into 115 million gallons of denatured fuel grade ethanol, 319,000 tons of dried distillers grains with solubles, and 14 million pounds of corn oil.

Our revenues are derived from the sale of our ethanol, distillers grains and corn oil. We market and sell our products primarily in the continental United States using third party marketers. Murex, N.A., Ltd. markets all of our ethanol. Our distillers grains are marketed by CHS, Inc.

The ethanol industry is currently impacted by the Volumetric Ethanol Tax Credit (VEETC) which is frequently referred to as the blenders' credit. This blenders' credit provides a tax credit of 45 cents per gallon of ethanol that is blended with gasoline. This incentive is scheduled to expire on December 31, 2011. Management anticipates that VEETC will not be renewed and therefore will not be available starting January 1, 2012. Management believes that the expiration of VEETC will not have a significant effect on ethanol demand provided gasoline prices remain high and the renewable fuels use requirement of the Federal Renewable Fuels Standard (RFS) is maintained. The RFS requires that a certain amount of renewable fuels must be used in the United STates each year. HOwever, if the RFS is repealed, ethanol demand may be significantly impacted. Recently, there have been proposals in Congress to reduce or eliminate the RFS. Management does not believe that these proposals will be adopted in the near future. However, if the RFS is reduced or eliminated and the blenders' credit is allowed to expire, the market price and demand for ethanol will likely decrease which could negatively impact our financial performance.

We expect to fund our operations during the next 12 months using cash flow from our continuing operations and our current credit facilities. However, based on volatility in the cost of corn and potentially tight margins throughout the period, we may need to seek additional funding.

Results of Operations

Comparison of Fiscal Year Ended September 30, 2011 and 2010

The following table shows the results of our operations and the approximate percentage of revenues, costs of goods sold, operating expenses and other items to total revenues in our statements of operations for the fiscal years ended September 30, 2011 and 2010:
:
 
Fiscal Year Ended
September 30, 2011
Fiscal Year Ended September 30, 2010
Statement of Operations Data
Amount
Percent
Amount
Percent
Revenues
$
337,019,930

100.00
 %
$
224,807,338

100.00
 %
Cost of Goods Sold
302,690,475

89.81

195,880,762

87.13

Gross Profit
34,329,455

10.19

28,926,576

12.87

Operating Expenses
4,250,752

1.26

3,735,530

1.66

Operating Income
30,078,703

8.92

25,191,046

11.21

Other Expense, net
(4,569,566
)
(1.36
)
(4,740,467
)
(2.11
)
Net Income
$
25,509,137

7.57
 %
$
20,450,579

9.10
 %

    
The following table shows the sources of our revenue for the fiscal year ended September 30, 2011 and September 30, 2010.


23


 
Fiscal Year Ended
September 30, 2011
Fiscal Year Ended
September 30, 2010
Revenue Source
Amount
% of Revenues
Amount
% of Revenues
Ethanol Sales
$
276,082,661

81.92
%
$
191,276,457

85.08
%
Dried Distillers Grains Sales
53,681,618

15.93

31,163,445

13.86

Wet Distillers Grains Sales
161,035

0.05

107,211

0.05

Corn Oil Sales
6,475,079

1.92

1,789,945

0.80

Other Revenue
619,537

0.18

470,280

0.21

Total Revenues
$
337,019,930

100.00
%
$
224,807,338

100.00
%

The following table shows additional data regarding production and price levels for our primary inputs and products for the fiscal years ended September 30, 2011 and 2010:
 
 
Fiscal Year Ended
September 30, 2011
Fiscal Year Ended
September 30, 2010
Production:
 
 
 
Ethanol sold (gallons)
 
114,661,886

109,986,252

Distillers grains sold (tons)
 
318,785

321,087

Corn oil sold (pounds)
 
13,934,980

6,796,940

 
 
 
 
Revenues:
 
 
 
Ethanol average price per gallon
 
$
2.40

$
1.739

Distillers grains average price per ton
 
$
168.90

$
97.39

Corn oil average price per pound
 
$
0.46

$
0.26

 
 
 
 
Primary Inputs:
 
 
 
Corn ground (bushels)
 
39,356,259

39,408,254

Natural gas purchased (MMBTU)
 
3,120,976

3,126,888

 
 
 
 
Costs of Primary Inputs:
 
 
 
Corn average price per bushel ground
 
$
6.63

$
3.85

Natural gas average price per MMBTU
 
$
4.59

$
5.01

 
 
 
 
Other Costs:
 
 
 
Chemical and additive costs per gallon of ethanol sold
 
$
0.073

$
0.062

Denaturant cost per gallon of ethanol sold
 
$
0.056

$
0.042

Electricity cost per gallon of ethanol sold
 
$
0.030

$
0.031

Direct Labor cost per gallon of ethanol sold
 
$
0.019

$
0.018


Revenues
    
For the fiscal year ended September 30, 2011, ethanol sales comprised approximately 82% of our revenues and distillers grains sales comprised approximately 16% of our revenues, while corn oil and carbon dioxide sales comprised approximately 2% of our revenues. For the fiscal year ended September 30, 2010, ethanol sales comprised approximately 85% of our revenue and distillers grains sales comprised approximately 14% of our revenue, while corn oil comprised approximately 1% of our revenues.

Ethanol

Our revenues from ethanol increased for our fiscal year ended September 30, 2011 as compared to the fiscal year ended September 30, 2010 primarily as a result of an increase in our ethanol production and higher ethanol prices on average per gallon in the fiscal year ended September 30, 2011.

During the fiscal year ended September 30, 2011, the market price of ethanol varied between $2.07 per gallon and $3.07 per gallon. Our average price per gallon of ethanol sold, including the effects of risk management/hedging, was $2.40 per gallon for the fiscal year ended September 30, 2011. During the fiscal year ended September 30, 2010, the market price of ethanol varied between $1.57 and $2.43 per gallon. Our average price per gallon of ethanol sold was $1.74. During the fiscal year ended

24


September 30, 2011, we sold approximately 114,662,000 gallons of ethanol as compared to our sales of approximately 109,986,000 gallons of ethanol for the same period in 2010. For the fiscal year ended September 30, 2011, we recorded net losses on our ethanol derivative contracts of $6,536,843. These losses were recorded against our revenues in the statement of operations. We recorded net gains on our ethanol derivative contracts of $33,217 during the fiscal year ended September 30, 2010.

Distillers Grains

Our revenues from distillers grains increased in the fiscal year ended September 30, 2011 as compared to the same period in 2010. This increase was primarily the result of an increase in the average price per ton of distillers grains in the fiscal year ended September 30, 2011 as compared to the same period in 2010.

During the fiscal year ended September 30, 2011 the market price of distillers grains varied between approximately $105 and $220 per ton. Our average price per ton of distillers grains sold was approximately $169. During the fiscal year ended September 30, 2010, the market price of distillers grains varied between approximately $93 per ton and $140 per ton. Our average price per ton of distillers grains sold was approximately $97. During our fiscal year ended September 30, 2011 we sold approximately 319,000 tons of distillers grains compared to approximately 321,000 for the same period in 2010.

Cost of Goods Sold

Our costs of goods sold as a percentage of revenues were approximately 90% for the fiscal year ended September 30, 2011 compared to 87% for the same period of 2010. Our two largest costs of production are corn and natural gas.

Corn Costs

During the fiscal year ended September 30, 2011 we used approximately 39,356,000 bushels of corn to produce our ethanol, distillers grain and corn oil as compared to approximately 39,408,000 bushels for the same period in 2010. During the fiscal year ended September 30, 2011, the market price of corn varied between $4.24 per bushel and $8.34 per bushel. Our average price per bushel of corn ground was $6.63 after considering the effects of our risk management/hedging. During the fiscal year endedSeptember 30, 2010, the market price of corn varied between $3.40 and $4.81 per bushel. Our average price per bushel of corn ground was $3.85 after considering the effects of our risk management/hedging. For the fiscal year ended September 30, 2011 and 2010, we recorded net losses on our corn derivative contracts of $5,008,132 and $2,424,135, respectively. These net losses were recorded in our costs of goods sold in our statement of operations.

Natural Gas
    
During our fiscal year ended September 30, 2011, we purchased approximately 3,121,000 MMBTU's of natural gas as compared to approximately 3,127,000 MMBTU's for the same period in 2010. During the fiscal year ended September 30, 2011, the market price of natural gas varied between $3.66 per MMBTU and $5.39 MMBTU. Our average price per MMBTU of natural gas was $4.59. During the fiscal year ended September 30, 2010, the market price of natural gas varied between $3.70 per MMBTU and $6.10 per MMBTU. Our average price per MMBTU of natural gas was $5.01.

Operating Expense

Our operating expenses were higher for the fiscal year ended September 30, 2011 than they were for the same period ended September 30, 2010. This increase in operating expenses is primarily due to an increase in general and administrative expenses. These increased expenses are the result of increased salaries and property taxes. We expect that going forward our operating expenses will remain relatively steady.

Operating Income (Loss)

Our income from operations for the fiscal year endedSeptember 30, 2011 was approximately 9% of our revenues compared to operating income of approximately 11% of our revenues for the fiscal year ended September 30, 2010. This decrease in our profitability was primarily the result of the extremely favorable market conditions and resulting operating margins we experienced in the fiscal year ended 2010 compared with more modest conditions and margins in the fiscal year ended 2011. Higher prices have resulted in higher profits that are lower percentage-wise relative to revenues.


25


Other Income and Other Expense

Other expense for the fiscal year ended September 30, 2011 was approximately 1% of our revenue and totaled approximately $4,570,000. Other expense for the fiscal year ended September 30, 2010 was approximately 2% of our revenue and totaled approximately $4,740,000. Other expense consisted primarily of interest expense.

Changes in Financial Condition for the Fiscal Years Ended September 30, 2011 and 2010

The following table highlights the changes in our financial condition:

 
September 30, 2011
September 30, 2010
Current Assets
$
49,830,340

$
31,898,901

Current Liabilities
$
18,628,361

$
20,562,149

Member's Equity
$
112,327,133

$
85,650,048


We experienced an increase in our current assets at September 30, 2011 as compared to September 30, 2010. We experienced an increase of approximately $3,400,000 in the value of our inventory at September 30, 2011 compared to September 30, 2010. Inventories increased from prior year end due to the increased price per bushel of corn and price per gallon of ethanol. At September 30, 2011 we had trade accounts receivable of approximately $19,101,000 compared to trade accounts receivable at September 30, 2010 of approximately $13,263,000. The increase in receivables is primarily due to the increased price of ethanol and timing of ethanol rail shipments. We also had cash of approximately $10,802,000 at September 30, 2011 as compared to $3,318,000 at September 30, 2010. This increase in cash is primarily the result of operations. Restricted cash decreased to approximately $2,359,000 at September 30, 2011 as compared to approximately $4,551,000 at September 30, 2010. This decrease in restricted cash is primarily related to our risk management strategy of entering into ethanol, corn and natural gas hedges to protect our ethanol, corn and natural gas prices

We experienced a decrease in our total current liabilities at September 30, 2011 compared to September 30, 2010. The decrease is primarily due to a decrease in our commodity derivative instruments for the fiscal year ended September 30, 2011 as compared to the same period in 2010.

We experienced a decrease in our long-term liabilities as of September 30, 2011 compared to September 30, 2010. At September 30, 2011 we had approximately $42,960,000 outstanding in the form of long-term loans, compared to approximately $56,188,000 at September 30, 2010. The decrease is primarily due to scheduled principal repayments made on our term loans.     

Comparison of Fiscal Years Ended September 30, 2010 and September 30, 2009

The following table shows the results of our operations and the percentage of revenues, cost of goods sold, operating expenses and other items to total revenues in our statement of operations for the fiscal years ended September 30, 2010 and 2009.

 
Fiscal Year Ended
September 30, 2010

 
 
Fiscal Year Ended
September 30, 2009

 
 
Income Statement Data
Amount
 
Percent
Amount
 
Percent

Revenues
$
224,807,338

 
100.00
 %
$
167,738,057

 
100.00
 %
Cost of Goods Sold
195,880,762

 
87.13

160,674,617

 
95.79

Gross Profit
28,926,576

 
12.87

7,063,440

 
4.21

Operating Expenses
3,735,530

 
1.66

3,726,051

 
2.22

Operating Income
25,191,046

 
11.21

3,337,389

 
1.99

Other (Expense)
(4,740,467
)
 
(2.11
)
(4,288,574
)
 
(2.56
)
Net Income (Loss)
$
20,450,579

 
9.10
 %
$
(951,185
)
 
(0.57
)%


26


 
Fiscal Year Ended
September 30, 2010
Fiscal Year Ended
September 30, 2009
Revenue Source
Amount
% of Revenues
Amount
% of Revenues
Ethanol Sales
$
191,276,457

85.08
%
$
138,802,095

82.75
%
Dried Distillers Grains Sales
31,163,445

13.86

27,534,648

16.42

Wet Distillers Grains Sales
107,211

0.05

181,059

0.11

Corn Oil Sales
1,789,945

0.80

1,220,255

0.73

Other Revenue
470,280

0.21



Total Revenues
$
224,807,338

100.00
%
$
167,738,057

100.00
%

The following table shows additional data regarding production and price levels for our primary inputs and our primary products for the fiscal years ended September 30, 2010 and 2009.

 
 
Fiscal Year Ended September 30, 2010
Fiscal Year Ended
September 30, 2009
Production:
 
 
 
Ethanol sold (gallons)
 
109,986,252

87,645,515

Distillers grains sold (tons)
 
321,087

267,699

 
 
 
 
Revenues:
 
 
 
Ethanol average price per gallon
 
$
1.739

$
1.58

Distillers grains average price per ton
 
$
97.39

$
103.53

 
 
 
 
Primary Inputs:
 
 
 
Corn ground (bushels)
 
39,408,254

32,293,302

Natural gas purchased (MMBTU)
 
3,126,888

2,760,264

 
 
 
 
Costs of Primary Inputs:
 
 
 
Corn average price per bushel ground
 
$
3.851

$
4.04

Natural gas average price per MMBTU
 
$
5.009

$
4.907

 
 
 
 
Other Costs:
 
 
 
Chemical and additive costs per gallon of ethanol sold
 
$
0.062

$
0.066

Denaturant cost per gallon of ethanol sold
 
$
0.042

$
0.036

Electricity cost per gallon of ethanol sold
 
$
0.031

$
0.033

Direct Labor cost per gallon of ethanol sold
 
$
0.018

$
0.022


Revenues

For the fiscal year ended September 30, 2010, we received approximately 85% of our revenue from the sale of fuel ethanol and approximately 14% of our revenue from the sale of distillers grains. Sales of corn oil represented less than 1% of our total sales. Comparatively, for the fiscal year ended September 30, 2009, we received approximately 83% of our revenue from the sale of fuel ethanol and approximately 17% of our revenue from the sale of distillers grains, and less than 1% of total sales from corn oil.

Ethanol

Our revenues from ethanol increased for our fiscal year ended September 30, 2010 as compared to our fiscal year ended September 30, 2009. Our increase in revenues for our 2010 fiscal year as compared to our 2009 fiscal year was the result of an increase in our ethanol production in 2010 and higher ethanol prices in 2010 on average per gallon as compared to 2009. We operated at approximately 118% of our name plate capacity in 2010.

During the fiscal year ended September 30, 2010, the market price of ethanol varied between approximately $1.57 per gallon and approximately $2.43 per gallon. Our average price per gallon of ethanol sold was approximately $1.74 for our 2010 fiscal year. During the fiscal year ended September 30, 2009, the market price of ethanol varied between approximately $1.36

27


per gallon and approximately $1.72 per gallon. Our average price per gallon of ethanol sold was approximately $1.58. During the fiscal year ended September 30, 2010, we sold approximately 109,986,000 gallons of ethanol as compared to our sale of 87,646,000 gallons of ethanol in 2009.

Distillers Grains

Our revenues from distillers grains increased in fiscal year ended September 30, 2010 as compared to the same period in 2009. This increase was primarily the result of increased distillers grains sales in 2010 as compared to 2009 partially offset by a decrease in the average price per ton we received from our distillers grains in the fiscal year ended September 30, 2010 as compared to the fiscal year ended September 30, 2009.

During the fiscal year ended September 30, 2010, the market price of distillers grains varied between approximately $93 per ton and approximately $140 per ton. Our average price per ton of distillers grains sold was approximately $97.39. During the fiscal year ended September 30, 2009, the market price of distillers grains varied between approximately $76.64 per ton and approximately $148.15 per ton. Our average price per ton of distillers grains sold was approximately $103.53. We sold approximately 53,000 more tons of distiller grains during our 2010 fiscal year as compared to our 2009 fiscal year. During our fiscal year ended September 30, 2010, we sold approximately 321,000 tons of distillers grains compared to approximately 268,000 tons during our fiscal year ended September 30, 2009. Management attributes this increase in distillers grains sales with increased production of ethanol during the 2010 fiscal year. As we produce more ethanol, the total tons of distillers grains that we produce also increases. Offsetting the increase in distillers grains sales was a decrease in the average price we received per ton of distillers grains sold during our 2010 fiscal year compared to our 2009 fiscal year. During our 2009 fiscal year, uncertainty existed regarding the supply of distillers grains in the market due to the fact that many ethanol producers were reducing production during late 2008 and early 2009. Management believes this resulted in higher distillers grains prices due to increasing demand and lower supplies. Therefore, we experienced higher distillers grains prices during our 2009 fiscal year. Further management believes that distillers grains prices lag behind corn prices. As a result, distillers grains prices during our 2010 fiscal year did not fully benefit from the increases in corn prices that we experienced in the second half of our 2010 fiscal year.

Cost of Goods Sold

Our cost of goods sold as a percentage of revenues was 87.13% for the fiscal year ended September 30, 2010 and 95.79% for the fiscal year ended September 30, 2009. Our two primary costs of producing ethanol and distillers grains are corn costs and natural gas costs.

Corn Costs

Our largest cost associated with the production of ethanol, distillers grains and corn oil is corn costs. During the fiscal year ended September 30, 2010 our corn costs increased as compared to our fiscal year ended September 30, 2009. This increase was the result of an increase in the amount of corn used by our plant in 2010 as compared to 2009 partially offset by a lower average price per bushel of ground corn in 2010 as compared to 2009.

During our fiscal year ended September 30, 2010, we used approximately 39,408,000 bushels of corn to produce our ethanol, distillers grain and corn oil as compared to approximately 32, 293,000 during our fiscal year ended September 30, 2009. Management attributes this increase in bushels of corn for our 2010 fiscal year to an increase in production of ethanol and distillers grains. During the fiscal year ended September 30, 2010, the market price of corn varied between approximately $3.40 per bushel and approximately $4.81 per bushel. Our average price per bushel of corn ground was approximately $3.85, without considering the effects of our risk management/hedging. During the fiscal year ended September 30, 2009, the market price of corn varied between approximately $3.41 per bushel and approximately $4.63 per bushel. Our average price per bushel of corn ground was approximately $4.04, without considering the effects of our risk management/hedging. Our corn costs associated with the beginning of our 2010 fiscal year were lower than normal. However, beginning in July corn prices increased as a result of uncertainty regarding weather factors that resulted in decreased corn yields in some parts of the United States. This led to fears regarding an imbalance between corn supply and demand which had a negative impact on corn prices.

In the ordinary course of business, we entered into forward purchase contracts for our commodity purchases for various delivery periods through July 2012 for a total commitment of approximately $7,761,000. Approximately $1,638,000 of the forward corn purchases were with a related party. As of September 30, 2010 we also have open short positions for 5,425,000 bushels of corn on the Chicago Board of Trade and 3,570,000 gallons of ethanol on the New York Mercantile Exchange to hedge our forward corn contracts and corn inventory. Our corn and ethanol positions are forecasted to settle for various delivery periods through March 2012 and November 2010, respectively. For the fiscal year ended September 30, 2010, we recorded net losses on our corn and ethanol contracts of approximately $2,424,000. These losses were recorded against our cost of goods sold in the statement

28


of operations. We expect continued volatility in the price of corn, which could significantly impact our cost of goods sold.

Natural Gas Costs

Our natural gas costs were higher during our fiscal year ended September 30, 2010 as compared to our fiscal year ended September 30, 2009. This increase in cost of natural gas for our 2010 fiscal year as compared to our 2009 fiscal year was primarily the result of an increase in the amount of natural gas that we used at our plant and an increase in the average price per MMBTU of our natural gas.
    
During our fiscal year ended September 30, 2010 we purchased approximately 367,000 more MMBTU's of natural gas than we purchased in our fiscal year ended September 30, 2009. During our fiscal year ended September 30, 2010 we purchased approximately 3,127,000 MMBTU's of natural gas as compared to approximately 2,760,000 MMBTU's during our fiscal year ended September 30, 2009. Management attributes this increase in natural gas to an increase in production. During the fiscal year ended September 30, 2010, the market price of natural gas varied between approximately $3.70 per MMBTU and approximately $6.10 per MMBTU. Our average price per MMBTU of natural gas was approximately $5.01. During the fiscal year ended September 30, 2009, the market price of natural gas varied between approximately $3.31 per MMBTU and approximately $8.028 per MMBTU. Our average price per MMBTU of natural gas was approximately $4.91.

Operating Expense

Our operating expenses as a percentage of revenues were 1.66% for the fiscal year ended September 30, 2010 and 2.22% for the same period in 2009. Our operating expenses have remained relatively steady for the fiscal year ended September 30, 2010 compared to the same periods of 2009. We had a decrease in professional fees expense offset by an increase in general and administrative costs. Operating expenses include salaries and benefits of administrative employees, insurance, taxes, professional fees and other general administrative costs.

Operating Income

Our income from operations for the fiscal year ended September 30, 2010 was approximately 11.21% compared to 1.99% of our revenues for the same period ended 2009. Our operating income for the fiscal year ended September 30, 2010 increased due to increased revenues as a result of better operating margins. For the fiscal year ended September 30, 2010 operating income was primarily the net result of our revenues exceeding our costs of goods sold and our operating expenses.

Other Expense

Our other expense for the fiscal year ended September 30, 2010 was approximately 2.11% of our revenues, compared to 2.56% for the fiscal year ended September 30, 2009. Our other expense for the fiscal year ended September 30, 2010 and 2009 consisted primarily of interest expense.

Changes in Financial Condition for the Fiscal Year Ended September 30, 2010 and 2009

 
September 30, 2010
September 30, 2009
Current Assets
$
31,898,901

$
22,049,914

Current Liabilities
$
20,562,149

$
13,036,275

Member's Equity
$
85,650,048

$
66,594,997


We experienced an increase in our current assets of approximately $7,240,000 at September 30, 2010 compared to September 30, 2009. We experienced an increase of approximately $7,317,000 in trade accounts receivable and an increase of $2,542,000 in inventory at September 30, 2010 compared to September 30, 2009. We also had cash of approximately $3,318,000 at September 30, 2010, compared to cash of approximately $7,265,000 at September 30, 2009 and prepaid and other current assets of approximately $965,000 at September 30, 2010, compared to approximately $847,000 at September 30, 2009.

We experienced an increase in our total current liabilities on September 30, 2010 compared to September 30, 2009. We experienced a decrease of approximately $1,992,000 in the current portion of our long term debt and capital lease obligations at September 30, 2010 compared to September 30, 2009. We experienced a decrease of approximately $269,000 for accrued expenses at September 30, 2010 compared to September 30, 2009; and an increase of approximately $1,710,000 in our accounts payable for corn purchases at September 30, 2010 compared to September 30, 2009. Such increase in our liabilities related to the current

29


portion of our derivative instruments of approximately $1,520,000 at September 30, 2010 compared to $862,000 at September 30, 2009; and an increase in our non-corn accounts payable of approximately $2,154,000 at September 30, 2010 compared to $1,330,000 at September 30, 2009.

We experienced a decrease in our long-term liabilities as of September 30, 2010 compared to September 30, 2009. At September 30, 2010, we had approximately $56,188,000 outstanding in the form of long-term loans, compared to approximately $77,427,000 at September 30, 2009. This decrease is due to paying down our long term debt.

Critical Accounting Estimates

Management uses various estimates and assumptions in preparing our financial statements in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Accounting estimates that are the most important to the presentation of our results of operations and financial condition, and which require the greatest use of judgment by management, are designated as our critical accounting estimates. We have the following critical accounting estimates:

We enter into derivative instruments to hedge the variability of expected future cash flows related to interest rates. We do not typically enter into derivative instruments other than for economic hedging purposes. All derivative instruments are recognized on the September 30, 2011 balance sheet at their fair market value. Changes in the fair value of a derivative instrument that is designated as and meets all of the required criteria for a cash flow hedge are recorded in accumulated other comprehensive income and reclassified into earnings as the underlying hedged items affect earnings.
At September 30, 2011, we had an interest rate swap with a fair value of $3,483,000 recorded as derivative instruments in the current and long-term liabilities section of the balance sheet and as a deferred loss in accumulated other comprehensive loss. We have an interest rate swap with a fair value of $4,651,000 for the same period ended in 2010. The interest rate swap is designated as a cash flow hedge.

As of September 30, 2011, we have open short positions for 5,910,000 bushels of corn and long positions of 5,235,000 for corn on the Chicago Board of Trade and short positions of 29,431,000 gallons of ethanol and long positions of 840,000 gallons of ethanol on the New York Mercantile Exchange. We also have long positions of 2,100,000 MMBTUs of natural gas on the New York Mercantile Exchange. These derivatives have not been designated as an effective hedge for accounting purposes. Corn, ethanol and natural gas positions are forecasted to settle through March 2013, March 2012 and March 2012, respectively. There may be offsetting positions that are not shown on a net basis that could lower the notional amount of positions outstanding as disclosed above.

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 useful lives of property and equipment to be a critical accounting estimate.

We value our inventory at the lower of cost or market. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. These valuations require the use of management's assumptions which do not reflect unanticipated events and circumstances that may occur. In our analysis, we consider future corn costs and ethanol prices, break-even points for our plant and our risk management strategies in place through our derivative instruments and forward contracts. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the valuation of the lower of cost or market on inventory to be a critical accounting estimate.

We enter forward contracts for corn purchases to supply the plant. These contracts represent firm purchase commitments which must be evaluated for potential losses. We have determined that there are no losses that are required to be recognized on these firm purchase commitments related to corn contracts in place at September 30, 2011. Our estimates include various assumptions including the future prices of ethanol, distillers grains and corn.

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. Operating margins have remained positive throughout our fiscal year ended September 30, 2011. We anticipate that margins will remain positive through the remainder of the 2011 calendar year.

30



We were able to reduce our reliance on our revolving lines of credit as a result of more favorable operating conditions in the ethanol market. This allowed us greater liquidity and increased the amount of funds that were available to us on our revolving line of credit. However, we anticipate that margins may tighten in our second fiscal quarter of 2012. 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 and may need to rely on our revolving lines of credit for operations. Our line of credit is set to expire in February 2012, but we expect to renew this credit facility for an additional year to February 2013.

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

 
 
2011
2010
Net cash provided by operating activities
$
21,649,488

19,940,794

Net cash used in investing activities
$
(770,137
)
(3,765,300
)
Net cash used for financing activities
$
(13,395,099
)
(20,122,799
)
Net increase (decrease) in cash
$
7,484,252

(3,947,305
)
Cash, end of period
$
10,802,072

3,317,820


Cash Flow from Operations

Approximately $21,649,000 of cash was provided by operating activities for the fiscal year ended September 30, 2011 as compared to approximately $19,941,000 provided by operating activities for the fiscal year ended September 30, 2010. Our net income from operations for the fiscal year ended September 30, 2011 was approximately $25,509,000 as compared to net income of approximately $20,451,000 for the same period in 2010. We used approximately $18,890,000 for settlement of our derivative instruments for the fiscal year ended September 30, 2011 as compared to the same period in 2010 in which we used $4,260,000 for settlement of our derivative instruments. In addition, we received approximately $11,662,000 from the change in fair value of our derivative instruments in our fiscal year ended September 30, 2011 as compared to $2,424,000 for the same period in 2010.

Cash Flow used in Investing Activities

Cash used in investing activities was approximately $770,000 for the fiscal year ended September 30, 2011 as compared to approximately $3,765,000 for the same period in 2010. Cash used in investing is for our capital expenditures.
    
Cash Flow used in Financing Activities

Cash used in financing activities was approximately $13,395,000 for the fiscal year ended September 30, 2011 as compared to cash used in financing activities of approximately $20,123,000 for the same period in 2010. For the fiscal year ended September 30, 2011, we received proceeds from our short-term line of credit and long-term revolving note with our senior lender as needed. However, both loans were paid down by the end of the year. In addition, we had net payments of approximately $13,389,000 on our long term debt for the fiscal year ended September 30, 2011 as compared to approximately $19,239,000 for the fiscal year ended September 30, 2010.

Our liquidity, results of operations and financial performance will be impacted by many variables, including the market price for commodities such as, but not limited to, corn, ethanol and other energy commodities, as well as the market price for any co-products generated by the facility and the cost of labor and other operating costs.  Assuming future relative price levels for corn, ethanol and distillers grains remain consistent with the relative price levels as of September 30, 2011 we expect operations to generate adequate cash flows to maintain operations. This expectation assumes that we will be able to sell all the ethanol that is produced at the plant.
The following table shows cash flows for the fiscal years ended September 30, 2010 and 2009:

31


 
 
2010
2009
Net cash provided by operating activities
$
19,940,794

(2,245,876
)
Net cash used in investing activities
$
(3,765,300
)
(13,931,689
)
Net cash provided by (used for) financing activities
$
(20,122,799
)
22,980,155

Net increase (decrease) in cash
$
(3,947,305
)
6,803,590

Cash, end of period
$
3,317,820

7,265,125


Cash Flow Used in Operating Activities

Approximately $19,941,000 of cash was provided by operating activities for the fiscal year ended September 30, 2010 as compared to approximately $2,245,000 used in operating activities for the fiscal year ended September 30, 2009. Our net income from operations for the fiscal year ended September 30, 2010 was approximately $20,451,000 as compared to net loss of approximately $951,000 for the same period in 2009.
 
Cash Flow Used in Investing Activities

We experienced a significant decrease in cash used in investing activities for our fiscal year ended September 30, 2010 as compared to 2009. This decrease was primarily a result of a decrease in our payments for construction in process from approximately $13,019,000 for the fiscal year ended September 30, 2009 to approximately $3,480,000 for the same period in 2010.

Cash Flow Provided by (used in) Financing Activities

Cash used in financing activities for the fiscal year ended September 30, 2010 was approximately $20,123,000 as compared to cash provided by financing activities of approximately $22,980,000 for the same period in 2009. This change in cash used in financing activities was the result of payments made on our long term debt financing.

Short and Long Term Debt Sources

On December 19, 2006, 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 $96,000,000, consisting of an $83,000,000 construction note, a $10,000,000 revolving line of credit and a $3,000,000 letter of credit. We also entered into an interest rate swap agreement for $41,500,000 of the construction term loan in order to achieve a fixed rate on a portion of this loan.
In April 2009, the construction loan was converted into multiple term loans one of which was a $41,500,000 Fixed Rate Note, which will be applicable to the interest rate swap agreement, a $31,500,000 Variable Rate Note, and a $10,000,000 Long Term Revolving Note. The term loans have a maturity of five years with a ten-year amortization.
Line of Credit
In February 2011, we extended and amended the $10,000,000 revolving line of credit to expire on February 14, 2012 and changed the interest rate charged on the short-term revolving line of credit to the greater of the three month LIBOR rate plus 400 basis points or 4.5%. The spread on the three month LIBOR rate will adjust down based on the Company meeting certain debt to net worth ratios, measured quarterly. At September 30, 2011 there were no borrowings outstanding on our short-term revolving line of credit and at September 30, 2010 there were no outstanding borrowings on the revolving line of credit. In May 2011, we increased the amount of credit under this line to $15,000,000. In order to do so we paid a commitment fee of one basis point or $5,000 to our senior lender. We expect to renew this line of credit for an additional year through February 2013.
Fixed Rate Note
As indicated above, we have an interest rate swap agreement in connection with the Fixed Rate Note payable to our senior lender. This interest rate swap helps protect our exposure to increases in interest rates and the swap effectively fixes the rate on the loan at 8.11% until April 2014. As of September 30, 2011 and September 30, 2010 we had an interest rate swap with a fair value of approximately $3,483,000 and $4,651,000 respectively, recorded in current and long term liabilities.
The Fixed Rate Note will accrue interest at a rate equal to the three month LIBOR rate plus 300 basis points. We began repaying principal on the Fixed Rate Note in July 2009. The outstanding balance on this note was approximately $34,921,000

32


and $37,996,000 at September 30, 2011 and September 30, 2010, respectively, and is included in current liabilities and long-term debt.

Variable Rate Note and Long Term Revolving Note

We are required to make quarterly payments of approximately $1,546,000 to be applied first to accrued interest on the long term revolving note, then to accrued interest on the variable rate note and finally to principal on the variable rate note. These payments began in July 2009 and continue through April 2014. In regards to the amendment in February 2010, the Company made mandatory excess cash flow payments of $1,000,000 in February 2010 and June 2010 that were applied to the principal of the variable rate note. The maximum availability on the long term revolving note is reduced by $250,000 each quarter. Interest on the variable rate note accrues at the greater of the three month LIBOR rate plus 300 basis points or 5%. At September 30, 2010, the interest rate was 5%. The spread over the three month LIBOR rate shall adjust down based on the Company meeting certain debt to net worth ratios, measured quarterly. Interest on the long term revolving note accrues at the greater of the three month LIBOR rate plus 300 basis points or 5%. At September 30, 2011, the interest rate was 5%. The spread over the three month LIBOR rate shall adjust down based on our compliance with certain debt to net worth ratios, measured quarterly. At September 30, 2011 and September 30, 2010, the balance on the variable rate note was approximately $14,469,000 and $24,420,000, respectively. This note is subject to an annual, mandatory prepayment, based on excess cash flow, capped at $4,000,000 annually and $12,000,000 over the life of the loan. For the year ended September 30, 2011, the calculated prepayment of excess cash flow under the terms of the loan was approximately $4,000,000. We paid installments of $1,000,000 in August 2011 and $3,000,000 in September 2011. For the year ended September 30, 2010, the calculated prepayment of excess cash flow was approximately $2,900,000. We paid installments of $1,000,000 in March and June 2010. The remaining balance of $900,000 was paid in January 2011. All prepayments were applied to the variable rate note. Subsequent to year end, the Company paid off the variable rate note in full.  At September 30, 2011 and September 30, 2010 there were no outstanding borrowings on the long term revolving note. The maximum availability on the long term revolving note at September 30, 2011 was $7,750,000.

Corn Oil Extraction Note
Effective July 31, 2008, we amended our construction loan agreement to include a new loan up to the maximum amount of $3,600,000 for the purchase and installation of a corn oil extraction system and related equipment. On April 8, 2009, the corn oil extraction note converted into a Corn Oil Extraction Term Note, which accrues interest at a rate equal to 3-month LIBOR plus 300 basis points, or 5%, whichever is greater. The principal amount of the Corn Oil Extraction Term Note is payable in equal quarterly installments of $90,000, plus accrued interest, which we began paying in July 2009. As of September 30, 2011 and September 30, 2010, we had $2,790,000 and $3,150,000 outstanding on our corn oil extraction loan respectively.
Letter of Credit
We had one letter of credit outstanding as of September 30, 2010 for $450,000, which was issued in August 2009 to replace our electrical services security deposit. This letter of credit was closed in August 2011 as it was no longer required per the agreement.

Covenants

Our loans are secured by our assets and material contracts. In addition, during the term of the loans, we will be subject to certain financial covenants consisting of a minimum fixed charge coverage ratio, minimum net worth, and minimum working capital. We are required to maintain a fixed charge coverage ratio of no less than 1.25:1.0. Our fixed charge coverage ratio will be 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. The covenants went into effect in April 2009. 
  
We are also required to maintain a minimum net worth of $65,000,000, 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.
We are also required to maintain a minimum working capital of $10,000,000, which is calculated as our current assets plus the amount available for drawing under our long term revolving note, less current liabilities.

33


Our loan agreement requires us to obtain prior approval from our lender before making, or committing to make, capital expenditures in an aggregate amount exceeding $1,000,000 in any single fiscal year. In connection with the amendment in February 2010, the bank increased the fiscal 2010 capital expenditure limit to $4,523,800. For fiscal year 2011, the capital expenditure limit returned to $1,000,000. We may make distributions to our members to cover their respective tax liabilities. In addition, we may also distribute up to 70% of net income provided we maintain certain leverage ratios and are in compliance with all financial ratio requirements and loan covenants before and after any such distributions are made to our members.
We were in compliance with all covenants at September 30, 2011 and we anticipate that we will continue to meet these covenants through September 30, 2012.
We anticipate that our current margins will be sufficient to generate enough cash flow to maintain operations, service our debt and comply with our financial covenants in our loan agreements. However, significant uncertainties in the market continue to exist. Due to current commodity markets, we may produce at negative margins and therefore, we will continue to evaluate our liquidity needs for the upcoming months.
We will continue to work with our lenders to try to ensure that the agreements and terms of the loan agreements are met going forward. However, we cannot provide any assurance that our actions will result in sustained profitable operations or that we will not be in violation of our loan covenants or in default on our principal payments. Presently, we are meeting our liquidity needs and complying with our financial covenants and the other terms of our loan agreements. Should market conditions change radically, and we violate the terms or covenants of our loan or fail to obtain a waiver of any such term or covenant, our primary lender could deem us in default of our loans and require us to immediately repay a significant portion or possibly the entire outstanding balance of our loans. Our lender could also elect to proceed with a foreclosure action on our plant.
Tax Abatement

In October 2006, the real estate that our plant was constructed on was determined to be an economic revitalization area, which qualified us for tax abatement. The abatement period is for a ten year term, with an effective date beginning calendar year end 2009 for the property taxes payable in calendar year 2010. The program allows for 100% abatement of property taxes beginning in year 1, and then decreases on a ratable scale so that in year 11 the full amount of property taxes are due and payable. We must apply annually and meet specified criteria to qualify for the abatement program.

Contractual Cash Obligations

In addition to our long-term debt obligations, we have certain other contractual cash obligations and commitments.  The following tables provide information regarding our contractual obligations and approximate commitments as of September 30, 2011:
 
 
 
Payment Due By Period
Contractual Cash Obligations
 
Total
 
Less than
One Year
 
One to
Three
Years
 
Three to
Five
Years
 
After Five
Years
Long-Term Debt Obligations
 
$
59,613,252

 
$
12,640,976

 
$
46,972,276

 
$

 
$

Operating Lease Obligations
 
2,243,394

 
1,084,800

 
1,158,594

 

 

Purchase Obligations
 
29,377,687

 
28,077,715

 
1,299,972

 

 

Total Contractual Cash Obligations
 
$
91,234,333

 
$
41,803,491

 
$
49,430,842

 
$

 
$

 
The long-term debt obligations in the table above include both principal and interest payments, excluding interest payments on the line of credit, at the interest rates applicable to the obligations as of September 30, 2011.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.


34


ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the impact of market fluctuations associated with interest rates and commodity prices as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in U.S. Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. We use cash, futures and option contracts to hedge changes to the commodity prices of corn and natural gas. We do not enter into these derivative financial instruments for trading or speculative purposes, nor do we designate these contracts as hedges for accounting purposes. We used derivative financial instruments to alter our exposure to interest rate risk. We entered into a interest rate swap agreement that we designated as a cash flow hedge.

Interest Rate Risk

We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding a revolving line of credit and term loans which bear variable interest rates.  Specifically, we have approximately $14,469,000 outstanding in variable rate debt that is recorded in current and long term liabilities as of September 30, 2011.  Our interest rate on our variable rate term loan debt has a minimum interest rate of 5%. Currently, our interest rate on our variable rate term loan debt is at 5%. However, subsequent to year end, the Company paid off the remaining balance of the variable rate note, therefore no longer is exposed to market risk from this loan.

The specifics of each note are discussed in greater detail in “Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations -Liquidity and Capital Resources.”

We manage our floating rate debt using an interest rate swap. We entered into a fixed rate swap to alter our exposure to the impact of changing interest rates on our results of operations and future cash outflows for interest. We use interest rate swap contracts to separate interest rate risk management from the debt funding decision. The interest rate swaps held by us as of September 30, 2011 qualified as a cash flow hedge. For this qualifying hedge, the effective portion of the change in fair value is recognized through earnings when the underlying transaction being hedged affects earnings, allowing a derivative's gains and losses to offset related results from the hedged item on the income statement. As of September 30, 2011, our interest rate swap had a liability fair value of approximately $3,483,000.

Commodity Price Risk

We expect to be exposed to market risk from changes in commodity prices.  Exposure to commodity price risk results from our dependence on corn in the ethanol production process and the sale of ethanol.

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

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

As of September 30, 2011, we have open short (selling) positions for 5,910,000 bushels of corn on the Chicago Board of Trade and open short (selling) positions for 29,431,000 gallons of ethanol on the New York Mercantile Exchange and Chicago Board of Trade to hedge our forward corn contracts and corn inventory. In addition, as of September 30, 2011, we have open long (buying) positions for 5,235,000 bushels of corn on the Chicago Board of Trade and long positions for 840,000 gallons of ethanol on the new York Mercantile Exchange and Chicago Board of Trade. We also have long positions of 2,100,000 MMBTUs of natural gas on the New York Mercantile Exchange. These derivatives have not been designated as an effective hedge for accounting purposes. Corn derivatives are forecasted to settle through March 2013 and ethanol and natural gas derivatives are forecasted to settle through March 2012. There may be offsetting positions that are not shown on a net basis that could lower the notional

35


amount of positions outstanding as disclosed above.

For the fiscal year ended September 30, 2011, we recorded a gain due to the change in fair value of our outstanding corn derivative positions of approximately $6,537,000.  At September 30, 2011, we have committed to purchase approximately 4,950,000 bushels of corn through February 2013 at an average bushel price of $5.85 and the spot price at September 30, 2011 was $6.28 per bushel.   As contracts are delivered, any gains realized will be recognized in our gross margin.  Due to the volatility and risk involved in the commodities market, we cannot be certain that these gains will be realized. 

As corn prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects, but are expected to produce long-term positive growth for us. As of September 30, 2011 we had price protection in place for approximately 12.4% of our anticipated corn needs for the next 12 months. In addition, we had price protection in place for approximately 3.3% of our natural gas needs for the next 12 months.

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 average cost of our corn and natural gas prices and average ethanol price as of September 30, 2011 of the forward and future contracts used to hedge our market risk for corn and natural gas usage requirements. The volumes are based on our expected use and sale of these commodities for a one year period from September 30, 2011. The results of this analysis, which may differ from actual results, are approximately as follows:

 
Estimated Volume Requirements for the next 12 months (net of forward and futures contracts)
Unit of Measure
Hypothetical Adverse Change in Price as of 9/30/11
Approximate Adverse Change to Income
Natural Gas
3,100,000

MMBTU
10
%
$
1,099,899

Ethanol
114,000,000

Gallons
10
%
$
29,095,741

Corn
40,000,000

Bushels
10
%
$
22,011,400

DDGs
318,000

Tons
10
%
$
5,265,000


Liability Risk

We participate in a captive reinsurance company (the “Captive”).  The Captive reinsures losses related to worker's compensation, commercial property and general liability.  Premiums are accrued by a charge to income for the period to which the premium relates and is remitted by our insurer to the captive reinsurer.  The Captive reinsures catastrophic losses in excess of a predetermined amount.  Our premiums are structured such that we have made a prepaid collateral deposit estimated for losses related to the above coverage.  The Captive insurer has estimated and collected an amount in excess of the estimated losses but less than the catastrophic loss limit insured by the Captive. We cannot be assessed in excess of the amount in the collateral fund.


36


ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and
Members of Cardinal Ethanol, LLC
We have audited the accompanying balance sheets of Cardinal Ethanol, LLC as of September 30, 2011 and 2010, and the related statements of operations, members' equity, and cash flows for each of the fiscal years in the three year period ended September 30, 2011. Cardinal Ethanol, LLC's management is responsible for these financial statements. 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 (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Cardinal Ethanol, LLC as of September 30, 2011 and 2010, and the results of its operations and its cash flows for each of the fiscal years in the three year period ended September 30, 2011, in conformity with accounting principles generally accepted in the United States of America.



/s/ Boulay, Heutmaker, Zibell & Co. P.L.L.P
Minneapolis, Minnesota
December 13, 2011


37


CARDINAL ETHANOL, LLC
Balance Sheets

 ASSETS
September 30, 2011
 
September 30, 2010


 

Current Assets

 

Cash
$
10,802,072

 
$
3,317,820

Restricted cash
2,358,802

 
4,550,665

Trade accounts receivable, net of an allowance of $23,500 and $0, respectively
19,100,842

 
13,262,640

Miscellaneous receivables
471,403

 
1,030,197

Inventories
11,732,998

 
8,333,140

Deposits
192,250

 
409,940

Prepaid and other current assets
435,282

 
965,099

Commodity derivative instruments
4,736,691

 
29,400

Total current assets
49,830,340

 
31,898,901



 

Property, Plant, and Equipment

 

Land and land improvements
21,105,097

 
21,082,869

Plant and equipment
121,310,752

 
117,122,818

Building
6,991,721

 
6,991,721

Office equipment
356,516

 
316,219

Vehicles
31,928

 
31,928

Construction in process

 
3,480,322


149,796,014

 
149,025,877

Less accumulated depreciation
(24,626,303
)
 
(16,245,531
)
Net property, plant, and equipment
125,169,711

 
132,780,346



 

Other Assets

 

Deposits
80,000

 
80,000

Investment
453,676

 
266,583

Financing costs, net of amortization
343,023

 
505,149

Total other assets
876,699

 
851,732



 

Total Assets
$
175,876,750

 
$
165,530,979



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

38


CARDINAL ETHANOL, LLC
Balance Sheets

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


 

Current Liabilities

 

Accounts payable
$
2,081,140

 
$
2,154,370

Accounts payable- corn
4,059,970

 
3,266,780

Construction retainage payable
101,928

 
351,700

Accrued expenses
1,547,097

 
1,264,755

Commodity derivative instruments
88,390

 
2,609,188

Derivative instruments - interest rate swap
1,521,531

 
1,520,315

Current maturities of long-term debt and capital lease obligations
9,228,305

 
9,395,041

Total current liabilities
18,628,361

 
20,562,149



 

Long-Term Debt and Capital Lease Obligations
42,960,017

 
56,188,380



 

Derivative Instruments - interest rate swap
1,961,239

 
3,130,402



 

Commitments and Contingencies

 



 

Members’ Equity

 

Members' contributions, net of cost of raising capital, 14,606 units authorized, issued and outstanding
70,912,213

 
70,912,213

Accumulated other comprehensive loss
(3,482,769
)
 
(4,650,717
)
Retained earnings
44,897,689

 
19,388,552

Total members' equity
112,327,133

 
85,650,048



 

Total Liabilities and Members’ Equity
$
175,876,750

 
$
165,530,979



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

39


CARDINAL ETHANOL, LLC
Statements of Operations

Fiscal Year Ended
 
Fiscal Year Ended
 
Fiscal Year Ended

September 30, 2011
 
September 30, 2010
 
September 30, 2009


 

 

Revenues
$
337,019,930

 
$
224,807,338

 
$
167,738,057



 

 

Cost of Goods Sold

 

 

Cost of goods sold
302,690,475

 
195,880,762

 
159,079,141

Lower of cost or market adjustment

 

 
1,595,476

Total
302,690,475

 
195,880,762

 
160,674,617



 

 

Gross Profit
34,329,455

 
28,926,576

 
7,063,440



 

 

Operating Expenses

 

 

Professional fees
526,368

 
612,115

 
757,950

General and administrative
3,724,384

 
3,123,415

 
2,968,101

Total
4,250,752

 
3,735,530

 
3,726,051



 

 

Operating Income
30,078,703

 
25,191,046

 
3,337,389



 

 

Other Income (Expense)

 

 

Grant income

 

 
24,702

Interest income
3,891

 
2,792

 
2,654

Interest expense
(4,412,755
)
 
(4,797,649
)
 
(4,345,390
)
Miscellaneous income (expenses)
(160,702
)
 
54,390

 
29,460

Total
(4,569,566
)
 
(4,740,467
)
 
(4,288,574
)


 

 

Net Income (Loss)
$
25,509,137

 
$
20,450,579

 
$
(951,185
)


 

 

Weight Average Units Outstanding - basic and diluted
14,606

 
14,606

 
14,606



 

 

Net Income (Loss) Per Unit - basic and diluted
$
1,746.48

 
$
1,400.15

 
$
(65.12
)
 
 
 
 
 
 
Distributions Per Unit
$

 
$
60.00

 
$

 
 
 
 
 
 


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





40


CARDINAL ETHANOL, LLC
Statements of Cash Flows

Fiscal Year Ended
 
Fiscal Year Ended
 
Fiscal Year Ended

September 30, 2011
 
September 30, 2010
 
September 30, 2009
Cash Flows from Operating Activities

 


 

Net income (loss)
$
25,509,137

 
$
20,450,579

 
$
(951,185
)
Adjustments to reconcile net income (loss) to net cash from operations:

 


 

Depreciation and amortization
8,542,898

 
8,451,832

 
8,099,316

Change in fair value of derivative instruments
11,661,874

 
2,424,135

 
(3,072,937
)
Non-cash dividend income
(187,093
)
 
(266,583
)
 

Lower of cost or market adjustments to inventory

 

 
1,595,476

Provision for uncollectible accounts
35,847

 

 

Change in operating assets and liabilities:

 


 

Restricted cash
2,191,863

 

 

Trade accounts receivables
(5,874,049
)
 
(7,317,494
)
 
(5,945,146
)
Miscellaneous receivable
558,794

 
(8,718
)
 
(994,479
)
Inventories
(3,399,858
)
 
(2,541,838
)
 
(7,386,778
)
Prepaid and other current assets
529,817

 
(118,328
)
 
(789,048
)
Deposits
217,690

 
923,947

 
322,563

Derivative instruments
(18,889,962
)
 
(4,260,000
)
 
2,937,925

Accounts payable
(73,230
)
 
824,585

 
1,152,663

Accounts payable-corn
793,190

 
1,709,592

 
1,556,398

Construction retainage payable
(249,772
)
 

 

Accrued expenses
282,342

 
(330,915
)
 
1,229,356

Net cash provided by (used in) operating activities
21,649,488

 
19,940,794

 
(2,245,876
)


 


 

Cash Flows from Investing Activities

 


 

Capital expenditures
(770,137
)
 
(284,978
)
 
(912,507
)
Payments for construction in process

 
(3,480,322
)
 
(13,019,182
)
   Net cash used for investing activities
(770,137
)
 
(3,765,300
)
 
(13,931,689
)


 


 

Cash Flows from Financing Activities

 


 

Dividends paid

 
(876,360
)
 

Payments for financing costs

 

 
(24,744
)
Payments for capital lease obligations
(6,113
)
 
$
(7,770
)
 
(7,245
)
Proceeds from long-term debt
29,800,000

 

 
24,806,928

Payments on long-term debt
(43,188,986
)
 
(19,238,669
)
 
(1,794,784
)
Net cash provided by (used for) financing activities
(13,395,099
)
 
(20,122,799
)
 
22,980,155




 


 

Net Increase (Decrease) in Cash
7,484,252

 
(3,947,305
)
 
6,803,590




 


 

Cash – Beginning of Period
3,317,820

 
7,265,125

 
461,535




 


 

Cash – End of Period
$
10,802,072

 
$
3,317,820

 
$
7,265,125


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


41



CARDINAL ETHANOL, LLC
Statements of Cash Flows

Fiscal Year Ended
 
Fiscal Year Ended
 
Fiscal Year Ended

September 30, 2011
 
September 30, 2010
 
September 30, 2009
Supplemental Cash Flow Information





Interest paid
$
4,559,126


$
5,067,484


$
2,874,893







Supplemental Disclosure of Noncash Investing and Financing Activities





Construction costs in construction retainage and accounts payable
$
101,928


$


$
351,700

Gain (loss) on derivative instruments included in other comprehensive loss
$
1,167,948


$
(519,168
)