SOUTHWEST IOWA RENEWABLE ENERGY, LLC - FORM 10-K

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - SOUTHWEST IOWA RENEWABLE ENERGY, LLC	Financial_Report.xls
EX-32.2 - SECTION 1350/906 CERTIFICATION/KROYMANN - SOUTHWEST IOWA RENEWABLE ENERGY, LLC	exhibit322_112211.htm
EX-32.1 - SECTION 1350/906 CERTIFICATION/CAHILL - SOUTHWEST IOWA RENEWABLE ENERGY, LLC	exhibit321_112211.htm
EX-31.2 - SECTION 302 CERTIFICATION/KROYMANN - SOUTHWEST IOWA RENEWABLE ENERGY, LLC	exhibit312_112211.htm
EX-31.1 - SECTION 302 CERTIFICATION/CAHILL - SOUTHWEST IOWA RENEWABLE ENERGY, LLC	exhibit311_112211.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

Form 10-K
(Mark one)
R	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended September 30, 2011

£	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from _________ to __________

		Commission file number 000-53041

SOUTHWEST IOWA RENEWABLE ENERGY, LLC
(Exact name of registrant as specified in its charter)

Iowa			20-2735046
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

10868 189th Street, Council Bluffs, Iowa			51503
(Address of principal executive offices)			(Zip Code)

Registrant’s telephone number (712) 366-0392

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

Title of each class			Name of each exchange on which registered

Securities registered under Section 12(g) of the Exchange Act:
Series A Membership Units
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes £ No R
Indicate by check mark whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £ Indicate by check mark whether the registrant has submitted electronically on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No R
Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer £ Accelerated filer £ Non-accelerated filer £ Smaller reporting company R
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R
As of September 30, 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 $52,134,000.
As of September 30, 2011, the Company had 8,805 Series A, 3,334 Series B and 1,000 Series C Membership Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE—None

PART I		1

Item 1.	Business	2

Item 1A.	Risk Factors	14

Item 2.	Properties	25

Item 3.	Legal Proceedings	25

Item 4.	(Removed and Reserved)	25

PART II		25

Item 5.	Market for Registrant’s Common Equity, Related Member Matters, and Issuer Purchases of Equity Securities	25

Item 6.	Selected Financial Data	25

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	27

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	36

Item 8.	Financial Statements and Supplementary Data	37

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56

Item 9A.	Controls and Procedures	56

Item 9B.	Other Information	56

PART III		57

Item 10.	Directors, Executive Officers and Corporate Governance	57

Item 11.	Executive Compensation	60

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Member Matters	63

Item 13.	Certain Relationships and Related Transactions, and Director Independence	63

Item 14.	Principal Accountant Fees and Services.	66

PART IV		67

Item 15.	Exhibits and Financial Statement Schedules	67

SIGNATURES		72

PART I

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K of Southwest Iowa Renewable Energy, LLC (the “Company,” “we,” or “us”) contains historical information, as well as forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance, or our expected future operations and actions. In some cases, you can identify forward-looking statements by terminology such as “may,” “will”, “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,” “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions. These forward-looking statements are only our predictions based on current information and involve numerous assumptions, risks and uncertainties. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the reasons described in this report. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:

Changes in the availability and price of corn, natural gas, and steam;

Our inability to comply with our credit agreements required to continue our operations;

Negative impacts that our hedging activities may have on our operations;

Decreases in the market prices of ethanol and distillers grains;

Ethanol supply exceeding demand; and corresponding ethanol price reductions;

Changes in the environmental regulations that apply to our plant operations;

Changes in 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;

Changes in federal and/or state laws (including the elimination of any federal and/or state ethanol tax incentives);

Changes and advances in ethanol production technology;

Additional ethanol plants built in close proximity to our ethanol facility in southwest Iowa;

Competition from alternative fuel additives;

Changes in interest rates and lending conditions of our loan covenants;

Our ability to retain key employees and maintain labor relations; and

Volatile commodity and financial markets.

These forward-looking statements are based on management’s estimates, projections and assumptions as of the date hereof and include the assumptions that underlie such statements. Any expectations based on these forward-looking statements are subject to risks and uncertainties and other important factors, including those discussed below and in the section titled “Risk Factors.” Other risks and uncertainties are disclosed in our prior Securities and Exchange Commission (“SEC”) filings. These and many other factors could affect our future financial condition and operating results and could cause actual results to differ materially from expectations based on forward-looking statements made in this document or elsewhere by Company or on its behalf. We undertake no obligation to revise or update any forward-looking statements. The forward-looking statements contained in this Form 10-K are included in the safe harbor protection provided by Section 27A of the Securities Act of 1933, as amended (the “1933 Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

AVAILABLE INFORMATION

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

Item 1. Business.

The Company is an Iowa limited liability company located in Council Bluffs, Iowa, and was formed in March, 2005 to construct and operate a 110 million gallon capacity ethanol plant. We began producing ethanol in February, 2009 and sell our ethanol, modified wet distillers grains with solubles, and corn syrup in the continental United States. We sell our dried distillers grains with solubles in the continental United States, Mexico and the Pacific Rim. During the first quarter of our fiscal year ended September 30, 2011 (“Fiscal 2011”), we implemented a corn oil extraction system, the corn oil from which accounts for approximately 2% of our revenue stream.

Our production facility (the “Facility”) is located in Pottawattamie County in southwestern Iowa. It is near two major interstate highways, within a mile of the Missouri River and has access to five major rail carriers. This location is in close proximity to raw materials and product market access. The Facility receives corn and chemical deliveries primarily by truck but is able to utilize rail delivery if necessary. Finished products are shipped by rail and truck. The site has access to water from ground wells and from the Missouri River. Additionally, in close proximity to the Facility’s primary energy source (steam), there are two natural gas providers available, both with infrastructure immediately accessible to the Facility.

During the last half of Fiscal 2011, the Missouri river experienced significant flooding as a result of unprecedented amounts of rain and snow in the Missouri River basin. This produced a sustained flood lasting many weeks at a 500-year flood level (a level which has a 0.2 percent chance of occurring). While there were levee failures elsewhere, we were fortunate that the levees held around our Facility. We did experience minimal rail disruption due to flooding in the surrounding areas to the North and South of the Facility, but our operations were not significantly impacted.

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.

Rail Access

We own a six mile loop railroad track for rail service to our Facility. Our track comes off the Council Bluffs Energy Center line where interstate I-29 crosses and proceeds south along the east side of Pony Creek. The track terminates in a loop-track south of the Facility, which accommodates 100 car trains. We entered into an Industrial Track Agreement with CBEC Railway, Inc. (the “Track Agreement”), which governs our use of the loop railroad and requires, among other things, that we maintain the loop track.

We are a party to an Amended and Restated Railcar Lease Agreement (“Railcar Agreement”) with Bunge North America, Inc. (“Bunge”) for the sublease of 325 ethanol cars and 300 hopper cars which are used for the delivery and marketing of our ethanol and Distillers Grains. Under the Railcar Agreement, we sublease railcars for terms lasting 120 months and continuing on a month to month basis thereafter. The Railcar Agreement will terminate upon the expiration of all railcar subleases.

Employees

We had 60 employees, 59 of which are full time, as of September 30, 2011. We are not subject to any collective bargaining agreements and we have not experienced any work stoppages. Our management considers our employee relationships to be favorable.

Principal Products

The principal products we produce are ethanol and distillers grains.

Ethanol

Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains, which can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based gasoline substitute. More than 99% of all ethanol produced in the United States is used in its primary form for blending with unleaded gasoline and other fuel products. The principal purchasers of ethanol are generally wholesale gasoline marketers or blenders. Ethanol is shipped by truck in the local markets, and by rail in the national market.

We produced 115.7 and 110.6 million gallons of ethanol for Fiscal 2011 and the year ended September 30, 2010 (“Fiscal 2010”), respectively, and approximately 81% and 84% of our revenue was derived from the sale of ethanol in Fiscal 2011 and 2010, respectively.

Co-products

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 and beef industry. Distillers grains contain by-pass protein that is superior to other protein supplements such as cottonseed meal and soybean meal. By-pass proteins are more digestible to the animal, thus generating greater lactation in milk cows and greater weight gain in beef cattle. We produce two forms of distillers grains at our dry mill ethanol facility: wet distillers grains (“WDGS”) and DDGS. WDGS are processed corn mash that has been dried to approximately 50% to 65% moisture. WDGS have a shelf life of approximately seven days and are often sold to nearby markets. DDGS are processed corn mash that has been dried to approximately 10% to 12% moisture. It has a longer shelf life and may be sold and shipped to any market regardless of its location in relation to our ethanol plant.

We sold 305,929 and 302,223 tons of dried distillers grains in Fiscal 2011 and 2010, respectively. Approximately 17% and 16% of our revenue was derived from the sale of distillers grains in Fiscal 2011 and 2010, respectively.

During Fiscal 2011 we installed an ICM corn oil extraction system and began selling corn oil. This system separates corn oil from the post-fermentation syrup stream as it leaves the evaporators of the ethanol plant. The corn oil is then routed to storage tanks, and the remaining concentrated syrup is routed to the plant’s syrup tank. Corn oil can be marketed as either a feed additive or a biodiesel feedstock. We sold 5,858 tons of corn oil in Fiscal 2011, representing approximately 2% of our revenue.

Principal Product Markets

As described below in “Distribution Methods,” we market and distribute all of our ethanol and distillers grains through a professional third party marketer. Our ethanol and distillers grains marketer makes all decisions with regard to where our products are marketed. Our ethanol and distillers grains are primarily sold in the domestic market; however, as United States production of ethanol and distillers grains continue to expand, we anticipate increased international sales of our products. Currently, approximately 50% of our distillers grains are exported outside of the continental United States. Management anticipates that demand for distillers grains in the Asian market may show decreased demand for distillers grains in the future due to the current high level of prices. As distillers grains become more accepted as an animal feed substitute throughout the world, distillers grains exporting may increase.

Distribution Methods

In 2009, Bunge became the exclusive purchaser of our ethanol pursuant to an Ethanol Purchase Agreement (the “Ethanol Agreement”). Bunge markets our ethanol in national, regional and local markets. Under the Ethanol Agreement, we sell Bunge all of the ethanol produced at the Facility, and Bunge purchases the same, up to the Facility’s nameplate capacity. We pay Bunge a per-gallon fee for ethanol sold by Bunge under the Ethanol

Agreement, subject to a minimum annual fee of $750,000 and adjustments according to specified indexes after three years. The initial term of the Ethanol Agreement runs until August 19, 2012 and it will automatically renew for successive three-year terms unless one party provides the other notice of their election to terminate 180 days prior to the end of the term.

We entered into a Distillers Grain Purchase Agreement dated October 13, 2006, as amended (“DG Agreement”) with Bunge, under which Bunge is obligated to purchase from us and we are obligated to sell to Bunge all distillers grains produced at our Facility. If we find another purchaser for distillers grains offering a better price for the same grade, quality, quantity, and delivery period, we can ask Bunge to either market directly to the other purchaser or market to another purchaser on the same terms and pricing.

The initial term of the DG Agreement runs until February 1, 2019, and will automatically renew for additional three year terms unless one party provides the other party with notice of election to not renew 180 days or more prior to expiration. Under the DG Agreement, Bunge pays us a purchase price equal to the sales price minus the marketing fee and transportation costs. The sales price is the price received by Bunge in a contract consistent with the DG Marketing Policy or the spot price agreed to between Bunge and us. Bunge receives a marketing fee consisting of a percentage of the net sales price, subject to a minimum yearly payment of $150,000. Net sales price is the sales price less the transportation costs and rail lease charges. The transportation costs are all freight charges, fuel surcharges, and other accessorial charges applicable to delivery of Distillers Grains. Rail lease charges are the monthly lease payment for rail cars along with all administrative and tax filing fees for such leased rail cars.

Pursuant to a Corn Oil Agency Agreement (the “Corn Oil Agreement”), effective as of November 12, 2010, between us and Bunge, we exclusively use Bunge as our agent to market corn oil produced at the Facility. For its efforts in marketing our corn oil, we pay Bunge a marketing fee based on the amount of corn oil sold. Beginning on November 12, 2013, the marketing fee will be adjusted based on the change in a specified formula.

Description of Dry Mill Process

Our Facility produces ethanol by processing corn. The corn is received by semitrailer truck (or railcar if needed), and is weighed and stored in a receiving building. It is then transported to a scalper to remove rocks and debris before being conveyed to storage bins. Thereafter, the corn is transported to a hammer mill or grinder where it is ground into a mash and conveyed into a tank for processing. We add water, heat and enzymes to break the ground corn into a fine liquid. This liquid is heat sterilized and pumped to a tank where other enzymes are added to convert the starches into glucose sugars. Next, the liquid is pumped into fermenters, where yeast is added, to begin a 55 to 60 hour batch fermentation process. A distillation process divides the alcohol from the corn mash. The alcohol which exits the distillation process is then partially dried. The resulting 200 proof alcohol is pumped into storage tanks. Corn mash from the distillation process is then pumped into one of several centrifuges. Water from the centrifuges is dried into a thick syrup. The solids that exit the centrifuge or evaporators are called wet cake and are conveyed to dryers. Corn mash is added to the wet cake as it enters the dryer, where moisture is removed. This process produces distillers grains.

Raw Materials

Corn Requirements

Ethanol can be produced from a number of different types of grains and waste products. However, approximately 90% of ethanol in the United States today is produced from corn. The cost of corn is affected primarily by supply and demand factors such as crop production, carryout, exports, government policies and programs, risk management and weather. With the volatility of the commodity markets, we cannot predict the future price of corn.

Our Facility needs approximately 39.3 million bushels of corn per year, or approximately 108,000 bushels per day, as the feedstock for its dry milling process. During Fiscal 2011 and 2010, we purchased 40.11 and 40.85 million bushels of corn, respectively, which was obtained primarily from local markets. To assist in our securing the

necessary quantities of grain for our plant, we entered into a Grain Feedstock Supply Agreement dated December 15, 2008 (the “Supply Agreement”) with AGRI-Bunge, LLC (“AB”), an affiliate of our significant equity holder Bunge. AB has since assigned its rights under the Supply Agreement to Bunge. Under the Supply Agreement, Bunge provides us with all of the corn we need to operate our ethanol plant, and we have agreed to only purchase corn from Bunge. Bunge provides grain originators who work at the Facility for purposes of fulfilling its obligations under the Supply Agreement. We pay Bunge a per-bushel fee for corn procured by Bunge for us under the Supply Agreement, subject to a minimum annual fee of $675,000 and adjustments according to specified indexes after three years. The term of the Supply Agreement is ten years, subject to earlier termination upon specified events.

The price and availability of corn are subject to significant fluctuations, depending upon a number of factors which affect commodity prices in general, including crop conditions, weather, governmental programs and foreign purchases.

Energy Requirements

The production of ethanol is a very energy intensive process which uses significant amounts of electricity and a heat source. Presently, about 26,250 BTUs of energy are required to produce a gallon of ethanol when we dry 100% of our distillers grains. It is our goal to operate the plant as efficiently as possible, reducing the amount of energy consumed per gallon of ethanol produced. Additionally, water supply and quality are important considerations.

Steam

Unlike most ethanol producers in the United States which use natural gas as their primary energy source, our primary energy source is steam. We believe utilizing steam makes us more competitive, as under certain energy market conditions our energy costs will be lower than natural gas fired plants. We have entered into an Executed Steam Service Contract (“Steam Contract”) with MidAmerican Energy Company (“MidAm”), under which MidAm provides us the steam required by us, up to 475,000 pounds per hour. The Steam Contract remains in effect until February 1, 2019. During Fiscal 2011 and 2010, we purchased approximately 2,340,184 and 2,332,807 MMBTUs of steam, respectively.

Natural Gas

Although steam is our primary energy source and accounts for around 77% of our energy usage, we have installed two natural gas back-up boilers for use when our steam service is temporarily unavailable. Natural gas is also needed for incidental purposes. Natural gas prices fluctuate with the energy complex in general. Natural gas prices trended lower in Fiscal 2011 as a result of the drop in crude oil prices and based on anticipated increases in supply relative to demand. We do not expect natural gas prices to remain steady in the near future and anticipate the prices to trend higher into the winter months of 2011-2012 as seasonal demand for natural gas increases due to heating needs in the colder weather. We have entered into a natural gas supply agreement with Constellation Energy for our long term natural gas needs. During Fiscal 2011 and 2010, we purchased 679,760 and 582,494 MMBTUs of natural gas, respectively.

Electricity

Our Facility requires a large continuous supply of electrical energy. We have purchased 70,608 and 68,601 kilowatts of electricity in Fiscal 2011 and 2010, respectively, from MidAm under an Electric Service Contract (“Electric Contract”) dated December 15, 2006. We agreed to pay MidAm (i) a service charge of $200 per meter, (ii) a demand charge of $3.38 in the summer and $2.89 in the winter (iii) a reactive demand charge of $0.49/kVAR of reactive demand in excess of 50% of billing demand, (iv) an energy charge ranging from $0.03647 to $0.01837 per kilowatt hour, depending on the amount of usage and season, (v) tax adjustments, (vi) AEP and energy efficiency cost recovery adjustments, and (vii) a CNS capital additions tracker. These rates only apply to the primary voltage electric service provided under the Electric Contract. The electric service will continue at these prices for up to 60 months, but in any event will terminate on June 30, 2012.

Water

We require a significant supply of water. Much of the water used in an 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 (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 is recycled back into the process, which minimizes the effluent. Our Facility’s fresh water requirements are approximately 1,500,000 gallons per day. Our water requirements are supplied through three ground wells which are permitted to produce up to 2,000,000 gallons of water per day, and we can access water from the Missouri River.

Patents, Trademarks, Licenses, Franchises and Concessions

SIRETM, our logos, trade names and service marks used in this report are our property. We were granted a license by ICM, Inc. (“ICM”) to use certain ethanol production technology necessary to operate our Facility. There is no fee or definitive term for this license with ICM, as it is perpetual in nature.

Risk Management and Hedging Transactions

The profitability of our operations is highly dependent on the impact of market fluctuations associated with commodity prices. We use various derivative instruments as part of an overall strategy to manage market risk and to reduce the risk that our ethanol production will become unprofitable when market prices among our principal commodities do not correlate. In order to mitigate our commodity price risks, we enter into hedging transactions, including forward corn, ethanol, and distillers grain contracts, in an attempt to partially offset the effects of corn price volatility. We also enter into over-the-counter and exchange-traded futures and option contracts for corn, ethanol and distillers grains, designed to limit our exposure to increases in the price of corn and manage ethanol price fluctuations. Although we believe that our hedging strategies can reduce the risk of commodity price fluctuations, the financial statement impact of these activities depends upon, among other things, the prices involved and our ability to physically receive or deliver the commodities involved. Our hedging activities can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged. As corn and ethanol 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.

Hedging arrangements expose us to the risk of financial loss in situations where the counterparty to the hedging contract defaults or, in the case of exchange-traded contracts, where there is a change in the expected differential between the price of the commodity underlying the hedging agreement and the actual prices paid or received by us for the physical commodity bought or sold. There are also situations where the hedging transactions themselves may result in losses, as when a position is purchased in a declining market or a position is sold in a rising market. Hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol and distillers grains.

We continually monitor and manage our commodity risk exposure and our hedging transactions as part of our overall risk management policy. As a result, we may vary the amount of hedging or other risk mitigation strategies we undertake, and we may choose not to engage in hedging transactions. Our ability to hedge is always subject to our liquidity and available capital.

Dependence on One or a Few Major Customers

As discussed above, we have marketing and agency agreements with Bunge, a significant equity holder, for the purpose of marketing and distributing our principal products. We rely on Bunge for the sale and distribution of all of our products and are highly dependent on Bunge for the successful marketing of our products. We do not

currently have the ability to market our ethanol and distillers grains internally should Bunge be unable or refuse to market these products at acceptable prices. We anticipate that we would be able to secure alternate marketers should Bunge fail, however, a loss of the marketer could significantly harm our financial performance.

Our Competition

Domestic Ethanol Competitors

The ethanol we produce is similar to ethanol produced by other plants. According to Renewable Fuels Association, there were 209 ethanol plants in operation in the United States with the capacity to produce 14.2 billion gallons of ethanol annually as of September 26, 2011. An additional eight plants are under construction or expanding, which could add an additional estimated 0.27 billion gallons of annual production capacity. On a national level, there are numerous other production facilities with which we are in direct competition, many of whom have greater resources and experience than we have. Some of our competitors are, among other things, capable of producing a significantly greater amount of ethanol or have multiple ethanol plants that may help them achieve certain benefits that we cannot achieve with one ethanol plant. Large producers may have an advantage over us from economies of scale and negotiating position with purchasers. Further, new products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages over us and harm our business.

Foreign Ethanol Competitors

We also face competition from foreign producers of ethanol and such competition may increase significantly in the future. Large international companies with much greater resources than ours have developed, or are developing, increased foreign ethanol production capacities. Brazil is the world’s second largest ethanol producer. Brazil makes ethanol primarily from sugarcane, a process which has historically been lower cost than producing ethanol from corn. This is due primarily to the fact that sugarcane does not need to go through the extensive cooking process to convert the feedstock to sugar. Several large companies produce ethanol in Brazil, including Bunge which, according to the Biofuels Digest, is one of the largest ethanol producers in Brazil. Another example of a large company producing ethanol in Brazil is Royal Dutch Shell, which recently announced that it intends to form a joint venture with Cosan, Brazil’s largest ethanol producer, which, when completed, will be one of the world’s largest ethanol producers.

The Caribbean region is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative. Large multinational companies have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would 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 though transportation and infrastructure constraints may temper the market impact on the United States.

Other Competition

Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development by ethanol and oil companies. Ethanol production technologies continue to evolve, and changes are expected to occur primarily in the area of ethanol made from cellulose obtained from other sources of biomass such as switchgrass or fast growing poplar trees. Because our plant is designed as single-feedstock facilities, we have limited ability to adapt the plants to a different feedstock or process system without additional capital investment and retooling.

Competition for Corn

Competition for corn supply from other ethanol plants and other corn consumers exists around our Facility. According to Iowa Renewable Fuels Association, as of September 8, 2011, there were 40 operational ethanol plants in Iowa. The plants are concentrated, for the most part, in the northern and central regions of the state where a

majority of the corn is produced. The existence and development of other ethanol plants, particularly those in close proximity to our plant, will increase the demand for corn that may result in higher costs for supplies of corn.

We compete with other users of corn, including ethanol producers regionally and nationally, producers of food and food ingredients for human consumption (such as high fructose corn syrup, starches, and sweeteners), producers of animal feed and industrial users. According to the United States Department of Agriculture (“USDA”), for 2010: 5.02 billion bushels of U.S. corn was used in ethanol production, with 1.4 billion bushels being used in food and other industrial uses, and 2.0 billion bushels used for export. As of November 9, 2011, the USDA increased the forecast of the amount of corn to be used for ethanol production during the current marketing year (2011-12). The 2011-12 forecast, which estimates that a total of 5.00 billion bushels of corn will be used in the production of corn ethanol, is approximately 0.20 million bushels less than used in that category last year. The USDA cites the absence of the Volumetric Ethanol Excise Tax Credit (“VEETC”) in 2012 as well as the current economic forecast as the reason for the decrease. In the November 2011 updates, the USDA decreased the projection of U.S. corn exports for the current marketing year by 1.11 billion bushels. This projection is 126 million bushels less than the projection from fall 2010.

Principal Supply & Demand Factors

Ethanol

Generally

Ethanol prices increased during Fiscal 2011 as a direct response to increasing corn prices. Management currently expects ethanol prices will continue to be directly related to the price of corn. Management believes the industry will need to grow both product delivery infrastructure and demand for ethanol in order to increase production margins in the near and long term. According to Renewable Fuels Association, there were 209 ethanol plants in operation in the United States with the capacity to produce 14.2 billion gallons of ethanol annually as of September 26, 2011. Currently, eight plants are under construction or expanding, which could add an additional estimated 0.27 billion gallons of annual production capacity. Unless the new supply of ethanol is equally met with ethanol demand, downward pressure on ethanol prices could start.

Management believes it is important that ethanol blending capabilities of the gasoline market be expanded to increase demand for ethanol. Recently, there has been increased awareness of the need to expand ethanol distribution and blending infrastructure, which would allow the ethanol industry to supply ethanol to markets in the United States that are not currently blending ethanol.

VEETC

The profitability of the ethanol industry is impacted by federal ethanol supports and tax incentives, such as the VEETC blending credit. VEETC is a volumetric ethanol excise tax credit, which gasoline distributors apply for. Based on volume, the VEETC allows greater refinery flexibility in blending ethanol since it makes the tax credit available on all ethanol blended with gasoline, diesel and ethyl tertiary butyl ether, including ethanol in E85. Under provisions of the 2008 Farm Bill, the tax credit under VEETC dropped to 45 cents per gallon of pure ethanol and 38 cents per gallon of E85. The VEETC is scheduled to expire on December 31, 2011. A number of bills have been introduced in the Congress to extend ethanol tax credits, including some bills that would make the ethanol tax credits permanent. There can be no assurance, however, that such legislation will be enacted. We are uncertain what impact the elimination or further reduction of VEETC or other similar federal tax incentives to the ethanol industry would have on our business. As of the date of this report on Form 10-K, the VEETC has not been renewed.

RFS

Significant federal legislation which impacts ethanol demand includes the Energy Policy Act of 2005 (the “2005 Act”) and the Energy Independence and Security Act of 2007 (the “2007 Act”). The 2005 Act created the Renewable Fuels Standard (the “RFS”), which was designed to favorably impact the ethanol industry by enhancing

both the production and use of ethanol. 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 Energy Improvement & Extension Act of 2008 (the “2008 Act”) included cellulosic ethanol supports applicable to corn-based ethanol and bolsters those contained in the 2007 Act. These supports have impacted the ethanol industry by enhancing both the production and use of ethanol. The U.S. Environmental Protection Agency (the “EPA”) is responsible for revising and implementing regulations to ensure that transportation fuel sold in the United States contains a minimum volume of renewable fuel. On February 3, 2010, the EPA implemented a regulation that required 12.95 billion gallons of renewable fuel be sold or dispensed in 2010, increasing to 36 billion gallons by 2022. This requirement does not apply just to corn-based ethanol, but includes all forms of fuel created from feedstocks that qualify as “renewable biomass.” The EPA regulation also expanded the RFS program beyond gasoline to generally cover all transportation fuel. We cannot assure that this program’s mandates will continue in the future.

The 2007 Act also requires facilities beginning operations after its enactment to operate with at least a 20% reduction in lifecycle greenhouse gas emissions compared to gasoline. In the event the EPA determines this size of reduction is not feasible, it may reduce the required reduction, but in no event will a new plant be allowed to operate at less than a 10% reduction in lifecycle greenhouse gas emissions. We believe that our use of steam as our primary energy source reduces our emissions, as compared to other ethanol plants which utilize natural gas or coal as their primary heat source.

The ethanol industry’s rapid expansion could yield more ethanol than the RFS requirements depending on how quickly idle capacity is brought back online, when under construction capacity begins producing and other factors. This means the ethanol industry must continue to generate demand for ethanol beyond the minimum floor set by the RFS in order to support current ethanol prices. We are dependent on Bunge’s ability to market the ethanol in this competitive environment.

As of October 5, 2011, legislation was introduced in the United States Congress to reduce the RFS by as much as 50% if corn supplies on an arbitrary date fall below predetermined stock-to-use ratio. The bill as introduced is termed the “RFS Flexibility Act.” We believe that any reversal in federal policy on the RFS could have a profound impact on the ethanol industry.

State Initiatives

In 2006, Iowa passed legislation promoting the use of renewable fuels in Iowa. One of the most significant provisions of the Iowa renewable fuels legislation is a renewable fuels standard encouraging 10% of the gasoline sold in Iowa to consist of renewable fuels. This renewable fuels standard increases incrementally to 25% of the gasoline sold in Iowa by 2019. Additionally, certain plants located in Nebraska that were in production on June 30, 2004 are eligible for state incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years. While we cannot qualify for these incentives, they do provide an economic advantage to some of our competitors.

E85

Demand for ethanol has been affected by moderately increased consumption of E85 fuel. E85 fuel is a blend of 85% ethanol and 15% gasoline. E85 can be used as an aviation fuel, as reported by the National Corn Growers Association, and as a hydrogen source for fuel cells. According to the United States Department of Energy (the “USDOE”), there are currently more than eight million flexible fuel vehicles capable of operating on E85 in the United States and automakers such as Ford and General Motors have indicated plans to produce several million more flexible fuel vehicles per year. The USDOE reports that there were approximately 2,000 retail gasoline stations supplying E85 as of March 18, 2011. While the number of retail E85 suppliers has increased each year, this remains a relatively small percentage of the total number of U.S. retail gasoline stations, which is approximately 170,000. In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it. As public awareness of ethanol and E85 increases along with E85’s increased availability, management anticipates some growth in demand for ethanol associated with increased E85 consumption.

As of October 13, 2010, the EPA released the decision to allow the use of E85 in 2007 and later vehicles contingent on final approval (later) of a “Misfueling Mitigation Program” and certain other conditions. The EPA also indicated that it would soon complete its technical review of vehicles from 2001-2006, but that it would deny approval on older vehicles, and also on vehicles other than cars and light-duty trucks.

E15

E15 is a blend of gasoline and up to 15% ethanol. As of November 7, 2011, E15 was not registered with the EPA and not legal for distribution or sale as transportation fuel. However, effective July 1, 2011, the EPA approved final rules permitting a partial waiver and allowing E15 to be used in all 2001 and newer passenger vehicles. Previously, on October 13, 2010, the EPA granted a partial waiver which allowed fuel and fuel additive manufacturers to introduce E15 into commerce for use in 2007 and newer light-duty motor vehicles, subject to certain conditions. On January 21, 2011, the EPA partially approved a waiver to allow the introduction into commerce of E15 for use in 2001 and newer light-duty motor vehicles.

Effective July 1, 2011, Iowa retailers are eligible for a three cent per gallon tax credit for every gallon of E15 sold. The EPA has stated it has “insufficient” data to conclude that damage to vehicles will occur through use of E15. Any reversal of this EPA waiver is likely to nullify the tax credit for Iowa retailers and adversely affect the demand for E15.

Cellulosic Ethanol

Discussion of cellulose-based ethanol has recently increased. 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 and rice straw, among other common plants. Cellulosic ethanol is ethanol produced from cellulose, and currently, production of cellulosic ethanol is in its infancy. It is technology that is as yet unproven on a commercial scale. However, 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. Provisions of the RFS are intended to accelerate production of cellulosic ethanol. This could decrease demand for our product or result in competitive disadvantages for our ethanol production process.

The 2007 Act provided numerous funding opportunities in support of cellulosic ethanol. In addition, the amended RFS mandates an increasing level of production of biofuels which are not derived from corn. These policies suggest an increasing policy preference away from corn ethanol and toward cellulosic ethanol. The profitability of ethanol production depends heavily on federal incentives so the loss or reduction of incentives from the federal government in favor of corn-based ethanol production may reduce our profitability.

Local Production

Because we are located on the border of Iowa and Nebraska, and because ethanol producers generally compete primarily with local and regional producers, the ethanol producers located in Iowa and Nebraska presently constitute our primary competition. According to the Iowa Renewable Fuels Association, in 2011, Iowa had 40 ethanol refineries in production, producing 3.67 billion gallons of ethanol. According to the Nebraska Ethanol Board, there were currently 24 existing ethanol plants in Nebraska as of October, 2011 with a combined ethanol production capacity of approximately two billion gallons of ethanol a year. Additionally, certain plants located in Nebraska are eligible for state incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years. Those producers qualifying for this incentive have a competitive advantage over us.

Distillers Grains

In North America, over 80% of DDGS are used in ruminant animal diets, and are also fed to poultry and swine. Every bushel of corn used in the dry grind ethanol process yields approximately 17 pounds of DDGS,

which is an excellent source of energy and protein for livestock and poultry. Introducing DDGS into a feed ration for these animals can reduce the total feed cost from 3 to 10%. Management expects that DDGS prices will continue to increase slightly in the foreseeable future as the supply increases (the result of increased ethanol production), with the poor state of the economy and higher corn prices. Management believes DDGSs will trade with a 75% to 80% value to corn during the fiscal year ending September 30, 2012.

Regulatory Environment

Governmental Approvals

Ethanol production involves the emission of various airborne pollutants, including particulate matters, carbon monoxide, oxides of nitrogen, volatile organic compounds and sulfur dioxide. Ethanol production also requires the use of significant volumes of water, a portion of which is treated and discharged into the environment. We are required to maintain various environmental and operating permits, as discussed below. Even though we have successfully acquired the permits necessary for our operations, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources on complying with such regulations. In addition, although we do not presently intend to do so, if we sought to expand the Facility’s capacity in the future, we would likely be required to acquire additional regulatory permits and could also be required to install additional pollution control equipment. We are in the process of applying for a minor permit which will be less restrictive on our operations when switching from externally sourced steam to natural gas boilers, as required.

Our failure to obtain and maintain the permits discussed below or other similar permits which may be required in the future could force us to make material changes to our Facility or to shut down altogether. The following are summaries of the various governmental approvals we have obtained to operate our Facility.

Environmental Regulations and Permits

We are subject to regulations on emissions from the Iowa Department of Natural Resources (“IDNR”) as authorized by the EPA. The EPA and IDNR environmental regulations are subject to change and often such changes may have an economic impact on our industry. Consequently, environmental compliance and permit adherence is an ongoing commitment that requires vigilance on the part of the Facility employees as well as financial support of the various programs and permit requirements. The ongoing expenses associated with maintaining and complying with permit requirements are included in our operations budget.

Air Pollution Construction and Operation Permits

The State of Iowa and IDNR recently determined that, based on calculated emissions, our Facility is considered a “minor source” of regulated air pollutants and is not currently required to obtain a permit under Title V of the Clean Air Act (a “Title V Permit”). The Facility may need to apply for a Title V permit in the future if EPA determines that biogenic greenhouse gas emissions are to be included in major source threshold calculations. We have been issued an operating permit that allows us to operate our Facility subject to federally enforceable emission and operating limits contained in the permit, requires annual emission testing to demonstrate compliance, and must be renewed every five years. Every year we must provide an account of the actual pollution generated by the Facility to the EPA and IDNR in order to maintain our status as a Conditionally Exempt Small Quantity Generator and our Air Permit for operating.

New Source Performance Standards

The Facility is subject to the EPA’s New Source Performance Standards (“NSPS”) for both its grain and distillation processes as well as the storage of volatile organic compounds used in the denaturing process. Duties imposed by the NSPS include initial notification, emission limits, compliance and monitoring requirements and recordkeeping requirements.

Hazardous Waste

Based on the small amount of hazardous waste generated, the Facility is classified as a “Conditionally Exempt Small Quantity Generator” of hazardous waste, the smallest category of a facility that generates hazardous waste. The facility manages the collection, transport and disposal of the hazardous waste generated. The source of the hazardous waste is the quality assurance lab.

Endangered Species

We have received direction from the United States Fish and Wildlife Service and IDNR to reduce any potential impact on certain endangered species, and accordingly restrict rail line maintenance and or service activities to certain times of the year.

Rail Line Matters

The Facility’s railroad line is a dedicated, controlled access line, which only serves the Facility. As a result, we believe the line should be considered an exempt “industry lead track” or “spur track” under applicable rail transportation regulations. The United State Surface Transportation Board, which regulates the construction of new railroad lines, has not required any environmental assessment of the site.

Waste Water Discharge Permit

We use water to cool our closed circuit systems in the Facility and we generate reverse osmosis reject water. In order to maintain high quality water for the cooling system, a proportional flow of the water is continuously discharged and replaced with make-up water. As a result, our Facility discharges non-contact cooling water from the cooling towers and also RO reject water. We received a National Pollutant Discharge Elimination System (NPDES) Permit from IDNR to discharge non-contact water into the Missouri River. Under the NPDES Permit, we are required to periodically test and report our discharge activity to the IDNR.

Storm Water Discharge Permit

We have obtained the required Storm Water Discharge Permit from the IDNR. This permit required preparation of a Storm Water Pollution Prevention Plan, which outlined various measures we implement to prevent storm water pollution during plant operations.

High Capacity Well Permit

The Facility does not use municipal water, gray sewage treatment water, or Missouri river water. We received a High Capacity Well Permit from Pottawattamie County, Iowa, authorizing us to drill three high capacity wells to meet our water needs. This permit allows us an upper limit of 2,000,000 gallons of water per day through these wells, though the Facility requires only 1,500,000 gallons of water daily. The three wells have been tested and commissioned and are operating at expected levels.

Top Screen Analysis

The Department of Homeland Security (“DHS”) requires any facility that possesses certain chemicals above a threshold to submit a Top Screen Analysis. We do possess chemicals subject to the Top Screen Analysis requirement and are required to complete the Top Screen Analysis on an on-going basis. The Top Screen Analysis requires us to provide information such as the chemicals we store on-site, where the chemicals are stored, and the risks associated with such chemicals. DHS requires us to complete the Top Screen Analysis within 60 days of receiving any listed chemicals.

On-Going Activities and Reporting

We are also required to submit Form R, a Toxic Release Inventory report, to the EPA. Form R is required for facilities processing or using certain listed chemicals above a regulated quantity. Our annual form R will include documentation of our release of those certain chemicals into the environment within the previous year. Every five years we will be required to submit a Form U Report under the Toxic Substances Control Act (“TSCA”) to the EPA. In the Form U, we are required to report on manufacturing thresholds that were exceeded for any of the chemicals listed in the TSCA during the reporting period. Under the Emergency Planning and Right to Know Act, we are required to report our receipt of certain regulated chemicals to community and state officials within 60 days. This act requires local emergency planning communities to prepare a comprehensive emergency response plan. The local emergency planning agencies have been notified and are collaborating with us to complete a comprehensive ERS (Emergency Response System), a network of contacts in the event of an emergency, to provide an orderly and systematic response to the given situation.

Nuisance

Ethanol production has been known to produce an odor to which surrounding residents could object. Ethanol production may increase dust in the area due to operations and the transportation of grain, ethanol, and distillers grains to or from the Facility. Such activities may subject us to nuisance, trespass, or similar claims by employees or property owners or residents in the vicinity of the Facility. To help minimize the risk of nuisance claims based on odors related to the production of ethanol and its co-products, and as required by the EPS PSD BACT determination discussed previously, we have installed reverse thermal oxidizers and flare technology in the Facility. We are not currently involved in any litigation involving nuisance claims.

Operational Safety Regulations

We are also subject to federal and state laws regarding operational safety. Safety is a top priority for the Facility. To further promote the “safety priority,” we are a member of the ERI. The ERI group is a program of Ethanol Risk and Insurance Solutions, which offers a service of conducting risk assessments and facility safety audits aimed at improving the overall safety and risk of the facility safety group and provides quarterly inspections of the Facility and information on various Occupational Safety and Health Administration programs. We also focus daily attention to safety by conducting job hazards analysis and developing standard operating procedures. We employ a full time safety, health and environmental manager to ensure compliance with various programs and to facilitate training for our employees and contract personnel. Nonetheless, the risks of compliance costs and liabilities are inherent in any large-scale manufacturing process.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge on our website at www.sireethanol.com as soon as reasonably practicable after we file or furnish such information electronically with the SEC. The information found on our website is not part of this or any other report we file with or furnish to the SEC.

The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Item 1A. Risk Factors.

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 Associated With Our Capital Structure

Our Units have no public trading market and are subject to significant transfer restrictions which could make it difficult to sell Units and could reduce the value of the Units.

We do not expect an active trading market for our limited liability company interests, or “Units,” to develop. To maintain our partnership tax status, our Units may not be publicly traded. Within applicable tax regulations, we utilize a qualified matching service (“QMS”) to provide a limited market to our Members, but we will not apply for listing of the Units on any stock exchange. Finally, applicable securities laws may restrict the transfer of our Units. As a result, while a limited market for our Units may develop through the QMS, Members may not sell Units readily, and use of the QMS is subject to a variety of conditions and limitations. The transfer of our Units is also restricted by our Third Amended and Restated Operating Agreement dated July 17, 2009 (the “Operating Agreement”) unless the Board of Directors (the “Board” or “Board of Directors”) approves such a transfer. Furthermore, the Board will not approve transfer requests which would cause the Company to be characterized as a publicly traded partnership under the regulations adopted under the Internal Revenue Code of 1986, as amended (the “Code”). The value of our Units will likely be lower because they are illiquid. Members are required to bear the economic risks associated with an investment in us for an indefinite period of time.

Members may not receive cash distributions which could result in an investor receiving little or no return on his or her investment.

Distributions are payable at the sole discretion of our Board, subject to the provisions of the Iowa Limited Liability Company Act (the “Act”), our Operating Agreement and our loan agreements. Cash distributions are not assured, and we may never be in a financial position to make distributions. Our Board may elect to retain future profits to provide operational financing for the Facility, debt retirement and possible plant expansion. In addition, our loan agreements restrict our ability to make distributions. This means that Members may receive little or no return on their investment and may be unable to liquidate their investment due to transfer restrictions and lack of a public trading market. This could result in the loss of a Member’s entire investment.

Our Units are subordinate to our debts and other liabilities, resulting in a greater risk of loss for investors.

The Units are unsecured equity interests and are subordinate in right of payment to all our current and future debt as discussed elsewhere in this report. In the event of our insolvency, liquidation dissolution or other winding up of our affairs, all of our debts, including winding-up expenses, must be paid in full before any payment is made to the holders of the Units. In the event of our bankruptcy, liquidation, or reorganization, all Units will be paid ratably with all of our other equity holders as provided under the Operating Agreement, and there is no assurance that there would be any remaining funds after the payment of all our debts for any distribution to Members. In addition, it is possible that in order to refinance our debt, or for capital needs, we may have to issue additional equity interests having preferential treatment in the event we liquidated or reorganized.

Our failure to comply with our loan covenants could require us to abandon our business.

Our indebtedness, including the indebtedness under the Credit Agreement (the “Credit Agreement”) with AgStar Financial Services, PCA and a group of lenders (the “Lenders”), a revolving note with Bunge N.A. Holdings, Inc. (“Holdings”), and convertible debt, increases the risk that we will not be able to operate profitably because we will need to make principal and interest payments on the indebtedness. Debt financing also exposes our Members to the risk that their entire investment could be lost in the event of a default on the indebtedness and a

foreclosure and sale of the Facility and its assets for an amount that is less than the outstanding debt. Our ability to obtain additional debt financing, if required, will be subject to approval of our lending group, which may not be granted, the interest rates and the credit environment as well as general economic factors and other factors over which we have no control.

Our debt service requirements and restrictive loan covenants limit our ability to borrow more money, make cash distributions to our Members and engage in other activities.

Under the terms of our indebtedness (the “Current Loans”) we have made certain customary representations and we are subject to customary affirmative and negative covenants, including restrictions on our ability to incur additional debt that is not subordinated, create additional liens, transfer or dispose of assets, make distributions, make capital expenditures, consolidate, dissolve or merge, and customary events of default (including payment defaults, covenant defaults, cross defaults, construction related defaults and bankruptcy defaults). The Current Loans also contain financial covenants including a maximum revolving credit availability based on the borrowing base, minimum working capital amount, minimum tangible net worth, a minimum fixed charge coverage ratio, and a minimum tangible owner’s equity. Our obligations to repay principal and interest on the Current Loans make us vulnerable to economic or market downturns. If we are unable to service our debt, we may be forced to sell assets, restructure our indebtedness or seek additional equity capital, which would dilute our Members’ interests. If we default on any covenant, our current Lenders, Bunge, or Holdings (or any subsequent lender) could make the entire debt, once incurred, immediately due and payable. If this occurs, we might not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be on terms that are acceptable to us. These events could cause us to cease operations.

Risks Associated With Operations

We are dependent on MidAm for our steam supply and any failure by it may result in a decrease in our profits or our inability to operate, which may decrease the value of Units or Members’ investment return.

Under the Steam Contract, MidAm provides us with steam to operate our Facility until January 1, 2019. We expect to face periodic interruptions in our steam supply under the Steam Contract. For this reason, we installed boilers at the Facility to provide a backup natural gas energy source. We also have entered into a natural gas supply agreement with Constellation Energy for our long term natural gas needs, but this does not assure availability at all times. In addition, our current environmental permits limit the annual amount of natural gas that we may use in operating our gas-fired boiler.

As with natural gas and other energy sources, our steam supply can be subject to immediate interruption by weather, strikes, transportation, and production problems that can cause supply interruptions or shortages. While we anticipate utilizing natural gas as a temporary heat source under MidAm’s plant outages, an extended interruption in the supply of both steam and natural gas backup could cause us to halt or discontinue our production of ethanol, which would damage our ability to generate revenues. A decrease in our revenues may lead to a decrease in the value of Units or Members’ investment return.

We may not be able to protect ourselves from an increase in the price of steam which may result in a decrease in profits, causing a decrease in the value of our Units and Members’ investment return.

We are significantly dependent on the price of steam. The Steam Contract sets the price of steam until January 1, 2012 and provides for price increases annually thereafter. The price increases are based upon market forces over which we have no control. The Steam Contract will protect us from extreme price changes for the term of the agreement, but upon the expiration of the Steam Contract, there is no assurance that we will be able to enter into a similar agreement. Although coal prices and supplies have historically been more stable than many other forms of energy, this may not be taken into consideration when we are negotiating a new steam contract. If higher steam prices are sustained for some time, such pricing may reduce our profitability due to higher operating costs. This may cause a decrease in the value of our Units and Members’ investment returns.

Any site near a major waterway system presents potential for flooding risk.

While our site is located in an area designated as above the 100-year flood plain, it does exist within an area at risk of a 500-year flood. Even though our site is protected by levee systems, its existence next to a major river and major creeks present a risk that flooding could occur at some point in the future. During the last half of Fiscal 2011, the Missouri River experienced significant flooding, as a result of unprecedented amounts of rain and snow in the Missouri River basin. This produced a sustained flood lasting many weeks at a 500-year flood level (a level which has a 0.2 percent chance of occurring). While there were levee failures elsewhere, the levees held around our facility. We did experience minimal rail disruption due to flooding in the surrounding areas to the north and south of the Facility, but our operations were not significantly impacted.

We have procured flood insurance as a means of risk mitigation; however, there is a chance that such insurance will not cover certain costs in excess of our insurance associated with flood damage or loss of income during a flood period. Our current insurance may not be adequate to cover the losses that could be incurred in a flood of a 500-year magnitude. Accordingly, floods could have a material adverse impact upon Unit value.

We may experience delays or disruption in the operation of our rail line and loop track, which may lead to decreased revenues.

We have entered into the Track Agreement to service our track and railroad cars, which we will be highly dependent on. There may be times when we have to slow production at our ethanol plant due to our inability to ship all of the ethanol and distillers grains we produce. If we cannot operate our plant at full capacity, we may experience decreased revenues which may affect the profitability of the Facility.

Our operating costs could increase, thereby reducing our profits or creating losses, which would decrease the value of Units or Members’ investment return.

We could experience cost increases associated with the operation of the Facility caused by a variety of factors, many of which are beyond our control. Corn prices are volatile and labor costs could increase over time, particularly if there is a shortage of persons with the skills necessary to operate the Facility. The adequacy and cost of electricity, steam and natural gas utilities could also affect our operating costs. Changes in price, operation and availability of truck and rail transportation may affect our profitability with respect to the transportation of ethanol and distillers grains to our customers. In addition, the operation of the Facility is subject to ongoing compliance with all applicable governmental regulations, such as those governing pollution control, ethanol production, grain purchasing and other matters. If any of these regulations were to change, it could cost us significantly more to comply with them. We will be subject to all of these regulations whether or not the operation of the Facility is profitable.

If we cannot retain competent personnel, we may not be able to operate profitably, which could decrease the value of Units or Members’ investment return.

Though we believe we have employed capable management to date, we provide no assurance that we can manage the Facility effectively or properly staff our operations going forward.

Our lack of business diversification could result in the devaluation of our Units if our revenues from our primary products decrease.

Our business consists solely of ethanol, distillers grains and corn oil production and sales. We have no other lines of business or other sources of revenue. Our lack of business diversification could cause Members to lose all or some of their investment if we are unable to generate a profit by the production and sales of ethanol, distillers grains and corn oil since we do not expect to have any other lines of business or alternative revenue sources.

We have a history of losses and may not ever operate profitably.

From our inception on March 28, 2005 through September 30, 2011, we incurred an accumulated net loss of approximately $27,750,394. There is no assurance that we will be able to operate profitably.

An investment in our Units may decline in value due to decisions made by our Board and Members’ only recourse is to replace our Directors, which could take several years.

Our Board may make poor decisions regarding actions of the Company, which may cause a decrease in the value of Units. Our Operating Agreement provides that each member of the Board serves a four year term, and in all cases until a successor is elected and qualified. Holders of Series A Units (the “Series A Members”) have the right to elect the balance of the directors not elected by the holders of Series B, Series C Members, (or Series U Members, if we issue such Units) (presently the Series A Members may elect four Directors); however, the terms of the directorships elected by the Series A Members are staggered such that only one Series A Director may be elected each year. Staggering the terms of the Series A Directors, in addition to the rights of Bunge (the “Series B Member”) and ICM (the “Series C Member”) to elect certain directorships, including Bunge or Holdings’ rights to elect directorships in the event either is issued additional Units in connection with our debt, means that Series A Members could only change the control of the Company through electing all four Series A Directors, which would take four years. If the Facility suffers due to lack of financing or the Board makes poor decisions, the Series A Members’ only recourse is to replace the Series A directors through elections at four successive annual meetings or an amendment to our Operating Agreement, which may be difficult to accomplish.

Our Operating Agreement contains restrictions on Members’ rights to participate in corporate governance of our affairs, which limits their ability to influence management decisions.

Our Operating Agreement provides that a Member or Members owning at least 30 percent of the outstanding Units may call a special meeting of the Members. This may make it difficult for Members to propose changes to our Operating Agreement without support from our Board of Directors.

Our directors have other business and management responsibilities that may cause conflicts of interest in their services to the Company.

Since we are managed both by our officers and to some extent by the Board, the devotion of the directors’ time to the project is critical. However, the directors have other management responsibilities and business interests apart from our project. Most particularly, our directors who were nominated by Bunge and ICM have duties and responsibilities to those companies which may conflict with our interests. As a result, our directors may experience conflicts of interest in allocating their time and services between us and their other business responsibilities. No formal procedures have been established to address or resolve these conflicts of interest.

We may have conflicting financial interests with Bunge and ICM that could cause them to put their financial interests ahead of ours.

ICM and Bunge advise our directors and have been, and are expected to be, involved in substantially all material aspects of our financing and operations. We have entered into a number of material commercial arrangements with Bunge, as described elsewhere in this report. Consequently, the terms and conditions of our agreements with ICM and Bunge have not been negotiated at arm’s length. Therefore, these arrangements may not be as favorable to us as could have been if obtained from unaffiliated third parties. Most of the cost of our project has been paid to ICM for the design and construction of the Facility. In addition, because of the extensive roles that ICM and Bunge had, it may be difficult or impossible for us to enforce claims that we may have against ICM or Bunge. Such conflicts of interest may reduce our profitability and the value of the Units and could result in reduced distributions to investors.

ICM, Bunge and Holdings and their respective affiliates may also have conflicts of interest because ICM, Bunge and Holdings and their respective employees or agents are involved as owners, creditors and in other

capacities with other ethanol plants in the United States. We cannot require ICM, Bunge or Holdings to devote their full time or attention to our activities. As a result, ICM, Bunge and/or Holdings may have, or come to have, a conflict of interest in allocating personnel, materials and other resources to our Facility.

From time to time, our directors may serve in director or leadership roles with trade associations which could raise a conflict of interest.

A number of our directors have or continue to serve as directors of local and state agricultural trade organizations. These organizations may adopt policies, or engage in political lobbying activities that are in opposition to, or that conflict with the Company’s business needs. This may require such a director to abstain from votes or discussion on certain Company-related business matters.

Risks Associated With the Ethanol Industry

We compete with larger, better financed entities, which could negatively impact our ability to operate profitably.

There is significant competition among ethanol producers with numerous producers and privately-owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. Our business faces a competitive challenge from larger plants, from plants that can produce a wider range of products than we can, and from other plants similar to ours. Large ethanol producers such as Abengoa Bioenergy Corp., Archer Daniels Midland, Cargill, Inc., Green Plains Renewable Energy, Inc., Valero and POET, among others, are capable of producing a significantly greater amount of ethanol than we produce. Furthermore, ethanol from certain Central American or Caribbean countries is eligible for tariff reduction or elimination upon importation to the United States. Ethanol imported from these Caribbean Basin countries may be a less expensive alternative to domestically-produced ethanol.

This competition also means that the supply of domestically-produced ethanol is at an all-time high. According to the Renewable Fuel Association as of September 26, 2011, there were 14.75 billion gallons of nameplate capacity installed in the U.S. of which 14.22 billion gallons of annual production capacity was in operations. An additional .27 billion gallons were under construction or expansion. Iowa alone is estimated to produce approximately 3.67 billion gallons of ethanol in 2011. Excess capacity in the ethanol industry will have an adverse impact on our operations, cash flows and general financial conditions. If the demand for ethanol does not grow at the same pace as increases in supply, the price of ethanol will likely decline. If excess capacity in the ethanol industry continues, the market price of ethanol may continue to decline to levels that are inadequate to generate sufficient cash flow to cover our costs. This could negatively impact our future profitability and decrease the value of our Units and Members’ investment return.

Changes in the supply, demand, production and price of corn could make it more expensive to produce ethanol, which could decrease our profits.

Our ethanol production requires substantial amounts of corn. A significant reduction in the quantity of corn harvested due to adverse weather conditions, farmer planting decisions, domestic and foreign government farm programs and policies, global demand and supply or other factors could result in increased corn costs which would increase our cost to produce ethanol. Events that tend to negatively impact the supply of corn are likely to increase prices and affect our operating results. The recent increase in corn prices over the past three months may result in lower profit margins in the long term for the production of ethanol, as market conditions generally do not allow us to pass along increased corn costs to our customers. If the demand for corn continues to drive corn prices significantly higher we may not be able to acquire the corn needed to continue operations.

The price of corn has fluctuated significantly in the past and may fluctuate significantly in the future. We cannot provide assurances that we will be able to offset any increase in the price of corn by increasing the price of our products.

Any reduction in the spread between ethanol and corn prices, whether as a result of further increase in corn price or an additional decrease in ethanol prices, may adversely affect our results of operations and financial conditions, leading to a decrease in the value of Units and Members’ investment return.

We have executed an output contract for the purchase of all of the ethanol we produce, which may result in lower revenues because of decreased marketing flexibility and inability to capitalize on temporary or regional price disparities, and could reduce the value of Units or Members’ investment return.

Bunge is the exclusive purchaser of our ethanol and markets our ethanol in national, regional and local markets. We do not plan to build our own sales force or sales organization to support the sale of ethanol. As a result, we are dependent on Bunge to sell our principal product. When there are temporary or regional disparities in ethanol market prices, it could be more financially advantageous to have the flexibility to sell ethanol ourselves through our own sales force. We have decided not to pursue this route. Our strategy could result in lower revenues and reduce the value of Units if Bunge does not perform as we plan.

Low ethanol prices and low gasoline prices could reduce our profitability.

Prices for ethanol products can vary significantly over time and decreases in price levels could adversely affect our profitability and viability. The price for ethanol has some relation to the price for oil and gasoline. The price of ethanol tends to increase as the price of gasoline increases, and the price of ethanol tends to decrease as the price of gasoline decreases, although this may not always be the case. Any lowering of gasoline prices will likely also lead to lower prices for ethanol and adversely affect our operating results. Further increased production of ethanol may lead to lower prices. Any downward change in the price of ethanol may decrease our prospects for profitability and thus the value of our Units and Members’ investment return.

There is scientific disagreement about the wisdom of policies encouraging ethanol production, which could result in changes in governmental policies concerning ethanol and reduce our profitability.

Some studies have challenged whether ethanol is an appropriate source of fuel and fuel additives, because of concerns about energy efficiency, potential health effects, cost and impact on air quality. Federal energy policy, as set forth in the 2005 Act and the 2007 Act, supports ethanol production. If a scientific consensus develops that ethanol production does not enhance our overall energy policy, our ability to produce and market ethanol could be materially and adversely affected. In the spring of 2009, the EPA issued a proposed rule that required ethanol and biodiesel producers meet higher greenhouse gas emission standards than those for petroleum-based fuels because of the potential for increased green house gas emissions from land clearing for increased corn and soybean plantings in the U.S and other countries. If this proposed rule were implemented today, it could impose significant cost on our operations.

Hedging transactions, which are primarily intended to stabilize our corn costs, may be ineffective and involve risks and costs that could reduce our profitability and have an adverse impact on our liquidity.

We are exposed to market risk from changes in commodity prices. Exposure to commodity price risk results principally from our dependence on corn in the ethanol production process. In an attempt to minimize the effects of the volatility of corn costs on our operating profits, we enter into forward corn, ethanol, and distillers grain contracts and engage in other hedging transactions involving over-the-counter and exchange-traded futures and option contracts for corn; provided, we have sufficient working capital to support such hedging transactions. Hedging is an attempt to protect the price at which we buy corn and the price at which we will sell our products in the future and to reduce profitability and operational risks caused by price fluctuation. The effectiveness of our hedging strategies, and the associated financial impact, depends 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 our futures contracts. Our hedging activities may not successfully reduce the risk caused by price fluctuations which may leave us vulnerable to high corn prices. We have experienced hedging losses in the past and we may experience hedging losses again in the future. We may vary the amount of hedging or other price mitigation strategies we undertake, or we may choose

not to engage in hedging transactions in the future and our operations and financial conditions may be adversely affected during periods in which corn prices increase.

Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of over-the-counter or exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us.

Our attempts to reduce market risk associated with fluctuations in commodity prices through the use of over-the-counter or exchange-traded futures results in additional costs, such as brokers’ commissions, and may require cash deposits with brokers or margin calls. Utilizing cash for these costs and to cover margin calls has an impact on the cash we have available for our operations which could result in liquidity problems during times when corn prices fall significantly. Depending on our open derivative positions, we may require additional liquidity with little advance notice to meet margin calls. We have had to in the past, and in the future will likely be required to, cover margin calls. While we continuously monitor our exposure to margin calls, we cannot guarantee that we will be able to maintain adequate liquidity to cover margin calls in the future.

Ethanol production is energy intensive and interruptions in our supply of energy, or volatility in energy prices, could have a material adverse impact on our business.

Ethanol production requires a constant and consistent supply of energy. If our production is halted for any extended period of time, it will have a material adverse effect on our business. If we were to suffer interruptions in our energy supply, our business would be harmed. We have entered into the Steam Contract for our primary energy source. We also are able to operate at full capacity using natural gas-fired boilers, which mitigates the risk of disruption in steam supply. However, the amount of natural gas we are permitted to use for this purpose is currently limited and the price of natural gas may be significantly higher than our steam price. In addition, natural gas and electricity prices have historically fluctuated significantly. Increases in the price of steam, natural gas or electricity would harm our business by increasing our energy costs. The prices which we will be required to pay for these energy sources will have a direct impact on our costs of producing ethanol and our financial results.

Our ability to successfully operate depends on the availability of water.

To produce ethanol, we need a significant supply of water, and water supply and quality are important requirements to operate an ethanol plant. Our water requirements are supplied by our wells, but there are no assurances that we will continue to have a sufficient supply of water to sustain the Facility in the future, or that we can obtain the necessary permits to obtain water directly from the Missouri River as an alternative to our wells. As a result, our ability to make a profit may decline.

Changes and advances in ethanol production technology could require us to incur costs to update our Facility or could otherwise hinder our ability to complete 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 us. If we are unable to adopt or incorporate technological advances, our ethanol production methods and processes could be less efficient than our competitors, which could cause our plant to become uncompetitive or completely obsolete. If our competitors develop, obtain or license technology that is superior to ours or that makes our technology obsolete, we may be required to incur significant costs to enhance or acquire new technology so that our ethanol production remains competitive. Alternatively, we may be required to seek third-party licenses, which could also result in significant expenditures. We cannot guarantee or assure that third-party licenses will be available or, once obtained, will continue to be available on commercially reasonable terms, if at all. These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income, all of which could reduce the value of Members’ investment.

Competition from the advancement of alternative fuels may decrease the demand for ethanol and negatively impact our profitability, which could reduce the value of Members’ investment.

Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological option to address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets in order to lower fuel costs, decrease dependence on crude oil and reduce harmful emissions. If the fuel cell and hydrogen industries continue to expand and gain broad acceptance, and hydrogen becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would negatively impact our profitability, causing a reduction in the value of Members’ investment.

Corn-based ethanol may compete with cellulose-based ethanol in the future, which could make it more difficult for us to produce ethanol on a cost-effective basis and could reduce the value of Members’ investment.

Most ethanol produced in the U.S. is currently produced from corn and other raw grains, such as milo or sorghum - especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, 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. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. It may not be practical or cost-effective to convert our Facility into a plant which will use cellulose-based biomass to produce ethanol. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue will be negatively impacted and Members’ investment could lose value.

Depending on commodity prices, foreign producers may produce ethanol at a lower cost than we can, which may result in lower ethanol prices which would adversely affect our financial results.

There is a risk of foreign competition in the ethanol industry. Brazil is currently the second largest ethanol producer in the world. Brazil’s ethanol production is sugar-cane based, as opposed to corn based, and has historically been less expensive to produce. Other foreign producers may be able to produce ethanol at lower input costs, including costs of feedstock, facilities and personnel, than we can.

At present, there is a $0.54 per gallon tariff on foreign ethanol. However, this tariff might not be sufficient to deter overseas producers from importing ethanol into the domestic market, resulting in depressed ethanol prices. It is also important to note that the tariff on foreign ethanol is the subject of ongoing controversy and disagreement amongst lawmakers. Many lawmakers attribute increases in food prices to growth in the ethanol industry. They see foreign competition in ethanol production as a means of reducing food prices. Additionally, the tariff on ethanol is controversial internationally because critics contend that it diverts corn from export and impedes Latin American agricultural development.

Ethanol produced or processed in numerous countries in Central America and the Caribbean region is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative. Large multinational companies have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would 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. As a result, our business faces a threat from imported ethanol either from Brazil, even with the import tariff, or from a Caribbean Basin source. While transportation and infrastructure constraints may temper the market impact throughout the United States, competition from imported ethanol may

affect our ability to sell our ethanol profitably, which may have a material adverse effect on our operations, cash flows and financial position.

If significant additional foreign ethanol production capacity is created, such facilities could create excess supplies of ethanol on world markets, which may result in lower prices of ethanol throughout the world, including the United States. Such foreign competition is a risk to our business. Further, if the tariff on foreign ethanol is ever lifted, overturned, reduced, repealed or expires, our ability to profitably compete with low-cost international producers could be impaired. Any penetration of ethanol imports into the domestic market may have a material adverse effect on our operations, cash flows and financial position.

Risks Associated With Government Regulation and Subsidization

Federal regulations concerning tax incentives could expire or change, which could reduce our revenues.

The federal government presently encourages ethanol production by taxing it at a lower rate which indirectly benefits us. Some states and cities provide additional incentives. The 2005 Act and the 2007 Act effectively mandated increases in the amount of annual ethanol consumption in the United States. The result is that the ethanol industry’s economic structure is highly dependent on governmental policies. Although current policies are favorable factors, any major change in federal policy, including a decrease in ethanol production incentives, would have significant adverse effects on our operations and might make it impossible for us to continue in business.

Federal regulations provide the VEETC expires on December 31, 2011.

The VEETC program allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax credit for each gallon of ethanol they blend. The federal Transportation Efficiency Act of the 21st Century, or TEA-21, extended the ethanol tax credit first passed in 1979 through 2007. The American Jobs Creation Act of 2004 extended the subsidy again through the end of calendar year 2011 by allowing distributors to take a $0.51 excise tax credit for each gallon of ethanol they blend. Under the Food, Conservation and Energy Act of 2008, the tax credit was reduced to $0.45 per gallon for 2009 and thereafter. We cannot give assurance that the tax incentives will be renewed prior to their expiration on December 31, 2011 or, if renewed, on what terms they will be renewed. Legislation has been introduced in Congress to extend the VEETC at a reduced level; however, the final outcome remains unclear. As of the date of this report on Form 10-K, the VEETC has not been renewed.

Nebraska state producer incentives are unavailable to us, which places us at a competitive disadvantage.

Neighboring states such as Nebraska have historically provided incentives to ethanol producers, and may do so in the future. Presently, we do not qualify for any state-granted incentives. To the extent that neighboring states provide economic incentives to our competitors, our ability to effectively compete with such recipients will be reduced.

We are subject to extensive environmental regulation and operational safety regulations that impact our expenses and could reduce our profitability.

Ethanol production involves the emission of various airborne pollutants, including particulate matters, carbon monoxide, oxides of nitrogen, volatile organic compounds and sulfur dioxide. We are subject to regulations on emissions from the EPA and the IDNR. The EPA’s and IDNR’s environmental regulations are subject to change and often such changes are not favorable to industry. Consequently, even if we have the proper permits now, we may be required to invest or spend considerable resources to comply with future environmental regulations.

Our failure to comply or the need to respond to threatened actions involving environmental laws and regulations may adversely affect our business, operating results or financial condition. We must follow procedures for the proper handling, storage, and transportation of finished products and materials used in the production process and for the disposal of waste products. In addition, state or local requirements also restrict our production and distribution operations. We could incur significant costs to comply with applicable laws and regulations. Changes to

current environmental rules for the protection of the environment may require us to incur additional expenditures for equipment or processes.

We could be subject to environmental nuisance or related claims by employees, property owners or residents near the Facility arising from air or water discharges. Ethanol production has been known to produce an odor to which surrounding residents could object. We believe our plant design mitigates most odor objections. However, if odors become a problem, we may be subject to fines and could be forced to take costly curative measures. Environmental litigation or increased environmental compliance costs could significantly increase our operating costs.

We are subject to federal and state laws regarding operational safety. Risks of substantial compliance costs and liabilities are inherent in ethanol production. Costs and liabilities related to worker safety may be incurred. Possible future developments-including stricter safety laws for workers or others, regulations and enforcement policies and claims for personal or property damages resulting from our operation could result in substantial costs and liabilities that could reduce the amount of cash that we would otherwise have to distribute to Members or use to further enhance our business.

Carbon dioxide may be regulated by the EPA in the future as an air pollutant, requiring us to obtain additional permits and install additional environmental mitigation equipment, which may adversely affect our financial performance.

Our Facility emits carbon dioxide as a by-product of the ethanol production process. The United States Supreme Court has classified carbon dioxide as an air pollutant under the Clean Air Act in a case seeking to require the EPA to regulate carbon dioxide in vehicle emissions. 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. While there are currently no regulations applicable to us concerning carbon dioxide, if Iowa or the federal government, or any appropriate agency, decides 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 steps unknown to us at this time in order to comply with such law or regulation. Compliance with future regulation of carbon dioxide, if it occurs, could be costly and may prevent us from operating the Facility profitably, which may decrease the value of our Units and Members’ investment return.

Our site borders nesting areas used by endangered bird species, which could impact our ability to successfully maintain or renew operating permits. The presence of these species, or future shifts in its nesting areas, could adversely impact future operating performance.

The Piping Plover (Charadrius melodus) and Least Tern (Sterna antillarum) use the fly ash ponds of the existing MidAm power plant for their nesting grounds. The birds are listed on the state and federal threatened and endangered species lists. The IDNR determined that our rail operation, within specified but acceptable limits, does not interfere with the birds’ nesting patterns and behaviors. However, it was necessary for us to modify our construction schedules, plant site design and track maintenance schedule to accommodate the birds’ patterns. We cannot foresee or predict the birds’ future behaviors or status. As such, we cannot say with certainty that endangered species related issues will not arise in the future that could negatively effect the plant’s operations, or the valuation of Units.

We may encounter or discover unforeseen environmental contaminants at our site.

We completed a Phase One environmental survey to determine the presence of hazardous waste on the Facility site. While we believe the historical use of our site has primarily been bare farmland, a Phase Two environmental study (to test for the presence of any contaminants that may have permeated the ground water or leached into the soil as a consequence of any prior disposal or improper storage by prior occupants or neighboring businesses) was performed and updated in connection with the closing of our 2006 equity offering. In the future, should such contaminants or hazards be discovered, we may be unable to utilize the Facility site as we intend or we may incur costs for cleanup.

Risks Related to Tax Issues in a Limited Liability Company

MEMBERS SHOULD CONSULT THEIR OWN TAX ADVISOR CONCERNING THE IMPACT THAT THEIR OWNERSHIP IN US MAY HAVE ON THEIR FEDERAL INCOME TAX LIABILITY AND THE APPLICATION OF STATE AND LOCAL INCOME AND OTHER TAX LAWS TO OWNERSHIP OF UNITS.

IRS classification of us as a corporation rather than as a partnership would result in higher taxation and reduced profits, which could reduce the value of an investment in us.

We are an Iowa limited liability company that has elected to be taxed as a partnership for federal and state income tax purposes, with income, gain, loss, deduction and credit passed through to our Members. However, if for any reason the Internal Revenue Service (“IRS”) would successfully determine that we should be taxed as a corporation rather than as a partnership, we would be taxed on our net income at rates of up to 35 percent for federal income tax purposes, and all items of our income, gain, loss, deduction and credit would be reflected only on our tax returns and would not be passed through to our Members. If we were to be taxed as a corporation for any reason, distributions we make to our Members will be created as ordinary dividend income to the extent of our earnings and profits, and the payment of dividends would not be deductible by us, thus resulting in double taxation of our earnings and profits. If we pay taxes as a corporation, we will have less cash to distribute to our Members.

The IRS may classify an investment in us as passive activity income, resulting in a Member’s inability to deduct losses associated with an investment in us.

It is likely that the IRS will classify an interest in us as a passive activity. If a Member is either an individual or a closely held corporation, and if a Member’s interest is deemed to be “passive activity,” then such Member’s allocated share of any loss we incur will be deductible only against income or gains such Member has earned from other passive activities. Passive activity losses that are disallowed in any taxable year are suspended and may be carried forward and used as an offset against passive activity income in future years. These rules could restrict a Member’s ability to currently deduct any of our losses that are passed through.

Income allocations assigned to Units may result in taxable income in excess of cash distributions, which means a Member may have to pay income tax on our Units with personal funds.

Members will pay tax on their allocated shares of our taxable income. Members may receive allocations of taxable income that result in a tax liability that is in excess of any cash distributions we may make to the Members. Among other things, this result might occur due to accounting methodology, lending covenants imposed by our current loans that restrict our ability to pay cash distributions, or our decision to retain the cash generated by the business to fund our operating activities and obligations. Accordingly, Members may be required to pay some or all of the income tax on their allocated shares of our taxable income with personal funds.

An IRS audit could result in adjustments to our allocations of income, gain, loss and deduction causing additional tax liability to our Members.

The IRS may audit our income tax returns and may challenge positions taken for tax purposes and allocations of income, gain, loss and deduction to Members. If the IRS were successful in challenging our allocations in a manner that reduces loss or increases income allocable to Members, Members may have additional tax liabilities. In addition, such an audit could lead to separate audits of Members’ tax returns, especially if adjustments are required, which could result in adjustments on Members’ tax returns. Any of these events could result in additional tax liabilities, penalties and interest to Members, and the cost of filing amended tax returns.

Item 2. Properties.

We own the Facility site located near Council Bluffs, Iowa, which consists of three parcels totaling 200 acres. This property is encumbered under the mortgage agreement with Lenders. We lease a building on the Facility site to an unrelated third party, and lease 55.202 acres on the south end of the property to an unrelated third party for farming. In December 2008, we entered into a lease agreement with Bunge for the lease of property in Council Bluffs, Iowa. The property contains a storage bin used for storing grain for the Facility. The initial term of the lease was for one year and it was extended for additional one-year terms until it was terminated in May, 2011.

Item 3. Legal Proceedings.

There are no items to report.

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 (i) 8,805 Series A Units issued and outstanding held by 811 persons, (ii) 3,334 Series B Units issued and outstanding held by Bunge, and (iii) 1,000 Series C Units issued and outstanding held by ICM. We do not have any established trading market for its Units, nor is one contemplated. To date, we have made no distribution to our Members, and we cannot be certain when we will be able to make distributions. Further, our ability to make distributions will be restricted under the terms of the Credit Agreement.

Item 6. Selected Financial Data.

		Fiscal 2011		Fiscal 2010

		Amounts		Amounts
Balance Sheet Data
Cash and Cash Equivalents	$	11,006,590	$	3,432,544
Current Assets		44,908,323		38,319,934
Total assets		210,709,826		215,191,380
Current liabilities		39,985,294		27,192,264
Long-term debt		121,400,805		135,868,087
Total Liabilities		161,986,109		163,760,357
Members’ equity		48,723,717		51,431,023

Adjusted EBITDA is defined as net income (loss) plus interest expense net of interest income, plus income tax expense (benefit) and plus depreciation and amortization, or EBITDA, as adjusted for unrealized hedging losses (gains). Adjusted EBITDA is not required by or presented in accordance with generally accepted accounting principles in the United States of America, or generally accepted accounting principles (“GAAP”), and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP, or as an alternative to cash flow from operating activities or as a measure of our liquidity.

We present Adjusted EBITDA because we consider it to be an important supplemental measure of our operating performance. Adjusted EBITDA is a key measure of our operating performance and is considered by our management and Board of Directors as an important operating metric in their assessment of our performance.

We believe Adjusted EBITDA allows us to better compare our current operating results with corresponding historical periods and with the operational performance of other companies in our industry because it does not give effect to potential differences caused by variations in capital structures (affecting relative interest expense, including the impact of write-offs of deferred financing costs when companies refinance their indebtedness), the amortization of intangibles (affecting relative amortization expense), unrealized hedging losses (gains) and other items that are unrelated to underlying operating performance. We also present Adjusted EBITDA because we believe it is frequently used by securities analysts and investors as a measure of performance. There are a number of material limitations to the use of Adjusted EBITDA as an analytical tool, including the following:

Adjusted EBITDA does not reflect our interest expense or the cash requirements to pay our interest. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations.

Although depreciation and amortization are non-cash expenses in the period recorded, the assets being depreciated and amortized may have to be replaced in the future, and Adjusted EBITDA does not reflect the cash requirements for such replacement. Because we use capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits. Therefore, any measure that excludes depreciation and amortization expense may have material limitations.

We compensate for these limitations by relying primarily on our GAAP financial measures and by using Adjusted EBITDA only as supplemental information. We believe that consideration of Adjusted EBITDA, together with a careful review of our GAAP financial measures, is the most informed method of analyzing our operations. Because Adjusted EBITDA is not a measurement determined in accordance with GAAP and is susceptible to varying calculations, Adjusted EBITDA, as presented, may not be comparable to other similarly titled measures of other companies. The following table provides a reconciliation of Adjusted EBITDA to net income (loss):


		Fiscal 2011		Fiscal 2010

		Amounts		Amounts
Income Statement Data
Revenues	$		333,088,857	$	207,833,200
Cost of Goods Sold			321,598,421		203,072,102
Gross Margin			11,490,436		4,761,098
General and Administrative Expenses			4,357,402		4,540,205
Other Expense			9,840,340		9,172,255
Net Loss	$		(2,707,306)	$	(8,951,362)
(Loss) per unit:
Basic & diluted	$		(206.05)	$	(681.28)

	Fiscal 2011			Fiscal 2010

	Amounts			Amounts

Net income (loss) $		(2,707,306)	$	(8,951,362)
Interest Expense		9,883,871		9,302,287
Depreciation		13,536,138		19,157,086
EBITDA $		20,712,703	$	19,508,011

Unrealized hedging		5,585,064		(612,914)
losses

Adjusted EBITDA	$	26,297,767	$	18,895,097

Adjusted EBITDA per unit	$	2,001.50	$	1,438.09

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Overview, Status and Recent Developments

Results of Operations

The following table shows our results of operations, stated as a percentage of revenue for Fiscal 2011 and 2010.

		Fiscal 2011(1)					Fiscal 2010 (1)
		Amounts		% of Revenues	Gallons Average Price		Amounts		% of Revenues	Gallons Average Price
Income Statement Data
Revenues	$		333,088,857	100%	$	2.91	$	207,833,200	100%	$	1.87
Cost of Goods Sold
Material Costs			259,184,071	78%		2.26		140,044,538	68%		1.26
Variable Production Exp.			31,368,432	9%		.27		29,076,928	14%		.26
Fixed Production Exp.			31,045,918	9%		.27		33,950,636	16%		.31
Gross Margin			11,490,436	3%		0.11		4,761,098	2%		0.04
General and Administrative Expenses			4,357,402	1%		0.04		4,540,205	2%		0.04
Other Expense			9,840,340	3%		0.08		9,172,255	4%		0.08
Net Loss	$		(2,707,306)	(1%)	$	(0.01)	$	(8,951,362)	(4%)	$	(0.08)

(1) Includes ethanol and distillers grains converted to gallons.

Revenues

Our revenue from operations is derived from three primary sources: sales of ethanol, distillers grains, and corn oil. The following chart displays statistical information regarding our revenues. The increase in revenue from Fiscal 2010 to Fiscal 2011 was due to the average price per gallon of ethanol increasing by approximately $0.78 plus 3.74 million additional gallons being sold between the two years and an increase in the dried distillers grains average price per ton of approximately $70, with 3,706 additional tons being produced between the two years. The introduction of corn oil in Fiscal 2011 generated an $5.3 million of revenue, equal to about 2% of our total revenue.

	Fiscal 2011							Fiscal 2010
	Gallons/Tons Sold		% of Revenues		Gallons/Tons Average Price			Gallons/Tons Sold		% of Revenues		Gallons/Tons Average Price
Statistical Revenue Information
Denatured Ethanol		114,506,382		81%		$	2.36		110,764,875		84%		$	1.58
Dry Distiller’s Grains		305,929		17%		$	173		302,223		16%		$	103
Corn Oil		5,858		2%		$	894		0		0%		$	0

Cost of Goods Sold

Our cost of goods sold as a percentage of our revenues was 97% and 98% for Fiscal 2011 and 2010, respectively. Our two primary costs of producing ethanol and distillers grains are corn and energy, with steam as our primary energy source and to a lesser extent, natural gas. Cost of goods sold also includes net (gains) or losses from derivatives and hedging relating to corn. We ground 40,779,371 and 39,678,841 bushels of corn at an average price of $6.49 and $3.55 per bushel during Fiscal 2011 and 2010, respectively. Our average steam and natural gas energy cost was constant at $4.76 per MMBTU in the two periods.

Realized and unrealized gains related to our derivatives and hedging related to corn resulted in a decrease of approximately $6,325,414 in our cost of goods sold for Fiscal 2011, compared to a decrease of approximately $2,036,833 in our cost of goods sold for Fiscal 2010. We recognize the gains or losses that result from the changes in the value of our derivative instruments related to corn in cost of goods sold as the changes occur. As corn prices fluctuate, the value of our derivative instruments are impacted, which affects our financial performance. We anticipate continued volatility in our cost of goods sold due to the timing of the changes in value of the derivative instruments relative to the cost and use of the commodity being hedged.

Variable production expenses showed an increase when comparing Fiscal 2011 to Fiscal 2010 due to the quantity and price of chemicals increasing. Fixed production expenses showed a decrease when comparing Fiscal 2011 to Fiscal 2010 due to a reduction in depreciation expense. While depreciation expense decreased, marketing expenses and repairs and maintenance expense increased when comparing Fiscal 2011 to Fiscal 2010.

Effective January 1, 2011 we increased the estimated useful life on a significant portion of our processing equipment; management believes this change of estimate more closely approximates the actual life. This change in estimate is accounted for on a prospective basis. This change resulted in a decrease in depreciation expense, an increase to operating income, a decrease of net (loss) of approximately $5.4 million, and a decrease in (loss) per unit of $411 for Fiscal 2011 over Fiscal 2010.

General & Administrative Expense

Our general and administrative expenses as a percentage of revenues were 1% and 2% for Fiscal 2011 and 2010, respectively. Operating expenses include salaries and benefits of administrative employees, professional fees and other general administrative costs. Our general and administrative expenses for Fiscal 2011 were $4,357,402, as compared to $4,540,205 for Fiscal 2010. The decrease in general and administrative expenses from 2010 to 2011 is due to a reduction in professional fees. We expect our operating expenses to remain flat to slightly decreasing during the first two quarters of the year ending September 30, 2012 (“Fiscal 2012”).

Other (Expense)

Our other expenses for Fiscal 2011 and 2010 were approximately 3% and 4% of our revenues, respectively. Our other expenses for the years ended Fiscal 2011 and 2010 were $9,840,340 and $9,172,255, respectively. The majority of this increase in other expenses was a result of additional interest expense incurred in the first half of Fiscal 2011 due to additional borrowings in connection with hedging activities.

Net (Loss)

Our net losses from operations for Fiscal 2011 and 2010 were approximately 1% and 4% of our revenues, respectively. Our net loss for Fiscal 2011 was primarily the result of increased corn costs and interest expense. Our net loss for Fiscal 2010 was primarily the result of fixed costs and interest expenses.

Liquidity and Capital Resources

As of September 30, 2011, we had a balance of $96,753,936 under our Credit Agreement. We also agreed to pay, beginning at the end of the September 30, 2010 fiscal quarter, an amount equal to 65% of our Excess Cash

Flow (as defined in the Credit Agreement), up to a total of $4,000,000 per year, and $16,000,000 over the term of the Credit Agreement. Under our Credit Agreement, the Borrowing Base is defined as, “at any time, the lesser of: (i) fifteen million dollars ($15,000,000.00), or (ii) the sum of: (A) seventy-five percent (75%) of our eligible accounts receivable, plus (B) seventy-five percent (75%) of our eligible inventory. In addition to compliance with the Borrowing Base, we are subject to various covenants under the Credit Agreement. The excess cash flow payment was modified by the Second Amendment to the Amended and Restated Credit Agreement dated June 30, 2011, whereby we also agreed to pay, beginning at the end of the Fiscal 2011, an amount equal to 65% of our Excess Cash Flow (as defined in the Credit Agreement), up to a total of $6,000,000 per year, and $24,000,000 over the term of the Credit Agreement. We were in compliance with all financial covenants under our Credit Agreement as of September 30, 2011.

Under our $15 million revolving line of credit with the Lenders (the “Revolving LOC”), we have $3,500,000 outstanding as of September 30, 2011 and $10,273,245 as of September 30, 2010, with an additional $11,500,000 and $1,426,755 available at September 30, 2011 and 2010, respectively. A letter of credit issued in favor of our provider, MidAm, in the amount of $2,000,000 (this letter of credit was no longer required as of April 1, 2011). We are also relying on receipt of our accounts receivable to help fund operations.

We entered into a revolving note with Holdings dated August 26, 2009 (the “Holdings Revolving Note”), providing for the extension of a maximum of $10,000,000 in revolving credit. Holdings has a commitment, subject to certain conditions, to advance up to $3,750,000 at our request under the Holdings Revolving Note; amounts in excess of $3,750,000 may be advanced by Holdings in its discretion. Interest accrues at the rate of 7.5 percent over six-month LIBOR. While repayment of the Holdings Revolving Note is subordinated to the Credit Agreement, we may make payments on the Holdings Revolving Note so long as we are in compliance with our borrowing base covenant and there is not a payment default under the Credit Agreement. As of September 30, 2011 and September 30, 2010, the balance outstanding was $3,000,000 and $0, respectively, under the Holdings Revolving Note. Under the Holdings Revolving Note, we made certain standard representations and warranties.

As a result of our Credit Agreement, Revolving LOC, convertible debt and the Holdings Revolving Note, we have a significant amount of debt, and our existing debt financing agreements contain, and our future debt financing agreements may contain, restrictive covenants that limit distributions and impose restrictions on the operation of our business. The use of debt financing makes it more difficult for us to operate because we must make principal and interest payments on the indebtedness and abide by covenants contained in our debt financing agreements. The level of our debt has important implications on our liquidity and capital resources, including, among other things: (i) limiting our ability to obtain additional debt or equity financing; (ii) making us vulnerable to increases in prevailing interest rates; (iii) placing us at a competitive disadvantage because we may be substantially more leveraged than some of our competitors; (iv) subjecting all or substantially all of our assets to liens, which means that there may be no assets left for members in the event of a liquidation; and (v) 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.

While the prices of our primary input (corn) and our principal products (ethanol and DDGS) are expected to be volatile in the first quarter of Fiscal 2012, given the relative prices of these commodities and the operation of our risk management program in the quarter, we believe operating margins will be strong in the first quarter of Fiscal 2012. We expect that in the last three quarters of Fiscal 2012 our margins will be under pressure due to the anticipated loss of VEETC and continued volatility within both the ethanol and corn markets.

Primary Working Capital Needs

Cash provided by (used in) operations for Fiscal 2011 and 2010 was $25,307,440 and ($1,797,177), respectively. This change is a result of increased corn and ethanol prices. For Fiscal 2011 and 2010, net cash (used in) investing activities was ($3,159,305) and ($3,518,705), respectively, primarily for fixed asset additions. For the years ended September 30, 2011 and 2010, cash provided by (used in) financing activities was ($14,574,089) and $1,293,342, respectively. In 2011, the cash was used to pay down our debt; and in 2010, this cash was generated

through loan proceeds. During Fiscal 2011, pursuant to contractual terms, we made principal payments on our term debt in the amount of $12,112,790, which included an Excess Cash Flow Payment of $4,000,000.

During the first quarter of Fiscal 2012, we estimate that we will require approximately $78,000,000 for our primary input of corn and $4,000,000 for our energy sources of steam and natural gas. We currently have approximately $11,500,000 available under our Revolving LOCs to hedge commodity price fluctuations. In addition, we have up to $10,000,000 in revolving credit available to support our working capital needs. We cannot estimate the availability of funds for hedging in the future.

Trends and Uncertainties Impacting Ethanol Industry and Our Future Operations

Our operations are highly dependent on commodity prices, especially prices for corn, ethanol and distillers grains. As a result of price volatility for these commodities, our operating results may fluctuate substantially. The price and availability of corn are subject to significant fluctuations depending upon a number of factors that affect commodity prices in general, including crop conditions, weather, governmental programs and foreign purchases. We may experience increasing costs for corn and natural gas and decreasing prices for ethanol and distillers grains which could significantly impact our operating results. Because the market price of ethanol is not directly related to corn prices, ethanol producers are generally not able to compensate for increases in the cost of corn feedstock through adjustments in prices charged for ethanol. We continue to monitor corn and ethanol prices and their effect on our longer-term profitability.

The price of corn has been volatile the past two years. Since September, 2009, the Chicago Mercantile Exchange (“CME”) near-month corn price has increased $3.01 per bushel. As of October 11, 2011, the CME near-month corn price for October, 2011 was $6.45 per bushel. We believe the increase in corn prices was primarily due to short supply and the USDA corn acreage report that was released on October 12, 2011. Increasing corn prices will negatively affect our costs of production, however, we also believe that higher corn prices may, depending on the prices of alternative crops, encourage farmers to plant more acres of corn in the coming years and possibly divert land in the Conservation Reserve Program to corn production. We believe an increase in land devoted to corn production could reduce the price of corn to some extent in the future.

On October 12, 2011, the USDA decreased in its original forecast of the amount of corn to be used for ethanol production during the current marketing year (2011-12), to a total of 5.00 billion bushels. The forecast is 20 million bushels less than used last year. In the October, 2011 update, the USDA decreased the projection of U.S. corn exports for the current marketing year by .05 billion bushels. This projection is 293 million bushels less than the projection of last fall and 306 million less than the exports of 2009-10.

The USDA report for crop year 2011 (the period of September, 2011 through August, 2012) has projected the season-average farm price of corn at $6.20 to $7.20 per bushel. This compares with the 2009-10 season-average of $3.55 per bushel. We feel that there will continue to be volatility in the corn market.

In the past, ethanol prices have tended to track the wholesale price of gasoline. Ethanol prices can vary from state to state at any given time. For the past two years as of September, 2011 according to the Chicago Board of Trade (“CBOT”), the average U.S. ethanol price was $2.54 per gallon. For the same time period, the average U.S. wholesale gasoline price was $2.83 per gallon or approximately $0.29 per gallon above ethanol prices. During the fourth quarter of Fiscal 2011, the average U.S. ethanol price was $2.83 per gallon. For the same time period, U.S. wholesale gasoline prices averaged $2.97 per gallon, or approximately $0.14 per gallon above ethanol prices.

The RFS and Other Federal Mandates

The American Jobs Creation Act of 2004 created VEETC, which is currently set to expire on December 31, 2011. Referred to as the blender’s credit, VEETC provides companies with a tax credit to blend ethanol with gasoline. The Food, Conservation and Energy Act of 2008 (the “2008 Farm Bill”) amended the amount of tax credit provided under VEETC to 45 cents per gallon of pure ethanol and 38 cents per gallon for E85, a blended motor fuel containing 85% ethanol and 15% gasoline. The elimination or further reduction of VEETC or other federal tax

incentives to the ethanol industry would likely have a material adverse impact on our business by reducing demand and price for the ethanol we produce.

The 2008 Act included cellulosic ethanol supports applicable to corn-based ethanol and bolsters those contained in 2007 legislation. Theses supports have impacted the ethanol industry by enhancing both the production and use of ethanol. The 2008 Act modified the RFS. The EPA is responsible for revising and implementing regulations to ensure that transportation fuel sold in the United States contains a minimum volume of renewable fuel. On February 3, 2010, the EPA implemented a regulation that requires 12.95 billion gallons of renewable fuel be sold or dispensed in 2010, increasing to 36 billion gallons by 2022. This requirement does not apply just to corn-based ethanol, but includes all forms of fuel created from feedstocks that qualify as “renewable biomass”. The EPA regulation also expanded the RFS program beyond gasoline to generally cover all transportation fuel. We cannot assure that this program’s mandates will continue in the future. We believe that any reversal in federal policy could have a profound impact on the ethanol industry.

The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline. The RFS mandate level for 2011 of 12.6 billion gallons approximates current domestic production levels. The 2012 RFS mandate is for 15.2 billion gallons of renewable fuels. The EPA has issued proposed allocations of classes of renewable fuels, which are not yet final. Future demand will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline versus ethanol, taking into consideration the blender’s credit and the RFS. Any significant increase in production capacity beyond the RFS level might have an adverse impact on ethanol prices. Additionally, the RFS mandate with respect to ethanol derived from grain could be reduced or waived entirely. A reduction or waiver of the RFS mandate could adversely affect the prices of ethanol and our future performance.

Federal law mandates the use of oxygenated gasoline. If these mandates are repealed, the market for domestic ethanol would be diminished significantly. Additionally, flexible-fuel vehicles receive preferential treatment in meeting corporate average fuel economy, or CAFE, standards. However, high blend ethanol fuels such as E85 result in lower fuel efficiencies. Absent the CAFE preferences, it may be unlikely that auto manufacturers would build flexible-fuel vehicles. Any change in these CAFE preferences could reduce the growth of E85 markets and result in lower ethanol prices.

Risks Related to Government Support and Subsidy

As noted above, VEETC is set to expire on December 31, 2011. The ongoing debate in budget discussions in the U.S. Congress provides uncertainty as to whether or not VEETC will be extended, and there have been proposals to eliminate it. If this tax credit is not renewed before the end of 2011, it likely would have a negative impact on the price of ethanol and the demand for ethanol in the market due to reduced discretionary blending of ethanol. Discretionary blending occurs when gasoline blenders use ethanol to reduce the cost of blended gasoline. However, due to the RFS, demand for ethanol may continue to mirror the RFS requirement, even if the VEETC is not renewed past 2011. If the RFS is reduced or eliminated, the decrease in demand for ethanol related to the elimination of VEETC may be more substantial.

Credit and Counterparty Risks

Through our normal business activities, we are subject to significant credit and counterparty risks that arise through normal commercial sales and purchases, including forward commitments to buy and sell, and through various other over-the-counter (OTC) derivative instruments that we utilize to manage risks inherent in our business activities. We define credit and counterparty risk as a potential financial loss due to the failure of a counterparty to honor its obligations. The exposure is measured based upon several factors, including unpaid accounts receivable from counterparties and unrealized gains (losses) from OTC derivative instruments (including forward purchase and sale contracts). We actively monitor credit and counterparty risk through credit analysis (by our marketing agent). We record provisions for counterparty losses from time to time as a result of our credit and counterparty analysis.

Impact of Hedging Transactions on Liquidity

Our operations and cash flows are highly impacted by commodity prices, including prices for corn, ethanol, distillers grains and natural gas. We attempt to reduce the market risk associated with fluctuations in commodity prices through the use of derivative instruments, including forward corn contracts and over-the-counter exchange-traded futures and option contracts. Our liquidity position may be positively or negatively affected by changes in the underlying value of our derivative instruments. When the value of our open derivative positions decrease, we may be required to post margin deposits with our brokers to cover a portion of the decrease or we may require significant liquidity with little advanced notice to meet margin calls. Conversely, when the value of our open derivative positions increase, our brokers may be required to deliver margin deposits to us for a portion of the increase. We continuously monitor and manage our derivative instruments portfolio and our exposure to margin calls and while we believe we will continue to maintain adequate liquidity to cover such margin calls from operating results and borrowings, we cannot estimate the actual availability of funds from operations or borrowings for hedging transactions in the future.

The effects, positive or negative, on liquidity resulting from our hedging activities tend to be mitigated by offsetting changes in cash prices in our core business. For example, in a period of rising corn prices, gains resulting from long grain derivative positions would generally be offset by higher cash prices paid to farmers and other suppliers in spot markets. These offsetting changes do not always occur, however, in the same amounts or in the same period, with lag times of as much as twelve months.

Commodity Price Risks

The financial performance of both the Company and our industry are highly dependent on commodity prices, especially prices for corn, ethanol, distillers grains and natural gas. These commodities are subject to price fluctuations due to a number of unpredictable factors. The price of corn is subject to fluctuations due to unpredictable factors such as weather; corn planted and harvested acreage; changes in national and global supply and demand; and government programs and policies. Ethanol prices are sensitive to world crude-oil supply and demand; crude-oil refining capacity and utilization; government regulation; and consumer demand for alternative fuels. Distillers grains prices are sensitive to various demand factors such as numbers of livestock on feed, prices for feed alternatives, and supply factors, primarily production by ethanol plants and other sources. We use natural gas in the ethanol production process to the extent our steam source is not available. The price of natural gas is influenced by such weather factors as extreme heat or cold in the summer and winter, or other natural events like hurricanes in the spring, summer and fall. Other natural gas price factors include North American exploration and production, and the amount of natural gas in underground storage during both the injection and withdrawal seasons.

We enter into various derivative contracts with the primary objective of managing our exposure to adverse price movements in the commodities used for, and produced in, our business operations and, to the extent we have working capital available, we engage in hedging transactions which involve risks that could harm our business. We measure and review our net commodity positions on a daily basis. Our daily net agricultural commodity position consists of inventory, forward purchase and sale contracts, over-the-counter and exchange traded derivative instruments. The effectiveness of our hedging strategies is dependent upon the cost of commodities and our ability to sell sufficient products to use all of the commodities for which we have futures contracts. Although we actively manage our risk and adjust hedging strategies as appropriate, there is no assurance that our hedging activities will successfully reduce the risk caused by market volatility which may leave us vulnerable to high commodity prices. Alternatively, we may choose not to engage in hedging transactions in the future. As a result, our future results of operations and financial conditions may also be adversely affected during periods in which corn prices changes.

In addition, as described above, hedging transactions expose us to the risk of counterparty non-performance where the counterparty to the hedging contract defaults on its contract or, in the case of over-the-counter or exchange-traded contracts, where there is a change in the expected differential between the price of the commodity underlying the hedging agreement and the actual prices paid or received by us for the physical commodity bought or sold. We have, from time to time, experienced instances of counterparty non-performance.

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 the current period (commonly referred to as the “mark to market” method). The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged. As corn prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, our hedging strategies may cause immediate adverse effects, but are expected to produce long-term positive impact.

In the event we do not have sufficient working capital to enter into hedging strategies to manage our commodities price risk, we may be forced to purchase our corn and market our ethanol at spot prices and as a result, we could be further exposed to market volatility and risk.

We expect the annual impact on our results of operations due to a $1.00 per bushel fluctuation in market prices for corn to be approximately $40,100,000, or $0.36 per gallon, assuming our plant operates at 100% name plate capacity (production of 110,000,000 gallons of ethanol annually). This assumes no increase in the price of ethanol and assumes a relative increase in the price of distillers grains. We expect the annual impact to our results of operations due to a $0.50 decrease in ethanol prices will result in approximately a $55,000,000 decrease in revenue.

We have a significant amount of debt, and our existing debt financing agreements contain, and our future debt financing agreements may contain, restrictive covenants that limit distributions and impose restrictions on the operation of our business. The use of debt financing makes it more difficult for us to operate because we must make principal and interest payments on the indebtedness and abide by covenants contained in our debt financing agreements. The level of our debt has important implications on our operations, including, among other things: (i) limiting our ability to obtain additional debt or equity financing; (ii) making us vulnerable to increases in prevailing interest rates; (iii) placing us at a competitive disadvantage because we may be substantially more leveraged than some of our competitors; (iv) subjecting all or substantially all of our assets to liens, which means that there may be no assets left for members in the event of a liquidation; and (v) 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.

Competition

We believe that the competition in the ethanol market will continue to increase in the near term due to the refitting of plants, reopening of idled plants, and the competitive dynamics of the fuel industry. Consolidation and recapitalization continue to occur within the ethanol industry; and companies are now emerging with more liquidity and less debt. We believe the increased capacity, and current competitive dynamics of the fuels market, we believe, will help ethanol prices remain steady to slightly higher in the near term.

Summary of Critical Accounting Policies and Estimates

Note 2 to our financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. Accounting estimates are an integral part of the preparation of financial statements and are based upon management’s current judgment. We used our knowledge and experience about past events and certain future assumptions to make estimates and judgments involving matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We believe that of our significant accounting policies, the following are noteworthy because changes in these estimates or assumptions could materially affect our financial position and results of operations:

Revenue Recognition

We sell ethanol and related products pursuant to marketing agreements. Revenues are recognized when the marketing company or the customers have taken title to the product, prices are fixed or determinable and collectability is reasonably assured. Our products are generally shipped FOB loading point. Our ethanol sales are handled through our ethanol agreement with Bunge. Syrup, distillers grains and solubles, and modified wet distillers grains with solubles are sold through our agreement with Bunge, which sets the price based on the market price to third parties. Marketing fees and commissions due to the marketers are paid separately from the settlement for the sale of the ethanol products and co-products and are included as a component of cost of goods sold. Shipping and handling costs incurred by us for the sale of ethanol and co-products are included in cost of goods sold.

Incentive Compensation Plan

We established an equity incentive compensation plan (the “Plan”) under which employees may be awarded equity appreciation units and equity participation units. The Plan is designed to allow participants, who consist of any officer or employee, to share in our value through the issuance of equity participation units and/or unit appreciation rights. Such awards do not include actual equity ownership of the Company. Costs of the Plan are amortized over the vesting period set for each award. The units outstanding at this time vest three years from the grant date. The liability under the Plan is recorded at fair market value on the balance sheet based on the book value of our equity units as of September 30, 2011.

Investment in Commodities Contracts, Derivative Instruments and Hedging Activities

Our operations and cash flows are subject to fluctuations due to changes in commodity prices. We are subject to market risk with respect to the price and availability of corn, the principal raw material used to produce ethanol and ethanol by-products. Exposure to commodity price risk results primarily from our dependence on corn in the ethanol production process. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow us to pass along increased corn costs to customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade and global demand and supply.

To minimize the risk and the volatility of commodity prices, primarily related to corn and ethanol, we use various derivative instruments, including forward corn, ethanol and distillers grain purchase contracts, over-the-counter and exchange-trade futures and option contracts. When we have sufficient working capital available, we enter into derivative contracts to hedge our exposure to price risk related to forecasted corn needs and forward corn purchase contracts. We use cash, futures and options contracts to hedge changes to the commodity prices of corn and ethanol.

Certain contracts that literally meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal purchases or sales are documented as normal and exempted from the accounting and reporting requirements of derivative accounting. Gains and losses on contracts designated as normal purchases or normal sales contracts are not recognized until quantities are delivered or utilized in production.

In addition, the Company enters into short-term cash, options and futures contracts as a means of managing exposure to changes in commodity prices. We maintain a risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by market volatility. Our specific goal is to protect ourselves from large fluctuations in commodity costs but, our hedging activities can also 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. The effects, positive or negative, on our financial statements tend to be mitigated by offsetting changes in future periods; however, these offsetting changes do not always occur, in the same amounts and can have lag times of as much as twelve months.

Although our derivative instruments are intended to be effective economic hedges of specified risks, all of our derivatives are designated as non-hedge derivatives for accounting purposes. For derivative instruments that are not accounted for as hedges, the change in fair value is recorded through earnings in the period of change (commonly referred to as the “mark to market” method). The fair value of our derivatives are marked to market each period and changes in fair value are included in revenue when the contract relates to ethanol and costs of goods sold when the contract relates to corn.

By using derivatives to hedge exposures to changes in commodity prices, we have exposures on these derivatives to credit and market risk. We are exposed to credit risk that the counterparty might fail to fulfill its performance obligations under the terms of the derivative contract. We minimize our credit risk by entering into transactions with high quality counterparties, limiting the amount of financial exposure we have with each counterparty and monitoring the financial condition of our counterparties. Market risk is the risk that the value of the financial instrument might be adversely affected by a change in commodity prices. We manage market risk by incorporating monitoring parameters within our risk management strategy that limit the types of derivative instruments and derivative strategies we use, and the degree of market risk that may be undertaken by the use of derivative instruments.

As part of our trading activity, we use futures and option contracts offered through regulated commodity exchanges to reduce risk and risk of loss in the market value of inventories. To reduce that risk, we generally take positions using cash and futures contracts and options. Any realized or unrealized gain or loss related to these derivative instruments was recorded in the statement of operations as a component of revenue if the contracts relate to ethanol and cost of goods sold if the contracts relate to corn.

Inventory

Inventory is stated at the lower of cost or market value using the average cost method. Market value is based on current replacement values, except that it does not exceed net realizable values and it is not less than the net realizable values reduced by an allowance for normal profit margin.

Property and Equipment

Property and equipment is stated at cost. Construction in progress is comprised of costs related to constructing the plant and is depreciated upon completion of the plant. Depreciation is computed using the straight-line method over the following estimated useful lives:

	Buildings	40 Years
	Process Equipment	10-20 Years
	Office Equipment	3-7 Years

Maintenance and repairs are charged to expense as incurred; major improvements are capitalized.

Effective January 1, 2011, we increased the estimated useful life on a significant portion of our processing equipment. This change in estimate is accounted for on a prospective basis. This change resulted in a decrease in depreciation expense, an increase to operating income, a decrease of net (loss) of approximately $5.4 million, and a decrease in (loss) per Unit of $411 for Fiscal 2011.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss would be recognized when estimated undiscounted future cash flows from operations are less than the carrying value of the asset group. An impairment loss would be measured by the amount by which the carrying value of the asset exceeds the fair value of the asset. In accordance with our policies, management has evaluated the plants for possible impairment based on projected future cash flows from operations. Management has determined that its projected future cash flows from operations exceed the carrying value of the plant and that no impairment existed at September 30, 2011.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Not applicable.

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Southwest Iowa Renewable Energy, LLC

We have audited the accompanying balance sheets of Southwest Iowa Renewable Energy, LLC as of September 30, 2011 and 2010, and the related statements of operations, members’ equity, and cash flows for years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financing 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 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 Southwest Iowa Renewable Energy, LLC as of September 30, 2011 and 2010, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ McGladrey & Pullen, LLP

Des Moines, Iowa

November 22, 2011

Southwest Iowa Renewable Energy, LLC Balance Sheets - September 30, 2011 and 2010

		2011		2010
ASSETS

CURRENT ASSETS Cash and cash equivalents	$	11,006,590	$	3,432,544
Restricted cash		301,361		-
Accounts receivable		224,176		-
Accounts receivable, related party		17,642,245		23,392,670
Due from broker		3,428,450		2,260,015
Inventory		11,198,147		8,013,153
Derivative financial instruments, related party		-		688,039
Prepaid expenses and other		1,107,354		533,513
Total current assets		44,908,323		38,319,934

PROPERTY AND EQUIPMENT
Land		2,064,090		2,064,090
Plant, building, and equipment		203,749,761		199,771,260
Office and other equipment		742,360		720,529
		206,556,211		202,555,879
Accumulated depreciation		(42,293,441)		(28,757,303)
		164,262,770		173,798,576
OTHER ASSETS
Other		-		1,142,388
Financing costs, net of amortization of $2,341,400 and $1,949,651, respectively		1,538,733		1,930,482
Total other assets		1,538,733		3,072,870

TOTAL ASSETS	$	210,709,826	$	215,191,380

LIABILITIES AND MEMBERS’ EQUITY

CURRENT LIABILITIES Accounts payable Accounts payable, related parties Derivative financial instruments, related party	$	2,090,561 5,239,128 2,097,075	$	978,388 2,542,055 -
Derivative financial instruments		2,875,075		75,125
Accrued expenses		2,615,092		2,624,916
Accrued expenses, related parties		3,831,583		2,913,206
Current maturities of notes payable		21,236,780		18,058,574
Total current liabilities		39,985,294		27,192,264

NOTES PAYABLE, less current maturities		121,400,805		135,868,087
OTHER COMMITMENTS		600,010		700,006
		122,000,815		136,568,093


MEMBERS’ EQUITY
Members’ capital, 13,139 units issued & outstanding		76,474,111		76,474,111
Earnings (deficit)		(27,750,394)		(25,043,088)
		48,723,717		51,431,023

	$	210,709,826	$	215,191,380

See Notes to Financial Statements.

Southwest Iowa Renewable Energy, LLC

Statements of Operations


		Year Ended September 30, 2011		Year Ended September 30, 2010


Revenues	$	333,088,857	$	207,833,200
Cost of Goods Sold
Cost of goods sold – non hedging		327,923,835		205,108,935
Realized & unrealized hedging (gains)		(6,325,414)		(2,036,833)
Cost of Goods Sold		321,598,421		203,072,102

Gross Margin		11,490,436		4,761,098

General and administrative expenses		4,357,402		4,540,205
Operating income (loss)		7,133,034		220,893

Other income and (expense):
Interest income		17,835		46,473
Other income		43,531		130,032
Interest expense		(9,901,706)		(9,348,760)
		(9,840,340)		(9,172,255)

Net (loss)	$	(2,707,306)	$	(8,951,362)

Weighted average units outstanding		13,139		13,139

Net (loss) per unit – basic and diluted		$(206.05)		$(681.28)

See Notes to Financial Statements.

Southwest Iowa Renewable Energy, LLC

Statements of Members’ Equity

	Members’ Capital		Earnings (Deficit) Accumulated		Total

Balance, September 30, 2009	$	76,474,111	$	(16,091,726)	$	60,382,385
Net (loss)		---		(8,951,362)		(8,951,362)

Balance, September 30, 2010		76,474,111		(25,043,088)		51,431,023
Net (loss)		---		(2,707,306)		(2,707,306)

Balance, September 30, 2011	$	76,474,111	$	(27,750,394)	$	48,723,717

See Notes to Financial Statements.

Southwest Iowa Renewable Energy, LLC

Statements of Cash Flows

		Year Ended September 30, 2011		Year Ended September 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss)	$	(2,707,306)	$	(8,951,362)
Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities:
Depreciation		13,536,138		19,157,086
Amortization		391,749		481,974
Forgiveness of IDED note		-		(100,000)
(Increase) decrease in current assets:
Accounts receivables		5,526,249		(9,164,776)
Inventories		(3,184,994)		(3,099,478)
Prepaid expenses and other		(573,841)		(94,082)
Derivative financial instruments		688,039		(349,226)
Due from broker		(1,168,435)		(151,748)
Decrease in other non-current liabilities		(99,996)		(99,996)
Increase (decrease) in current liabilities:
Accounts payable		3,809,246		(2,826,473)
Derivative financial instruments		4,897,025		-
Accrued expenses		4,193,566		3,400,904
Net cash provided by (used in) operating activities		25,307,440		(1,797,177)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of property and equipment		(2,857,944)		(2,376,317)
Increase in other long term assets				(1,142,388)
Increase in restricted cash		(301,361)		---
Net cash (used in) investing activities		(3,159,305)		(3,518,705)

CASH FLOWS FROM FINANCING ACTIVITIES
Payments for financing costs		-		(30,139)
Proceeds from notes payable, net of refinance		13,300,000		13,726,754
Payments on notes payable		(27,874,089)		(12,403,273)
Net cash provided by (used in) financing activities		(14,574,089)		1,293,342
Net increase (decrease) in cash and cash equivalents		7,574,046		(4,022,540)

CASH AND CASH EQUIVALENTS
Beginning		3,432,544		7,455,084
Ending	$	11,006,590	$	3,432,544

SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES
Payment on Bridge loan in exchange for Negotiable Subordinated Term Note	$	-	$	8,773,300
Use of deposit for purchase of property and equipment	$	1,142,388		-
Accrued interest included in long term debt	$	3,285,013	$	3,590,027
Cash paid for interest	$	5,716,274	$	6,138,928

See Notes to Financial Statements

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

SOUTHWEST IOWA RENEWABLE ENERGY, LLC

Notes to Financial Statements

September 30, 2011

Note 1: Nature of Business

Southwest Iowa Renewable Energy, LLC (the “Company”), located in Council Bluffs, Iowa, was formed in March, 2005 and began producing ethanol in February 2009. In the year ended September 30, 2011 (“Fiscal 2011”) and the year ended September 30, 2010 (“Fiscal 2010”), the Company operates at 100% of its 110 million gallon nameplate capacity. The Company sells its ethanol, modified wet distillers grains with solubles, and corn syrup in the continental United States. The Company sells its dried distillers grains with solubles in the continental United States, Mexico, and the Pacific Rim.

Note 2: Summary of Significant Accounting Policies

Use of Estimates

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

Cash & Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less when purchased to be cash equivalents.

Restricted Cash

The Company has restricted cash used as collateral for a loan with the Iowa Department of Economic Development (“IDED”).

Financing Costs

Financing costs associated with the construction and revolving loans are recorded at cost and include expenditures directly related to securing debt financing. The Company began amortizing these costs using the effective interest method over the terms of the agreements in March, 2008. The interest expense amortization was capitalized during the development stage as construction in progress.

Concentration of Credit Risk

The Company’s cash balances are maintained in bank deposit accounts which at times may exceed federally-insured limits. The Company has not experienced any losses in such accounts.

Revenue Recognition

The Company sells ethanol and related products pursuant to marketing agreements. Revenues are recognized when the marketing company (the “Customer”) has taken title to the product, prices are fixed or determinable and collectability is reasonably assured.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 2: Summary of Significant Accounting Policies (continued)

The Company’s products are generally shipped FOB loading point. The Company’s ethanol sales are handled through an ethanol agreement (the “Ethanol Agreement”) with Bunge North America, Inc. (“Bunge”). Syrup, distillers grains and solubles, and modified wet distillers grains with solubles (co-products) are sold through a distillers grains agreement (the “DG Agreement”) with Bunge, which sets the price based on the market price to third parties. Marketing fees, agency fees, and commissions due to the marketers are paid separately from the settlement for the sale of the ethanol products and co-products and are included as a component of cost of goods sold. Shipping and handling costs incurred by the Company for the sale of ethanol and co-products are included in cost of goods sold.

Accounts Receivable

Trade accounts receivable are recorded at original invoice amounts less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering customers’ financial condition, credit history and current economic conditions. As of September 30, 2011, management had determined no allowance is necessary. Receivables are written off when deemed uncollectible and recoveries of receivables written off are recorded when received.

Incentive Compensation Plan

The Company established an incentive compensation plan under which employees may be awarded equity appreciation units and equity participation units. The fair value of the awards is amortized over the vesting period set for each award. The units outstanding as of September 30, 2011, vest three years from the grant date.

Investment in Commodities Contracts, Derivative Instruments and Hedging Activities

The Company’s operations and cash flows are subject to fluctuations due to changes in commodity prices. The Company is subject to market risk with respect to the price and availability of corn, the principal raw material used to produce ethanol and ethanol by-products. Exposure to commodity price risk results from its dependence on corn in the ethanol production process. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow the Company to pass along increased corn costs to customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade and global demand and supply.

To minimize the risk and the volatility of commodity prices, primarily related to corn and ethanol, the Company uses various derivative instruments, including forward corn, ethanol and distillers grains purchase contracts, over-the-counter and exchange-trade futures and option contracts. When the Company has sufficient working capital available, it enters into derivative contracts to hedge its exposure to price risk related to forecasted corn needs and forward corn purchase contracts. The Company uses cash, futures and options contracts to hedge changes to the commodity prices of corn and ethanol.

Management has evaluated the Company’s contracts to determine whether the contracts are derivative instruments. Certain contracts that literally meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal purchases or sales are documented as normal and exempted from the accounting and reporting requirements of derivative accounting. Gains and losses on contracts are designated as normal purchases or normal sales contracts are not recognized until quantities are delivered or utilized in production.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 2: Summary of Significant Accounting Policies (continued)

The Company applies the normal purchase and sale exemption to forward contracts relating to ethanol and distillers grains and solubles and therefore these forward contracts are not marked to market. As of September 30, 2011, the Company was committed to sell 18,390,652 gallons of ethanol and 70,018 tons of distillers grains and solubles.

For forward corn contracts initiated prior to September 28, 2010, the Company applied the normal purchase and sales exemption under derivative accounting. However, forward corn purchase contracts initiated after September 28, 2010 are not exempt from the accounting and reporting requirements of derivative accounting as the Company elected to net settle its forward corn contracts. Because there is no physical delivery associated with net-settled forward contracts, the Company no longer applies the normal purchase and sale exemption under derivative accounting for forward purchases of corn. Changes in fair value of our forward corn contracts, which are marked to market each period, are included in costs of goods sold. As of September 30, 2011, the Company was committed to purchasing 3.258 million bushels of corn on a forward contract basis resulting in a total commitment of approximately $20,892,000. These forward contracts had a fair value of approximately $18,795,000 at September 30, 2011.

In addition, the Company enters into short-term cash, options and futures contracts as a means of managing exposure to changes in commodity prices. The Company enters into derivative contracts to hedge the exposure to volatile commodity price fluctuations. The Company maintains a risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by market volatility. The Company’s specific goal is to protect itself from large moves in commodity costs. All derivatives designated as non-hedge derivatives and the contracts will be accounted for at fair value. Although the contracts will be effective economic hedges of specified risks, they are not designated as and accounted for as hedging instruments.

The Company is exposed to certain risks related to ongoing business operations. The primary risks that the Company manages by using forward or derivative instruments are price risk on anticipated purchases of corn and sales of ethanol.

As part of its trading activity, the Company uses futures and option contracts offered through regulated commodity exchanges to reduce risk and risk of loss in the market value of inventories. To reduce that risk, the Company generally takes positions using cash and futures contracts and options. The gains or losses are included in revenue if the contracts relate to ethanol and cost of goods sold if the contracts relate to corn. During the twelve months ended September 30, 2011 and 2010, the Company recorded a combined realized and unrealized (gain) of ($6,325,414) and ($2,036,833), respectively, as a component of cost of goods sold.

The Company is subject to market risk with respect to the price and availability of corn, the principal raw material used to produce ethanol and ethanol co-products. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow the Company to pass along increased corn costs to customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade and global demand and supply.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 2: Summary of Significant Accounting Policies (continued)

The effect of derivatives on the gross margin for the three and nine months ended September 30, 2011 and 2010 is summarized below:

		Balance Sheet Classification		Number of Bushels at September 30, 2011			Fair Value at September 30, 2011			Fair Value at September 30, 2010
Derivative Asset
	Derivative asset, related party		Current Asset		-	$	-	$	688,039
	Derivative liability		Current Liability		2,845,000	$	2,875,075	$	75,125
	Derivative liability, related party		Current Liability		3,258,143	$	2,097,075	$	-

	Statement of Operations Classification			Twelve Months Ended September 30, 2011		Twelve Months Ended September 30, 2010

Realized losses (gains)		Cost of Goods Sold	$	(11,910,478)	$	1,423,919
Unrealized (gains) losses		Cost of Goods Sold		5,585,064		(612,914)
Net realized and unrealized (gains) losses			$	(6,325,414)	$	(2,036,833)

Inventory

Property and Equipment

Property and equipment are stated at cost. Depreciation is computed using the straight-line method over the following estimated useful lives:

	Buildings	40 Years

	Process Equipment	10 - 20 Years

	Office Equipment	3-7 Years

Maintenance and repairs are charged to expense as incurred; major improvements and betterments are capitalized. Effective January 1, 2011 the Company increased the estimated of useful life on a significant portion of its processing equipment. This change in estimate is accounted for on a prospective basis. This change resulted in a decrease in depreciation expense, an increase to operating income, a decrease net (loss) of approximately $5.4 million, and a decrease in (loss) per unit of $411 for Fiscal 2011.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss would be recognized when estimated undiscounted future cash flows from operations are less than the carrying value of the asset group. An impairment loss would be measured by the amount by which the carrying value of the asset exceeds the fair value of the asset. In accordance with Company policies, management has evaluated the plant for possible impairment based on projected

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 2: Summary of Significant Accounting Policies (continued)

future cash flows from operations. Management has determined that its projected future undiscounted cash flows from operations exceed the carrying value of the plant and that no impairment existed at September 30, 2011.

Income Taxes

The Company has elected to be treated as a partnership for federal and state income tax purposes and generally does not incur income taxes. Instead, the Company’s earnings and losses are included in the income tax returns of the members. Therefore, no provision or liability for federal or state income taxes has been included in these financial statements.

Management has evaluated the Company’s tax positions under the Financial Accounting Standards Board issued guidance on accounting for uncertainty in income taxes and concluded that the Company has taken no uncertain tax positions that require adjustment to the financial statements to comply with the provisions of this guidance. With few exceptions, the Company is no longer subject to income tax examinations by the U.S. Federal, state or local authorities for the years before 2008.

Net (loss) per unit

(Loss) per unit has been computed on the basis of the weighted average number of units outstanding during each period presented.

Fair value of financial instruments

The carrying amounts of cash and cash equivalents, derivative financial instruments, accounts receivable, accounts payable and accrued expenses approximate fair value due to the short term nature of these instruments. The Company believes it is not practical to estimate the fair value of debt.

Risks and Uncertainties

The Volumetric Ethanol Excise Tax Credit (“VEETC”) is set to expire on December 31, 2011. The ongoing debate in budget discussions in the U.S. Congress provides uncertainty as to whether or not VEETC will be extended, and there have been proposals to eliminate it. If this tax credit is not renewed before the end of 2011, it likely would have a negative impact on the price of ethanol and the demand for ethanol in the market due to reduced discretionary blending of ethanol. Discretionary blending occurs when gasoline blenders use ethanol to reduce the cost of blended gasoline. However, due to the Renewable Fuels Standard (the “RFS”), demand for ethanol may continue to mirror the RFS requirement, even if the VEETC is not renewed past 2011. If the RFS is reduced or eliminated, the decrease in demand for ethanol related to the elimination of VEETC may be more substantial.

Note 3: Inventory

Inventory is comprised of the following at:

	September 30, 2011		September 30, 2010

Raw materials – corn	$	1,737,842	$	3,796,261
Supplies and chemicals		2,167,919		1,716,922
Work in process		2,026,188		1,484,157
Finished goods		5,266,198		1,015,813
Total	$	11,198,147	$	8,013,153

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 4: Members’ Equity

At September 30, 2011 and September 30, 2010 outstanding member units were:

A Units	8,805
B Units	3,334
C Units	1,000

The Series A, B and C unit holders all vote on certain matters with equal rights. The Series C unit holders as a group have the right to elect one Board member. The Series B unit holders as a group have the right to elect the number of Board members which bears the same proportion to the total number of Directors in relation to Series B outstanding units to total outstanding units. Series A unit holders as a group have the right to elect the remaining number of Directors not elected by the Series C and B unit holders.

Note 5: Revolving Loan/Credit Agreements

AgStar

The Company entered into a Credit Agreement (the “Credit Agreement”) with AgStar Financial Services, PCA (“AgStar”) and a group of lenders (together, the “Lenders”) for $126,000,000 senior secured debt, consisting of a $111,000,000 construction loan and a $15,000,000 revolving line of credit. Borrowings under the loan include a variable interest rate based on LIBOR plus 4.45% for each advance under the Credit Agreement. On August 1, 2009, the loan was segmented into an amortizing term facility of $101,000,000, a term revolver of $10,000,000 and a revolving working capital term facility of $15,000,000. On September 1, 2011, the Company elected to convert 50% of the term note into a fixed rate loan at the lender’s bonds rate plus 4.45%, with a 6% floor. The portion of the term loan not fixed and the term revolving line of credit accrues interest equal to LIBOR plus 4.45%, with a 6% floor. The Credit Agreement requires compliance with certain financial and nonfinancial covenants. As of September 30, 2011, the Company was in compliance with all required covenants. Borrowings under the Credit Agreement are collateralized by substantially all of the Company’s assets. The term credit facility of $101,000,000 requires monthly principal payments. The loan is amortized over 114 months and matures five years after the conversion date, August 1, 2014. The term of the $15,000,000 revolving working capital facility matures on March 31, 2012. Any borrowings are subject to borrowing base restrictions as well as certain prepayment penalties. The $10,000,000 term revolver is interest only until maturity on August 1, 2014.

Under the terms of the Credit Agreement, the Company may draw the lesser of $15,000,000 or 75 percent of eligible accounts receivable and eligible inventory. As part of the revolving line of credit, the Company may request letters of credit to be issued up to a maximum of $5,000,000 in the aggregate. There were no outstanding letters of credit as of September 30, 2011.

As of September 30, 2011 and 2010, the outstanding balance under the Credit Agreement was $96,753,936 and $114,616,726, respectively. In addition to all the other payments due under the Credit Agreement, the Company also agreed to pay, beginning at the end of Fiscal 2010, an amount equal to 65% of the Company’s Excess Cash Flow (as defined in the Credit Agreement), up to a total of $4,000,000 per year, and $16,000,000 over the term of the Credit Agreement. The excess cash flow payment was modified by the Second Amendment to the Amended and Restated Credit Agreement dated June 30, 2011, whereby the Company also agreed to pay, beginning at the end of the Fiscal 2011, an amount equal to 65% of the Company’s Excess Cash Flow (as defined in the Credit Agreement), up to a total of $6,000,000 per year, and $24,000,000 over the term of the Credit Agreement. An excess cash flow payment of $3,757,406 for Fiscal 2011 is due and payable in four equal installments in the year ending September 30, 2012 (“Fiscal 2012”).

Southwest Iowa Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 5: Revolving Loan/Credit Agreements (continued)

On June 23, 2010, the Company amended and restated the Original Holdings Note by issuing a new note to Holdings (the “Holdings Note”), which increased the principal amount of such note to $28,107,000 (representing outstanding principal plus accrued interest payment date) and amended Holding’s right to proceeds from the sale or issuance of equity or debt securities during such time as Holdings holds Series U Units. The Holdings Note is convertible into Series U Units, at the option of Holdings, at the price of $3,000 per Unit. Interest accrues at the rate of 7.5 percent over six-month LIBOR. Principal and interest may be paid only after payment in full under the Credit Agreement. As of September 30, 2011 and 2010, there was $31,663,730 and $29,290,300 outstanding under the Holdings Note, respectively. There was $425,500 and $404,000 of accrued interest (including accrued expenses, related parties) due to Holdings as of September 30, 2011 and 2010, respectively.

The Company entered into a revolving note with Holdings dated August 26, 2009 (the “Holdings Revolving Note”), providing for the extension of a maximum of $10,000,000 in revolving credit. Holdings has a commitment, subject to certain conditions, to advance up to $3,750,000 at the Company’s request under the Holdings Revolving Note; amounts in excess of $3,750,000 may be advanced by Holdings in its discretion. Interest accrues at the rate of 7.5 percent over six-month LIBOR. While repayment of the Holdings Revolving Note is subordinated to the Credit Agreement, the Company may make payments on the Revolving Note so long as it is in compliance with its borrowing base covenant and there is not a payment default under the Credit Agreement. As of September 30, 2011 and 2010, the balance outstanding was $3,000,000 and $0, respectively, under the Holdings Revolving Note.

On June 17, 2010, ICM, Inc. (“ICM”) issued the a term note to the Company (the “ICM Term Note”) in the amount of $9,970,000, which is convertible at the option of ICM into Series C Units at a conversion price of $3,000 per unit. As of September 30, 2011 and 2010, there was $10,903,000 and $10,061,000 outstanding under the ICM Term Note, respectively, and approximately $146,500 and $139,000 of accrued interest due (including accrued expense, related party) to ICM, respectively.

Note 6: Notes Payable

Notes payable consists of the following as of September 30, 2011 and September 30, 2010:

		September 30, 2011		September 30, 2010
$300,000 Note payable to IDED, a non-interest bearing obligation with monthly payments of $2,500 due through the maturity date of March 2016 on the non-forgivable portion. (A)	$	280,000	$	-
$200,000 Note payable to IDED, a non-interest bearing obligation with monthly payments of $1,667 due through the maturity date of March 2012 on the non-forgivable portion. (A)		8,333		28,333

Note payable to affiliate Holdings, bearing interest at LIBOR plus 7.50-10.5% (7.93% at September 30, 2011); maturity on August 31, 2014.		31,663,730		29,220,130

Note payable to affiliate ICM, bearing interest at LIBOR plus 7.50-10.5% (7.93% at September 30, 2011); maturity on August 31, 2014.		10,902,885		10,061,472

Southwest Iowa Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 6: Notes Payable (continued)

Term facility payable to AgStar bearing interest at LIBOR plus 4.45%, with a 6.00% floor (6.00% at September 30, 2011); maturity on August 1, 2014.		43,593,856 39,660,080		95,366,726

Term revolver payable to AgStar bearing interest at LIBOR plus 4.45%, with a 6.00% floor (6.00% at September 30, 2011); maturity on August 1, 2014.		10,000,000		10,000,000

$15 million revolving working capital term facility payable to AgStar bearing interest at LIBOR plus 4.45% with a 6.00% floor (6.00% at June 30, 2011), maturing March 31, 2012.		3,500,000		9,250,000

Capital leases payable to AgStar bearing interest at 3.088% maturing May 15, 2013.		28,701		-

Revolving line of credit payable to affiliate Holdings bearing interest at LIBOR plus 7.50-10.5% with a floor of 3.00% (7.74% at September 30, 2011).		3,000,000		-
Less current maturities		142,637,585 (21,236,780)		153,926,661 (18,058,574)
Total long term debt	$	121,400,805	$	135,868,087

(A) The $300,000 IDED loan is comprised of two components under the Master Contract (the “Master Contract”) between the Company and IDED: i) a $150,000, non interest-bearing component that requires monthly payments of $2,500, which began in March, 2011 with a final payment of $2,500 due February, 2016; and ii) a $150,000 forgivable loan. The Company has a $300,000 letter of credit with regard to the $300,000 loan (secured by a time deposit account in the same amount) to collateralize the loan. The note under the Master Contract is collateralized by substantially all of the Company’s assets, subordinate to the Credit Agreement.

Approximate aggregate maturities of notes payable as of September 30, 2011 are as follows:

Year Ended September 30,
2012	$	21,236,780

2013		10,805,628

2014		110,555,538

2015		30,000

2016		10,000
Total	$	142,637,585

Southwest Iowa Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 7: Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company used various methods including market, income and cost approaches. Based on these approaches, the Company often utilized certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable inputs. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Based on the observable inputs used in the valuation techniques, the Company is required to provide the following information according to the fair value hierarchy.

The fair value hierarchy ranks the quality and reliability of the information used to determine fair values. Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

Level 1 -

Valuations for assets and liabilities traded in active markets from readily available pricing sources for market transactions involving identical assets or liabilities.

Level 2 -

Valuations for assets and liabilities traded in less active dealer or broker markets. Valuations are obtained from third-party pricing services for identical or similar assets or liabilities.

Level 3 -

Valuations incorporate certain assumptions and projections in determining the fair value assigned to such assets or liabilities.

A description of the valuation methodologies used for instruments measured at fair value, including the general classifications of such instruments pursuant to the valuation hierarchy, is set below.

Derivative financial statements. Commodity futures and exchange traded options are reported at fair value utilizing Level 1 inputs. For these contracts, the Company obtains fair value measurements from an independent pricing service. The fair value measurements consider observable data that may include dealer quotes and live trading levels from the Chicago Mercantile Exchange (“CME”) market. Ethanol contracts are reported at fair value utilizing Level 2 inputs from third-party pricing services. Forward purchase contracts are reported at fair value utilizing

Level 2 inputs. For these contracts, the Company obtains fair value measurements from local grain terminal values. The fair value measurements consider observable data that may include live trading bids from local elevators and processing plants which are based off the CME market.

The following table summarizes financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2011 and 2010, segregated by the level of the valuation inputs within the fair value hierarchy utilized to measure fair value:

Southwest Iowa Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 7: Fair Value Measurement (continued)

September 30, 2011

		Total		Level 1		Level 2		Level 3
Readily marketable inventories (corn)		$	1,737,842	$	---	$	1,737,842		---

Derivative financial instruments

	Corn forward contracts asset (liability)	$	(2,097,075)	$	---	$	(2,097,075)	$	---

	Corn futures & exchange traded options asset ( liability)	$	(2,875,075)	$	(2,875,075)	$	---	$	---
		$	(3,234,308)	$	(2,875,075)	$	(359,233)	$	---

September 30, 2010

		Total		Level 1		Level 2		Level 3
Derivative financial instruments

	Corn forward contracts asset (liability)	$	688,039	$	---	$	688,039	$	---

	Corn futures & exchange traded options asset (liability)	$	(75,125)	$	(75,125)	$	---	$	---
		$	612,914	$	(75,125)	$	688,039	$	---

Certain financial assets and liabilities are measured at fair value on a non-recurring basis; that is the instruments are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances, for example, when there is evidence of impairment.

Note 8: Incentive Compensation

The Company has a unit appreciation plan which provides that the Board of Directors may make awards of equity participation units (“EPUs”) to employees from time to time, subject to vesting provisions as determined for each award. The EPUs are valued at book value. The Company had five unvested EPUs outstanding under this plan as of September 30, 2011, which will vest three years from the date of the award. During the twelve months ended September 30, 2011 and 2010, the Company recorded compensation expense related to this plan of approximately $5,264, and none, respectively. As of September 30, 2011 and 2010, the Company had a liability of approximately $5,264 and none, respectively, outstanding as deferred compensation and has approximately $13,686 to be recognized as future compensation expense over the weighted average vesting period of approximately three years. The amount to be recognized in future years as compensation expense is estimated based on book value of the Company. The liability under the plan is recorded at fair market value on the balance sheet based on the book value of the Company’s equity units as of September 30, 2011.

Southwest Iowa Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 9: Related Party Transactions

Bunge

On November 1, 2006, in consideration of its agreement to invest $20,004,000 in the Company, Bunge purchased the only Series B Units under an arrangement whereby the Company would (i) enter into various agreements with Bunge or its affiliates discussed below for management, marketing and other services, and (ii) have the right to elect a number of Series B Directors which are proportionate to the number of Series B Units owned by Bunge, as compared to all Units. Under the Company’s Third Amended and Restated Operating Agreement (the “Operating Agreement”), the Company may not, without Bunge’s approval (i) issue additional Series B Units, (ii) create any additional Series of Units with rights which are superior to the Series B Units, (iii) modify the Operating Agreement to adversely impact the rights of Series B Unit holders, (iv) change its status from one which is managed by managers, or vise versa, (v) repurchase or redeem any Series B Units, (vi) take any action which would cause a bankruptcy, or (vii) approve a transfer of Units allowing the transferee to hold more than 17% of the Company’s Units or to a transferee which is a direct competitor of Bunge.

Bunge N.A. Holdings, Inc. (“Holdings”) agreed to extend the Company a Subordinated Term Note, dated August 26, 2009 (the “Original Holdings Note”), due on August 31, 2014, repayment of which is subordinated to the Credit Agreement. On June 23, 2010, the Company amended and restated the Original Holdings Note by issuing the Holdings Note to Holdings, which increased the principal amount of such note to $28,107,000 (representing outstanding principal plus accrued interest payment date) and amended Holding’s right to proceeds from the sale or issuance of equity or debt securities during such time as Holdings holds Series U Units. The Holdings Note is convertible into Series U Units, at the option of Holdings, at the price of $3,000 per Unit. Interest accrues at the rate of 7.5 percent over six-month LIBOR. Principal and interest may be paid only after payment in full under the Credit Agreement. As of September 30, 2011 and 2010, there was $31,663,730 and $29,290,300 outstanding under the Holdings Note, respectively, and approximately $425,500 and $404,000 of accrued interest due to Holdings as of September 30, 2011 and 2010, respectively.

The Company entered into a revolving note with Holdings dated August 26, 2009 (the “Holdings Revolving Note”), providing for the extension of a maximum of $10,000,000 in revolving credit. Holdings has a commitment, subject to certain conditions, to advance up to $3,750,000 at the Company’s request under the Holdings Revolving Note; amounts in excess of $3,750,000 may be advanced by Holdings in its discretion. Interest will accrue at the rate of 7.5-10.5 percent over six-month LIBOR (with a floor of 3.00%). While repayment of the Holdings Revolving Note is subordinated to the Credit Agreement, the Company may make payments on the Revolving Note so long as it is in compliance with its borrowing base covenant and there is not a payment default under the Credit Agreement. As of September 30, 2011 and 2010, the balance outstanding was $3,000,000 and $0, respectively, under the Holdings Revolving Note.

In December, 2008, the Company and Bunge entered into other various agreements. Under a Lease Agreement (the “Lease Agreement”), the Company leased from Bunge a grain elevator located in Council Bluffs, Iowa, for approximately $67,000 per month. The lease was terminated on May 1, 2011. Expenses for the twelve months ended September 30, 2011 and 2010 were $467,063 and $799,964, respectively, under the Lease Agreement.

Under the Ethanol Agreement, the Company sells Bunge all of the ethanol produced at its facility, and Bunge purchases the same, up to the facility’s nameplate capacity of 110,000,000 gallons a year. The Company pays Bunge a per-gallon fee for ethanol sold by Bunge, subject to a minimum annual fee of $750,000 and adjusted according to specified indexes after three years. The initial term of the agreement, which commenced August 20, 2009, is three years and it will automatically renew for successive three-year terms unless one party provides the other with notice of their election to terminate 180 days prior to the end of the term. The Company has incurred expenses of $1,820,836 and $773,060 during the twelve months ended September 30, 2011 and 2010, respectively, under the Ethanol Agreement.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 9: Related Party Transactions (continued)

Under a Risk Management Services Agreement effective January 1, 2009, Bunge agreed to provide the Company with assistance in managing its commodity price risks for a quarterly fee of $75,000. The agreement has an initial term of three years and will automatically renew for successive three year terms, unless one party provides the other notice of their election to terminate 180 days prior to the end of the term. Expenses under this agreement for the twelve months ended September 30, 2011 and 2010 were $300,000.

On June 26, 2009, the Company executed a Railcar Agreement with Bunge for the lease of 325 ethanol cars and 300 hopper cars which are used for the delivery and marketing of ethanol and distillers grains. Under the Railcar Agreement, the Company leases railcars for terms lasting 120 months and continuing on a month to month basis thereafter. The Railcar Agreement will terminate upon the expiration of all railcar leases. Expenses under this agreement for the twelve months ended September 30, 2011 and were $4,855,718 and $4,855,683, respectively.

The Company entered into a Distillers Grain Purchase Agreement dated October 13, 2006, as amended (“DG Agreement”) with Bunge, under which Bunge is obligated to purchase from the Company and the Company is obligated to sell to Bunge all distillers grains produced at the Facility. If the Company finds another purchaser for distillers grains offering a better price for the same grade, quality, quantity, and delivery period, it can ask Bunge to either market directly to the other purchaser or market to another purchaser on the same terms and pricing. The Company expensed $1,725,423 and $977,658 in fees during Fiscal 2011 and Fiscal 2010.

The initial ten year term of the DG Agreement began February 1, 2009. The DG Agreement automatically renews for additional three year terms unless one party provides the other party with notice of election to not renew 180 days or more prior to expiration. Under the DG Agreement, Bunge pays the Company a purchase price equal to the sales price minus the marketing fee and transportation costs. The sales price is the price received by Bunge in a contract consistent with the DG Marketing Policy or the spot price agreed to between Bunge and the Company. Bunge receives a marketing fee consisting of a percentage of the net sales price, subject to a minimum yearly payment of $150,000. Net sales price is the sales price less the transportation costs and rail lease charges. The transportation costs are all freight charges, fuel surcharges, and other accessorial charges applicable to delivery of distillers grains. Rail lease charges are the monthly lease payment for rail cars along with all administrative and tax filing fees for such leased rail cars.

On August 26, 2009, in connection with our issuance of the Holdings Note, we also executed that Bunge Agreement—Equity Matters (the “Holdings Equity Agreement”), which was subsequently amended on June 17, 2010, under which (i) Holdings has preemptive rights to purchase new securities in us, and (ii) we are required to redeem any Series U Units held by Holdings with 76% of the proceeds received by us from the issuance of equity or debt securities. Holdings has waived its right to purchase any equity in us in connection with our issuance of Notes and subsequent conversion of the Notes by Holders.

On November 12, 2010, the Company entered into a Corn Oil Agency Agreement with Bunge to market its corn oil (the “Corn Oil Agency Agreement”). The Corn Oil Agency Agreement has an initial term of three years and will automatically renew for successive three-year terms unless one party provides the other notice of their election to terminate 180 days prior to the end of the term. Expenses under this agreement for the twelve months ended September 30, 2011 and 2010 were $87,870 and $0, respectively.

ICM

On November 1, 2006, in consideration of its agreement to invest $6,000,000 in the Company, ICM became the sole Series C Member. As part of ICM’s agreement to invest in Series C Units, the Operating Agreement provides that the Company will not, without ICM’s approval (i) issue additional Series C Units, (ii) create any additional Series of Units with rights senior to the Series C Units, (iii) modify the Operating Agreement to adversely impact the rights of Series C Unit holders, or (iv) repurchase or redeem any Series C Units. Additionally, ICM, as the sole Series C Unit owner, is afforded the right to elect one Series C Director to the Board so long as ICM remains a Series C Member.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 9: Related Party Transactions (continued)

On June 17, 2010, the Company issued the ICM Term Note in the amount of $9,970,000, which is convertible at the option of ICM into Series C Units at a conversion price of $3,000 per unit. As of September 30, 2011 and 2010, there was approximately $10,903,000 and $10,061,000 outstanding under the ICM Term Note, respectively, and approximately $146,500 and $139,000 of accrued interest due to ICM as of September 30, 2011 and 2010, respectively.

Additionally, to induce ICM to agree to the ICM Term Note, the Company entered into an equity agreement with ICM (the “ICM Equity Agreement”) on June 17, 2010, whereby ICM (i) retains preemptive rights to purchase new securities in the Company, and (ii) receives 24% of the proceeds received by the Company from the issuance of equity or debt securities.

On July 13, 2010, the Company entered into a Joint Defense Agreement (the “Joint Defense Agreement”) with ICM, which contemplates that the Company may purchase from ICM one or more Tricanter centrifuges (the “Centrifuges”). Because such equipment has been the subject of certain legal actions regarding potential patent infringement, the Joint Defense Agreement provides that: (i) that the parties may, but are not obligated to, share information and materials that are relevant to the common prosecution and/or defense of any such patent litigation regarding the Centrifuges (the “Joint Defense Materials”), (ii) that any such shared Joint Defense Materials will be and remain confidential, privileged and protected (unless such Joint Defense Materials cease to be privileged, protected or confidential through no violation of the Joint Defense Agreement), (iii) upon receipt of a request or demand for disclosure of Joint Defense Material to a third party, the party receiving such request or demand will consult with the party that provided the Joint Defense Materials and if the party that supplied the Joint Defense Materials does not consent to such disclosure then the other party will seek to protect any disclosure of such materials, (iv) that neither party will disclose Joint Defense Materials to a third party without a court order or the consent of the party who initially supplied the Joint Defense Materials, (v) that access to Joint Defense Materials will be restricted to each party’s outside attorneys, in-house counsel, and retained consultants, (vi) that Joint Defense Materials will be stored in secured areas and will be used only to assist in prosecution and defense of the patent litigation and (vii) if there is a dispute between us and ICM, then each party waives its right to claim that the other party’s legal counsel should be disqualified by reason of this the Joint Defense Agreement or receipt of Joint Defense Materials. The Joint Defense Agreement will terminate the earlier to occur of (x) upon final resolution of all patent litigation and (y) a party providing ten (10) days advance written notice to the other party of its intent to withdraw from the Joint Defense Agreement. No payments have been made by either party under the Joint Defense Agreement.

On August 25, 2010, the Company entered into a Tricanter Purchase and Installation Agreement (the “Tricanter Agreement”) with ICM, pursuant to which ICM sold the Company a tricanter oil separation system (the “Tricanter Equipment”). In addition, ICM installed the equipment at the Company’s ethanol plant in Council Bluffs, Iowa. As of September 30, 2011 and September 30, 2010, the Company paid $2,592,500 and $0, respectively, related to the Tricanter Agreement.

Note 10: Commitments

The Company has entered into a steam contract with an unrelated party under which the vendor agreed to provide the steam required by the Company, up to 475,000 pounds per hour. The Company agreed to pay a net energy rate for all steam provided under the contract as well as a monthly demand charge. The net energy rate is set for the first three years then adjusted each year beginning on the third anniversary date. The steam contract will remain in effect until January 1, 2019. Expenses under this agreement for the year ended September 30, 2011 and 2010 were $10,984,798 and $11,089,373, respectively.

In April, 2008 the Company entered into a Firm Throughput Service Agreement with a natural gas supplier, an unrelated party, under which the vendor agreed to provide the gas required by the Company, up to 900 Dth per day. The Company agreed to pay the maximum reservation and commodity rates as provided under the vendor’s FERC Gas Tariff as revised

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 10: Commitments (continued)

from time to time, as well as other additional charges. The agreement specifies an in-service date of October 1, 2008, and the term of the agreement is seven years. Expenses for the year ended September 30, 2011 and 2010 were $40,217 and $32,089, respectively.

The Company purchased 70,608 and 68,601 kilowatts of electricity for the years ended September 30, 2011 and 2010, respectively, from an unrelated party, MidAmerica Energy Company (“MidAm”) under an Electric Service Contract (“Electric Contract”) dated December 15, 2006. Under the Electric Contract, the Company is allowed to install a standby generator, which would operate in the event MidAm is unable to provide the Company with electricity.

In the Electric Contract, the Company agreed to own and operate a 13 kV switchgear with metering bay, all distribution transformers, and all 13 kV and low voltage cable on the Company’s side of the switchgear. The Company agreed to pay (i) a service charge of $200 per meter, (ii) a demand charge of $3.38 in the Summer and $2.89 in the Winter (iii) a reactive demand charge of $0.49/kVAR of reactive demand in excess of 50% of billing demand, (iv) an energy charge ranging from $0.03647 to $0.01837 per kilowatt hour, depending on the amount of usage and season, (v) tax adjustments, (vi) AEP and energy efficiency cost recovery adjustments, and (vii) a CNS capital additions tracker. These rates only apply to the primary voltage electric service provided under the Electric Contract. The electric service will continue at these prices for up to 60 months, but in any event will terminate on June 30, 2012. The pricing under the Electric Contract is based on the assumptions that the Company will have an average billing demand of 7,300 kilowatts per month and that the Company will average an 85% load factor over a 12 month period. If these assumptions are not met, the Company will pay the most applicable tariff rate. Additionally, at any time, the Company may elect to be charged under one of MidAm’s electric tariffs.

In January, 2007, the Company entered into an agreement with an unrelated party, Iowa Interstate Railroad, LTD, to provide the transportation of the Company’s commodities from Council Bluffs, Iowa to an agreed upon customer location. The agreement continues for five years and will automatically renew for additional one year periods unless cancelled by either party. The Company agreed to pay a mutually agreed upon rate per car. Expenses for the year ended September 30, 2011 and 2010 were approximately $574,058 and $735,884, respectively, of which approximately $45,850 was included in accounts payable each year.

In August, 2008, the Company entered into an agreement with an unrelated party which establishes terms governing the Company’s purchase of natural gas. The agreement commenced in August, 2008 and has a term of two years. The agreement was renewed in the spring of 2011 for an additional one year period. The Company has incurred expenses of $3,358,519 and $3,135,678, for the year ended September 30, 2011 and 2010, respectively.

The Company leases certain equipment, vehicles, and operating facilities under non-cancellable operating leases that expire on various dates through 2017. The future minimum lease payments required under these leases are approximately $5,181,000 in 2012, $5,578,000 in 2013, $5,531,000 in 2014, $5,398,000 in 2015, $5,398,000 in 2016 and $13,186,000 thereafter. Rent expense related to operating leases for the years ended September 30, 2011 and 2010 was $5,633,982 and $5,937,612, respectively.

Note 11: Major Customers

On August 20, 2009, the Company entered into the Ethanol Agreement for marketing, selling, and distributing all of the ethanol and distillers grains with solubles produced by the Company. The Company has expensed $3,546,259 and $1,750,718 in marketing fees under this agreement for the twelve months ended September 30, 2011 and 2010, respectively. Revenues with this customer were $327,849,110 and $207,833,200, respectively, for the twelve months ended September 30, 2011 and 2010. Trade accounts receivable due from this customer were $17,642,245 and $23,392,670 September 30, 2011 and 2010, respectively.

Southwest Iowa Renewable Energy, LLC

Notes to Audited Financial Statements

Note 12: Contingent Liability

On March 24, 2011, the Company received a letter from the Environmental Protection Agency (the “EPA”) alleging violations of environmental regulations which could lead to the imposition of a civil penalty. In the letter, EPA offered the Company an opportunity to negotiate a resolution of the matter. The Company and EPA are currently attempting to negotiate a resolution and, to that end, the Company will be providing additional information to the EPA regarding the alleged violations. Based on the information available as of September 30, 2011, the Company established a reserve of $50,000 in anticipation of the potential for assessment of a civil penalty in this matter. The violations alleged in the letter have been addressed and the Company is aware of no ongoing violations with respect to the matters addressed in the letter.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

There are no items to report.

Item 9A. Controls and Procedures.

The Company’s management, including its President and Chief Executive Officer (our principal executive officer), Brian T. Cahill, along with its Controller (our principal financial officer), Karen L. Kroymann, have reviewed and evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amended, the “Exchange Act”), as of September 30, 2011. The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Based upon this review and evaluation, these officers believe that the Company’s disclosure controls and procedures are presently effective in ensuring that material information related to us is recorded, processed, summarized and reported within the time periods required by the forms and rules of the Securities and Exchange Commission (the “SEC”).

The Company’s management, including the Company’s principal executive officer and principal financial officer, have reviewed and evaluated any changes in the Company’s internal control over financial reporting that occurred as of September 30, 2011 and there has been no change that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

The Company’s management assessed the effectiveness of the Company’s internal control over financing reporting as of September 30, 2011. In making this assessment, the Company’s management used the criteria set forth by the Committee Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on this assessment, the Company’s management concluded that, as of September 30, 2011, the Company’s integrated controls over financial report were effective.

This annual report does not include an attestation report of the company’s registered public accounting firm pursuant to the exemption under Section 989G of the Dodd-Frank Act of 2010.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The Directors and/or officers listed below under “Independent Directors & Officers” meet the “independent director” standards applicable to companies listed on the Nasdaq Capital Market (though our Units are not listed on any exchange or quotation system). Contrariwise, those Directors listed below under “Interested Directors” do not meet the “independent director” standards applicable to companies listed on the Nasdaq Capital Market. None of the Directors listed below have served on the board of directors of any other company having a class of securities registered under Section 12 of the Exchange Act or subject to the requirements of Section 15(d) of the Exchange Act, nor have any of our Directors served as directors of an investment company registered under the Investment Company Act of 1940. Under the Operating Agreement, the independent Directors’ terms are staggered such that one Director will be up for election every year.

Director Qualifications

The table below discusses the experiences, qualifications and skills of each of our Directors which led to the conclusion that they should serve as such. Our Series A directors are nominated by the Board of Directors, following consideration by the Board Nominating Committee, and then elected by our Series A members. The two Series B Board members and the Series C Board member are appointed by Bunge and ICM, respectively, under the terms of our Operating Agreement.

Director	Experiences, Qualifications and Skills

Series A Directors	Elected by Series A Unit Holders
Theodore V. Bauer	Mr. Bauer’s background as a farmer and agribusinessman, as well as his past service on a number of civic and corporate boards, including the Iowa Quality Producers Alliance, an organization devoted to value-added agriculture and rural economic development, are important factors qualifying Mr. Bauer as one of the Board’s Series A independent directors.
Michael K. Guttau	Mr. Guttau was recruited to serve as an independent Series A Board member and as the Audit Committee Financial expert given his background and experience as a banking executive and board member of a number of banking and civic organizations. Mr. Guttau’s experience includes more than 30 years as a rural banker, providing a long-term view of agriculture and ag-related businesses.
Hubert M. Houser	Senator Houser brings to the Board more than 30 years of experience as a member of the Iowa legislature and the county board in which the Company is located. During his career, Senator Houser has developed a reputation as a leader in rural economic development. He provides significant assistance to the Board in the Company’s interaction with all levels of local and state government and also provides a long-term view of the further development of SIRE’s site and business.
Karol D. King		Mr. King, the Board’s Chairman and an independent Director elected by Series A members, has a long career as a farmer and owner of a number of ag-related business. In addition, Mr. King has held leadership positions in numerous local and national ag producer groups, in particular the Iowa and national corn growers associations. In these capacities he has participated in the development of the ethanol industry.

Series B Directors		Appointed by Bunge
Eric L. Hakmiller		Mr. Hakmiller is Vice-President and General Manager of Bunge Biofuels. Bunge Biofuels is involved in sourcing and supplying corn, selling DDGS in both domestic and export markets, selling biodiesel and marketing and trading ethanol. Bunge Biofuels also manages the risk of these volatile commodities to decrease market risk both for its own account and its marketing partners. Mr. Hakmiller brings this broader market view to his service as a SIRE Board member.
Tom J. Schmitt		With more than 32 years of agribusiness experience with Bunge, and in his capacity as Manager of Western Region, Bunge North America Oilseed Processing, Mr. Schmitt brings extensive experience to the Board in oversight of agribusiness facilities. Mr. Schmitt’s current responsibilities include management of the Bunge soy bean crush facility in Council Bluff’s, located near SIRE’s plant. This Bunge facility has an annual crush capacity of approximately 77 million bushels and is the largest soy bean crush facility in the United States.

Series C Directors		Appointed by ICM
Gregory P. Krissek		In his capacity as Director of Government Affairs for ICM, Mr. Krissek is intensely involved in public biofuels issues at the local, state and national level. In addition to bringing this insight to the Board, in addition to service on the Company’s Board, Mr. Krissek serves on the boards of six private ethanol companies and brings a broad view of ethanol plant operations to the Company.

Independent Directors & Officers

Name and Age	Position(s) Held with the Company	Term of Office and Length of Time Served	Principal Occupation(s) During Past 5 Years

Karol D. King, 64	Series A Director and Chairman	Term expires 2013, Director since November, 2006	Corn, popcorn and soybean farmer near Mondamin, Iowa, since 1967; President, King Agri Sales, Inc. (marketer of chemicals, fertilizer and equipment) since 1995; President, Kelly Lane Trucking, LLC, since 2007. Mr. King attended Iowa State University and has served on the Harrison County Farm Bureau Board, the Iowa Corn Growers Board, the Iowa Corn Promotion Board, the US Feed Grains Council Board, the National Gasohol Commission, and the National Corn Growers Association Board.
Theodore V. Bauer, 59	Series A Director, Secretary and Treasurer	Term expires 2012, Director since March 2005; Officer since November 2006	Director, Secretary and Treasurer (since 2005) of the Company; Owner and operator of a farming operation and hunting preserve near Audubon, Iowa, since 1977; Co-Founder, and from 2005 to 2007, Director, Templeton Rye Spirits LLC; Director, Iowa Quality Producers Alliance, since 2003; Vice President, West Central Iowa Rural Water, from 2002 to 2007. Mr. Bauer has an Ag Business degree from Iowa State University and is a graduate of the Texas A&M TEPAP program.
Hubert M. Houser, 69	Series A Director	Term expires 2014, Director since 2005	Lifetime owner of farm and cow-calf operation located near Carson, Iowa. Mr. Houser has served in the Iowa Legislature since 1993, first in the House of Representatives and currently in the Senate. Mr. Houser also served on the Pottawattamie County Board of Supervisors from 1979 to 1992, director of the Riverbend Industrial Park, and was a founder of the Iowa Western Development Association and Golden Hills RC&D.
Michael K. Guttau, 65	Series A Director	Term expires 2014, Director since 2007	Council of Federal Home Loan Banks, Washington, D.C.; Chairman from 2008 to 2009, Vice Chairman from 2004 to 2007, Chairman of Audit Committee from 2004 to 2006 and Chairman of Risk Management Committee (2007), Federal Home Loan Bank of Des Moines; since 1972, various positions with Treynor State Bank, currently CEO and Chairman of the Board; Superintendent of Banking, Iowa Division of Banking, from 1995 to 1999; Director, Iowa Bankers Association, Iowa Bankers Mortgage Corporation, Iowa Student Loan Liquidity Corp., Iowa Business Development Finance Corp. and Iowa See Capital Liquidation Corp.; President, Southwest Iowa Bank Administration Institute; Past Chairman, ABA Community Bankers from 1991 to 1992. Mr. Guttau received his B.S., Farm Operation, from Iowa State University in 1969 and completed numerous U.S. Army education programs from 1969 to 1978. Mr. Guttau is the 2010 recipient of the James Leach Bank Leadership Award.

Interested Directors

Name and Age	Position(s) Held with the Company	Term of Office† and Length of Time Served	Principal Occupation(s) During Past 5 Years

Tom J. Schmitt, 61†‡	Series B Director	Since July 17, 2009	Manager, Western Region, Bunge North America Oilseed Processing. Mr. Schmitt has worked with Bunge over thirty-two years. Mr. Schmitt received a Bachelor’s degree in business administration from St. Ambrose University.

Eric L. Hakmiller, 49†‡	Series B Director and Vice Chairman	Since July 17, 2009	Vice-President and General Manager, Bunge Biofuels, Bunge North America. Mr. Hakmiller received a Bachelor’s degree in economics from the University of Maine and a graduate degree from Loyola Marymount University.
Gregory P. Krissek, 49†‡	Series C Director	Since November 1, 2006	Director of Government Affairs, ICM, Inc., since 2006; Director of Marketing and Governmental Affairs, United Bio Energy, from 2003 to 2006; Chairman, National Ethanol Vehicle Coalition, 2007; Secretary-Treasurer of the Board, Ethanol Promotion and Information Council since 2004, President since June 2008; director, Kansas Association of Ethanol Processors since 2004; Kansas Energy Council, since 2004 prior Director of Operations, Kansas Corn Commission; Assistant Secretary, Kansas Department of Agriculture, 1997 to 2000.

† The Interested Directors’ terms do not have a specified number of years, as these Directors are nominated by the

Series B Member and the Series C Member, as discussed further below under Items 11 and 13.

‡ The information provided below under Item 13, “Certain Relationships and Related Transactions, and Director

Independence,” respecting the election of Messrs. Krissek, Schmitt, and Hakmiller as Directors, is incorporated into

this Item 10 by reference.

Executive Officers

Name

and Age

Position(s)

Held with the

Company

Length of

Time

Served

Principal Occupation(s)

During Past 5 Years

Brian T. Cahill, 58	President and Chief Operating Officer	Since September, 2009	Executive Vice President, Distillery Innovations Segment, MGP Ingredients, Inc. (“MGP”) (a public company, which provides services in the development, production and marketing of naturally-derived specialty ingredients and alcohol products) from 2007 to 2008; CFO/Vice President of Finance and Administration, MGP, from 2002 to 2007; General Manager, MGP, from 1992 to 2002. Mr. Cahill received a Bachelor of Science in Accounting from Bradley University and is a Certified Public Accountant.
Karen L. Kroymann, 50	Controller	Since June, 2009	Controller, Transgenomic, Inc., (a public company which provides services for DNA lab testing and manufacture-analysis equipment) from 2007 to 2008; Controller, TTI Technologies (a synthetic coal manufacturer) from 2006 to 2007; Asst. Controller, Future Foam (a manufacturer and fabricator of polyurethane foam) from 1999-2006). Ms. Kroymann received a Bachelor’s of Arts degree from Mt. St. Clare College, an M.B.A. from the University of Nebraska and is a Certified Public Accountant.

Code of Ethics

The Company adopted a code of ethics that applies to its employees and executive officers effective January 16, 2009.

Audit Committee

The Board has a standing Audit Committee which makes recommendations to the Board regarding the engagement of the independent registered public accounting firm for audit and non-audit services; evaluates the independence of the auditors and reviews with the independent auditors the fee, scope and timing of audit and non-audit services. The Audit Committee presently consists of Michael Guttau (Chair), Karol D. King and Theodore V. Bauer. Each member of the Audit Committee is considered “independent” under standards applicable to companies listed on the Nasdaq Capital Market (though the Company’s Units are not listed on any exchange or quotation system). Mr. Guttau is the financial expert who is required to serve on the audit committee under SEC rules and is considered an “independent” financial expert under standards applicable to companies listed on the Nasdaq Capital Market (though our Units are not listed on any exchange or quotation system). The Audit Committee held four meetings in Fiscal 2011.

Item 11. Executive Compensation.

Governance / Compensation Committee

The Governance / Compensation Committee (the “Governance Committee”) operates under a written charter, which the Governance Committee approved on February 15, 2007, and which was adopted by the Board of Directors on February 16, 2007 (the “Governance Charter”). The Governance Charter is available on the Company’s website. The Governance Charter provides that the Governance Committee will annually review and approve our compensation program for our Directors, officers and managers. The Governance Charter does not exclude from the Governance Committee’s membership Directors who also serve as officers of the Board or Interested Directors. Presently, the Governance Committee’s membership consists of Messrs. Schmitt (Chair), Bauer, and King. Accordingly, Messrs. Bauer and King did participate in recommending to the Board the Compensation Policy. The Governance Charter does provide that the Governance Committee may form and delegate its responsibilities to subcommittees, and the Governance Charter does not contemplate (nor does it prohibit) the use of compensation consultants to assist the Governance Committee in its determination of Director, officer and managers’ compensation.

Compensation of Executive Officers

In June 2010, we adopted the Plan. The purpose of the Plan is to allow any officer or employee of the Company to share in the Company’s value through the issuance, from time to time, of Equity Participation Units (“Equity Participation Units”) and/or Unit Appreciation Rights (“Unit Appreciation Right”) (as further described immediately below in “Long-Term Incentive Compensation”). Pursuant to the Plan and individual award agreements, the Governance Committee recommended and the Board approved the award of 5.11 Equity Participation Units to Mr. Cahill on December 17. 2010. Mr. Cahill’s award vests in full on December 17, 2013. Under the Plan, the Governance Committee is responsible for designing, reviewing and overseeing the administration of our executive compensation program. Pursuant to the Governance Charter, the Governance Committee approved the compensation terms for Mr. Cahill and Ms. Kroymann when they were hired in 2009, and has approved all adjustments since that time.

Subsequently, during Fiscal 2010, the Governance Committee engaged a compensation consultant (the “Consultant”) to evaluate the compensation of Mr. Cahill and Ms. Kroymann, as controller, in relation to other executive officers in comparable positions in the industry. Additionally, during Fiscal 2010, the Governance Committee met with the Consultant to develop a company-wide compensation philosophy based on comparable market data and establishment of a management evaluation process.

As such, the compensation of our senior executives is designed to achieve the following objectives: (i) align the interests of the executive officers and our Unit holders; (ii) attract, retain and motivate high caliber executive officers; and (iii) pay for performance by linking a significant amount of executive compensation to individual contribution to selected metrics of our business plan. The following are the main elements of compensation under our agreements with our two senior officers.

●

Base Salary: A portion of annual cash compensation is paid as base salary to provide a level of security and stability. Mr. Cahill’s annual base salary under his employment agreement is $180,000 while Ms. Kroymann is paid $101,694 in base salary.

●

Annual Cash Incentive: We expect that a significant portion of the annual cash compensation paid to the executive officers will be directly related to the achievement of individual performance goals and contributions. Awards were available for 2011 and were made to employees in November 2011.

●

Long-Term Incentive Compensation: As mentioned above, on June 30, 2010 our Board of Directors adopted the Plan for the purpose of attracting and retaining key personnel. The Plan is designed to allow Participants, who consist of any officer or employee, to share in our value through the issuance of Equity Participation Units and/or Unit Appreciation Rights. Each award will be granted pursuant to an individual award agreement, which will set forth the number of units or rights granted, the book value of our Series A Units as of the grant date for purposes of valuing each Equity Participation Unit or Unit Appreciation Right, the fiscal year for which the Equity Participation Unit or Unit Appreciation Right is granted, and any In-Service Payment Date (as defined in the Plan). All awards will be recommended by our Governance Committee and then approved by the Board of Directors.

●

Retirement and Welfare Benefits: We sponsor both a standard 401(k) and Roth 401(k) plan. To be eligible to participate, a new hire is eligible to participate the first of the month after their start date. While eligible employees are given an option to enroll, those who do not choose either “yes” or “no” are automatically enrolled in the standard 401(k) plan at 3% withholding. Under the program, we match the first 3%, and ½ of the next 2%, of the employee’s contributions. Each participant picks his or her own investment strategy—either the planned grouping of investments or individually selected investments. We have implemented a basic benefits plan for all full time employees, including medical, dental, life insurance and disability coverage.

Summary Compensation Table

The following table provides all compensation paid to our executive officers in Fiscal 2011 and 2010. Mr. Cahill was awarded 5.11 Equity Participation Units on December 17, 2010 (Fiscal 2011) which were valued at $3,914 per unit, the book value of our Units, or $20,001 in the aggregate, as of the grant date. These Equity Participation Units will not vest for three years under the Plan, subject to certain events which may result in accelerated vesting.

Name and Principal Position	Fiscal Year	Salary ($)	Bonus ($)	Stock Awards ($)	Total ($)
Brian T. Cahill, President and CEO	2011	$187,897	$45,000	$20,001(1)	$252,898
Brian T. Cahill, President and CEO	2010	$184,662	$15,000	-	$199,662

Karen L. Kroymann, Controller	2011	$101,694	$6,147	-	$107,841
Karen L. Kroymann, Controller	2010	$93,182	$10,000	-	$103,182

(1)

Mr. Cahill receives no benefit from the 5.11 Equity Participation Units he was awarded until they vest in 2013. As described in footnote 8 to the Company’s audited financial statements for the year ended September 30, 2011, the Equity Participation Units are valued at book value. The grant date fair value included in the Stock Awards column for the Equity Participation Units is based upon the probable outcome of the performance conditions as required by FASB ASC Topic 718 and assuming Mr. Cahill remains at the company for the required three years, the Equity Participation Units awarded to Mr. Cahill had a grant date fair value of $20,001.

Outstanding Equity Awards at Fiscal Year-End

	Stock Awards
Name and Principal Position	Number of Unvested Units	Market Value of Unvested Units
Brian T. Cahill, President and CEO	5.11(1)	$18,950

(1)

As mentioned above, Mr. Cahill was awarded 5.11 Equity Participation Units under the Plan that will vest in 2013. Mr. Cahill receives no benefit from any of the Equity Participation Units until such time they are vested in 2013. The Equity Participation Units awarded to Mr. Cahill were valued at $3,708 per unit as of September 30, 2011 for an aggregate award of $18,950.

Compensation of Directors

We do not provide our Directors with any equity or equity option awards, nor any non-equity incentive payments or deferred compensation. Similarly, we do not provide our Directors with any other perquisites, “gross-ups,” defined contribution plans, consulting fees, life insurance premium payments or otherwise. Following recommendation by the Governance Committee and subsequent approval by the Board on March 16, 2007, we pay our Directors the following amounts (collectively, the “Compensation Policy”): (i) each Director receives an annual retainer of $12,000, (ii) each Director receives $1,000 per Board meeting attended (whether in person or telephonic), and (iii) the Compensation Policy has been approved to provide each Director will receive $3,000 per Board meeting attended (whether in person or telephonic), to be implemented at such time when the Company’s financial condition improves, provided that the foregoing amounts in (i) – (iii) shall not exceed $24,000 per Director in any calendar year. Additionally, the following amounts are paid to Directors for specified services: (i) the Chairman of the Board is paid $7,500 per year, (ii) the Chairman of the Audit Committee and Audit Committee Financial Expert is paid $5,000 per year, (iii) the Chairmen of all other Committees are paid $2,500 per year, and (iv) the Secretary of the Board is paid $2,500 per year.

Independent Directors

The following table lists the compensation we paid in Fiscal 2011 to our Directors who are considered “independent” under standards applicable to companies listed on the Nasdaq Capital Market (though the Company’s Units are not listed on any exchange or quotation system) (the “Independent Directors”).

Name	Fees Earned or Paid in Cash	All Other Compensation	Equity or Non-Equity incentives	Total

Theodore V. Bauer	$26,500	$0	$0	$26,500
Hubert M. Houser	$26,500	$0	$0	$26,500
Karol D. King	$31,500	$0	$0	$31,500
Michael K. Guttau	$29,000	$0	$0	$29,000

Interested Directors

The following table lists the compensation we paid in Fiscal 2011 to our Directors who are not considered “independent” under standards applicable to companies listed on the Nasdaq Capital Market (though our Units are not listed on any exchange or quotation system) (the “Interested Directors”).

Name	Fees Earned or Paid in Cash	All Other Compensation	Equity or Non-Equity incentives	Total

Eric L. Hakmiller†	$26,500	$0	$0	$26,500
Tom J. Schmitt†	$26,500	$0	$0	$26,500
Gregory P. Krissek†	$24,000	$0	$0	$24,000

† The Directors fees payable to the Interested Directors are paid directly to their corporate employers at such Directors’ request, and the Interested Directors do not receive any compensation from the Company for their service as Directors.

Selection of our directors is governed by the Nominating Committee Charter, which was adopted by the Board of Directors on February 16, 2007. We also have an audit committee, which consists of Michael K. Guttau (Chairman), Theodore V. Bauer and Karol D. King. Mr. Guttau is the financial expert who is required to serve on the audit committee under SEC rules and is

considered an “independent” financial expert under standards applicable to companies listed on the Nasdaq Capital Market (though the our Units are not listed on any exchange or quotation system).

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Member Matters.

As of September 30, 2011, there were 8,805 Series A Units, 3,334 Series B Units, and 1,000 Series C Units issued and outstanding. The following table sets forth certain information as of September 30, 2011, with respect to the Unit ownership of: (i) those persons or groups (as that term is used in Section 13(d)(3) of the Exchange Act) who beneficially own more than 5% of any Series of Units, (ii) each Director of the Company, and (iii) all Officers and Directors of the Company, nine in number, as a group. The address of those in the following table is 10868 189th Street, Council Bluffs, Iowa 51503. Mr. Cahill and Ms. Kroymann serve in the capacity of executive officers. Except as noted below, the persons listed below possess sole voting and investment power over their respective Units. The following does not reflect any Units which may be issued to Holdings and ICM, respectively, under the terms of the convertible debt owed to them.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class

Series A	Theodore V. Bauer	36 Units1	0.41%
Series A	Hubert M. Houser	39 Units2	0.44%
Series A	Karol D. King	29 Units3	0.33%
Series A	Michael K. Guttau	12 Units4	0.14%
--	Brian T. Cahill	-0-	--
--	Karen L. Kroymann	-0-	--
--	Eric L. Hakmiller	-0-	--
--	Tom J. Schmitt	-0-	--
--	Gregory P. Krissek	-0-	--
Series B	Bunge North America, Inc.	3334 Units	100%
Series C	ICM, Inc.	1000 Units	100%
Series A	ICM Inc.	18 Units	0.14%

Series A	All Officers and Directors as a Group	116 Units	1.32%

____________________________________

1 These Series A Units are owned jointly by Mr. Bauer and his wife, Donna Bauer.

2 These Series A Units are owned jointly by Mr. Houser and his wife, Paula Houser.

3 These Series A Units are owned jointly by Mr. King and his wife, Rozanne King.

4 These Series A Units are owned jointly by Mr. Guttau and his wife, Judith Guttau.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Relationships and Related Party Transactions

Bunge

On November 1, 2006, in consideration of its agreement to invest $20,004,000 in the Company, Bunge purchased the only Series B Units under an arrangement whereby the Company would (i) enter into various agreements with Bunge or its affiliates discussed below for management, marketing and other services, and (ii) have the right to elect a number of Series B Directors which are proportionate to the number of Series B Units owned by Bunge, as compared to all Units. Under the Operating Agreement, we may not, without Bunge’s approval (i) issue additional Series B Units, (ii) create any additional Series of Units with rights which are superior to the Series B Units, (iii) modify the Operating Agreement to adversely impact the rights of Series B Unit holders, (iv) change its status from one which is managed by managers, or visa-versa, (v) repurchase or redeem any Series B Units, (vi) take any action which would cause a bankruptcy, or (vii) approve a transfer of Units allowing the transferee to hold more than 17% of our Units or to a transferee which is a direct competitor of Bunge.

Holdings agreed to extend the us the Original Holdings Note due on August 31, 2014, repayment of which is subordinated to the Credit Agreement. On June 23, 2010, we amended and restated the Original Holdings Note by issuing the Holdings Note to Holdings, which increased the principal amount of such note to $28,107,000 (representing outstanding principal plus accrued interest payment date) and amended Holding’s right to proceeds from the sale or issuance of equity or debt securities

during such time as Holdings holds Series U Units. The Holdings Note is convertible into Series U Units, at the option of Holdings, at the price of $3,000 per Unit. Interest accrues at the rate of 7.5 percent over six-month LIBOR. Principal and interest may be paid only after payment in full under the Credit Agreement. As of September 30, 2011 and 2010, there was $31,663,730 and $29,290,300 outstanding under the Holdings Note, respectively, and approximately $425,500 and $404,000 of accrued interest due to Holdings, respectively.

We entered into the Holdings Revolving Note, providing for the extension of a maximum of $10,000,000 in revolving credit. Holdings has a commitment, subject to certain conditions, to advance up to $3,750,000 at the Company’s request under the Holdings Revolving Note; amounts in excess of $3,750,000 may be advanced by Holdings in its discretion. Interest will accrue at the rate of 7.5 percent over six-month LIBOR. While repayment of the Holdings Revolving Note is subordinated to the Credit Agreement, the Company may make payments on the Revolving Note so long as it is in compliance with its borrowing base covenant and there is not a payment default under the Credit Agreement. As of September 30, 2011 and 2010, the balance outstanding was $3,000,000 and $0, respectively, under the Holdings Revolving Note.

In December, 2008, we and Bunge entered into other various agreements. Under a Lease Agreement (the “Lease Agreement”), we leased from Bunge a grain elevator located in Council Bluffs, Iowa, for approximately $67,000 per month. The lease was terminated on May 1, 2011. Expenses for the twelve months ended September 30, 2011 and 2010 were $467,063 and $799,964, respectively, under the Lease Agreement.

Under the Ethanol Agreement, we sell Bunge all of the ethanol produced at our Facility, and Bunge purchases the same, up to the Facility’s nameplate capacity of 110,000,000 gallons a year. We pay Bunge a per-gallon fee for ethanol sold by Bunge, subject to a minimum annual fee of $750,000 and adjusted according to specified indexes after three years. The initial term of the agreement, which commenced August 20, 2009, is three years and it will automatically renew for successive three-year terms unless one party provides the other with notice of their election to terminate 180 days prior to the end of the term. We have incurred expenses of $1,820,836 and $773,060 during Fiscal 2011 and 2010, respectively, under the Ethanol Agreement.

Under a Risk Management Services Agreement effective January 1, 2009, Bunge provides us with assistance in managing our commodity price risks for a quarterly fee of $75,000. The agreement has an initial term of three years and will automatically renew for successive three year terms, unless one party provides the other notice of their election to terminate 180 days prior to the end of the term. Expenses under this agreement for Fiscal 2011 and 2010 were $300,000 and $300,000, respectively.

On June 26, 2009, we executed a Railcar Agreement with Bunge for the lease of 325 ethanol cars and 300 hopper cars which are used for the delivery and marketing of ethanol and distillers grains. Under the Railcar Agreement, we lease railcars for terms lasting 120 months and continuing on a month to month basis thereafter. The Railcar Agreement will terminate upon the expiration of all railcar leases. Expenses under this agreement for Fiscal 2011 and 2010 were $4,855,718 and $4,855,683, respectively.

We entered into the DG Agreement with Bunge, under which Bunge buys from us and we are obligated to sell to Bunge all distillers grains produced at the Facility. If we find another purchaser for distillers grains offering a better price for the same grade, quality, quantity, and delivery period, we can ask Bunge to either market directly to the other purchaser or market to another purchaser on the same terms and pricing. We expensed $1,725,423 and $977,658 in fees during Fiscal 2011 and Fiscal 2010, respectively.

The initial ten year term of the DG Agreement began February 1, 2009. The DG Agreement automatically renews for additional three year terms unless one party provides the other party with notice of election to not renew 180 days or more prior to expiration. Under the DG Agreement, Bunge pays us a purchase price equal to the sales price minus the marketing fee and transportation costs. The sales price is the price received by Bunge in a contract consistent with the DG Marketing Policy or the spot price agreed to between Bunge and us. Bunge receives a marketing fee consisting of a percentage of the net sales price, subject to a minimum yearly payment of $150,000. Net sales price is the sales price less the transportation costs and rail lease charges. The transportation costs are all freight charges, fuel surcharges, and other accessorial charges applicable to delivery of distillers grains. Rail lease charges are the monthly lease payment for rail cars along with all administrative and tax filing fees for such leased rail cars.

Holdings with 76% of the proceeds received by us from the issuance of equity or debt securities. Holdings has waived its right to purchase any equity in us in connection with our issuance of Notes and subsequent conversion of the Notes by Holders.

On November 12, 2010, we entered into the Corn Oil Agency Agreement with Bunge to market our corn oil. The Corn Oil Agency Agreement has an initial term of three years and will automatically renew for successive three-year terms unless one party provides the other notice of their election to terminate 180 days prior to the end of the term. Expenses under this agreement for the twelve months ended September 30, 2011 and 2010 were $87,870 and $0, respectively.

ICM

On November 1, 2006, in consideration of its agreement to invest $6,000,000 in the Company, ICM became the sole Series C Member. As part of ICM’s agreement to invest in Series C Units, the Operating Agreement provides that we will not, without ICM’s approval (i) issue additional Series C Units, (ii) create any additional Series of Units with rights senior to the Series C Units, (iii) modify the Operating Agreement to adversely impact the rights of Series C Unit holders, or (iv) repurchase or redeem any Series C Units. Additionally, ICM, as the sole Series C Unit owner, is afforded the right to elect one Series C Director to the Board so long as ICM remains a Series C Member.

On June 17, 2010, we issued the ICM Term Note in the amount of $9,970,000, which is convertible at the option of ICM into Series C Units at a conversion price of $3,000 per unit. As of September 30, 2011 and 2010, there was $10,903,000 and $10,061,000 outstanding under the ICM Term Note, respectively, and approximately $146,500 and $139,000 of accrued interest due to ICM, respectively.

Additionally, to induce ICM to agree to the ICM Term Note, we entered into an equity agreement with ICM (the “ICM Equity Agreement”) on June 17, 2010, whereby ICM (i) retains preemptive rights to purchase new securities in the Company, and (ii) receives 24% of the proceeds received by us from the issuance of equity or debt securities as repayment for the ICM Tern Note.

On July 13, 2010, we entered into a Joint Defense Agreement (the “Joint Defense Agreement”) with ICM, in connection with our potential purchase of tricanter centrifuges (the “Centrifuges”) from ICM. Because the Centrifuges have been the subject of legal actions regarding potential patent infringement, the Joint Defense Agreement provides that: (i) the parties may share information and materials that are relevant to the common prosecution and/or defense of any such patent litigation regarding the Centrifuges (the “Joint Defense Materials”), (ii) any Joint Defense Materials will be and remain confidential, privileged and protected (subject to exceptions), (iii) upon receipt of a request or demand for disclosure of Joint Defense Material to a third party, the party receiving such request or demand will consult with the party that provided the Joint Defense Materials and if the party that supplied the Joint Defense Materials does not consent to such disclosure then the other party will seek to protect any disclosure of such materials, (iv) neither party will disclose Joint Defense Materials to a third party without a court order or the consent of the other party, (v) access to Joint Defense Materials will be restricted, (vi) Joint Defense Materials will be stored in secured areas and will be used only to assist in prosecution and defense of the patent litigation and (vii) if there is a dispute between us and ICM, then each party waives its right to claim that the other party’s legal counsel should be disqualified by reason of this the Joint Defense Agreement or receipt of Joint Defense Materials. The Joint Defense Agreement will terminate the earlier to occur of (i) upon final resolution of all patent litigation and (ii) a party providing ten (10) days advance written notice to the other party of its intent to withdraw from the Joint Defense Agreement. No payments have been made by either party under the Joint Defense Agreement.

On August 25, 2010, we entered into a Tricanter Purchase and Installation Agreement (the “Tricanter Agreement”) with ICM, under which ICM sold us a tricanter oil separation system (the “Tricanter Equipment”) and installed the equipment at our Facility. In the Tricanter Agreement, ICM agreed to indemnify and hold us harmless from all claims arising out of the infringement of adversely owned patents, copyrights or any other intellectual property rights in connection with our purchase and/or use of the Tricanter Equipment. As of June 30, 2011, we have paid $2,592,500 to ICM for the Tricanter Agreement.

We do not have any policies finalized and adopted by the Board governing the review or approval of related party transactions.

Director Independence

We classify our directors as “independent” according to the standards applicable to companies listed on the Nasdaq Capital Market (though our Units are not listed on any exchange or quotation system). Under the Operating Agreement, the independent directors’ terms are staggered such that one director will be up for election every year. Our independent directors

are Karol D. King, Theodore V. Bauer, Herbert M. Houser, and Michael K. Guttau. The Audit Committee currently consists of Michael K. Guttau (Chair), Theodore V. Bauer and Karol D. King. All of the members of the Audit Committee meet the “independent director” standards applicable to companies listed on the Nasdaq Capital Market (though our Units are not listed on any exchange or quotation system). Presently, the Nominating Committee’s membership consists of Theodore V. Bauer, Hubert M. Houser (Chair) and Karol D. King, all of whom meet the “independent director” standards applicable to companies listed on the Nasdaq Capital Market (though the Company’s Units are not listed on any exchange or quotation system). The Committee Charter does not exclude from its membership directors who also serve as officers or Interested Directors. The Governance Committee’s membership consists of Messrs. Bauer, King, and Schmitt (Chair). Mr. Schmitt is considered an Interested Director.

Audit Committee Report

The Audit Committee has reviewed and discussed the audited financial statements for Fiscal 2011 with management and discussed other matters related to the audit with the independent auditors. Management represented to the Audit Committee that our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America. The Audit Committee met with the independent auditors, with and without management present, and discussed with the independent auditors matters required to be discussed by Statement on Auditing Standards No. 61, as amended (Communication with Audit Committees). The independent auditors also provided to the Audit Committee the written disclosures and the letter required by Independence Standards Board Standard No. 1 (Independence Discussions with Audit Committees), and the Audit Committee discussed with the independent auditors the firm’s independence.

Based upon the Audit Committee’s discussions with management and the independent auditors, and the Audit Committee’s review of representations of management and the report of the independent auditors to the Audit Committee, the Audit Committee recommended that the Board of Directors include the audited financial statements in our Annual Report on Form 10-K for Fiscal 2011.

AUDIT COMMITTEE:

Michael K. Guttau, Chair

Theodore V. Bauer

Karol D. King

Item 14. Principal Accountant Fees and Services.

Independent Public Accountant Fees and Services

The following table presents fees paid for professional services rendered by our independent public accountants for Fiscal 2011 and Fiscal 2010:

Fee Category	Fiscal 2011 Fees	Fiscal 2010 Fees

Audit Fees	$131,250	$139,500

Audit-Related Fees	$0	$0

Tax Fees	$33,787	$56,991

All Other Fees	$0	$0

Total Fees	$165,037	$196,491

Audit Fees are for professional services rendered by McGladrey & Pullen, LLP (“McGladrey”) for the audit of the Company’s annual financial statements and review of the interim financial statements included in quarterly reports and services that are normally provided by McGladrey in connection with statutory and regulatory filings or engagements, including review of SEC registration statements and related correspondence.

Audit-Related Fees are for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees.” These services include accounting

consultations in connection with acquisitions, consultations concerning financial accounting and reporting standards. We did not pay any fees for such services in Fiscal 2011 or 2010.

Tax Fees are for professional services rendered by RSM McGladrey, Inc., an affiliate of McGladrey, for tax compliance, tax advice and tax planning and include preparation of federal and state income tax returns, and other tax research, consultation, correspondence and advice.

All Other Fees are for services other than the services reported above. We did not pay any fees for such other services in Fiscal 2011 or 2010.

The Audit Committee has concluded the provision of the non-audit services listed above is compatible with maintaining the independence of McGladrey.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

The Audit Committee pre-approves all audit and permissible non-audit services provided by our independent auditors. These services may include audit services, audit-related services, tax services and other services. Pre-approval is generally provided for up to one year and any pre-approval is detailed as to the particular service or category of services and is generally subject to a specific budget. The independent auditors and management are required to periodically report to the Audit Committee regarding the extent of services provided by the independent auditors in accordance with this pre-approval, and the fees for the services performed to date. The Audit Committee may also pre-approve particular services on a case-by-case basis.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)	Documents filed as part of this Report:

(1)	Balance Sheets at September 30, 2011 and September 30, 2010

Statements of Operations for the years ended September 30, 2011 and September 30, 2010

Statements of Members’ Equity for the years ended September 30, 2011 and 2010

Statement of Cash Flows for the year ended September 30, 2011 and September 30, 2010

Notes to Financial Statements

(b)

The following exhibits are filed herewith or incorporated by reference as set forth below:

2	Omitted – Inapplicable.

3(i)	Articles of Organization, as filed with the Iowa Secretary of State on March 28, 2005 (incorporated by reference to Exhibit 3(i) of Registration Statement on Form 10 filed by the Company on January 28, 2008).

4(i)	Third Amended and Restated Operating Agreement dated July 17, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on August 21, 2009).

9	Omitted – Inapplicable.

10.1	Agreement dated October 13, 2006 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.1 of Registration Statement on Form 10/A filed by the Company on October 23, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.2

Executed Steam Service Contract dated January 22, 2007 with MidAmerican Energy Company (incorporated by reference to Exhibit 10.4 of Registration Statement on Form 10/A filed by the Company on October 23, 2008). Portions of the Contract have been omitted pursuant to a request for confidential treatment.

10.3	Assignment of Steam Service Contract dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.5 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.4	Electric Service Contract dated December 15, 2006 with MidAmerican Energy Company (incorporated by reference to Exhibit 10.6 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.5	Assignment of Electric Service Contract dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.7 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.6

Distillers Grain Purchase Agreement dated October 13, 2006 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.8 of Registration Statement on Form 10 filed by the Company on January 28, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment

10.7	Assignment of Distillers Grain Purchase Agreement dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.9 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.8	Grain Feedstock Agency Agreement dated October 13, 2006 with AGRI-Bunge, LLC (incorporated by reference to Exhibit 10.10 of Registration Statement on Form 10 filed by the Company on October 23, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.9	Assignment of Grain Feedstock Agency Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.11 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.10

Agreement between Owner and Design/Builder Based on The Basis of a Stipulated Price dated September 25, 2006 with ICM, Inc. (incorporated by reference to Exhibit 10.12 of Registration Statement on Form 10/A filed by the Company on October 23, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.11

Security Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.15 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.12

Mortgage, Security Agreement Assignment of Rents and Leases and Fixture Filing dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.16 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.13

Environmental Indemnity Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.17 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.14

Convertible Note dated May 2, 2007 in favor of Monumental Life Insurance Company (incorporated by reference to Exhibit 10.18 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.15

Convertible Note dated May 2, 2007 in favor of Metlife Bank, N.A. (incorporated by reference to Exhibit 10.19 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.16

Convertible Note dated May 2, 2007 in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.20 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.17

Convertible Note dated May 2, 2007 in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.21 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.18

Convertible Note dated May 2, 2007 in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.22 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.19

Revolving Line of Credit Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.23 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.20

Revolving Line of Credit Note in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.24 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.21

Revolving Line of Credit Note in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.25 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.22

Term Revolving Note in favor of Metlife Bank, N.A. (incorporated by reference to Exhibit 10.26 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.23

Term Revolving Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.27 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.24

Term Revolving Note in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.28 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.25

Term Revolving Note in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.29 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.26

Lien Subordination Agreement dated May 2, 2007 among Southwest Iowa Renewable Energy, LLC, AgStar Financial Services, PCA and Iowa Department of Economic Development (incorporated by reference to Exhibit 10.30 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.27

Value Added Agricultural Product Marketing Development Grant Agreement dated November 3, 2006 with the United States of America (incorporated by reference to Exhibit 10.31 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.28

Fee Letter dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.33 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.29

Master Contract dated November 21, 2006 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.35 of Registration Statement on Form 10 filed by the Company on January 28, 2008).

10.30

Amended and Restated Disbursing Agreement dated March 7, 2008 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.39 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.31

Allonge to Revolving Line of Credit Note in favor of First National Bank of Omaha dated March 7, 2008 (incorporated by reference to Exhibit 10.43 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.32

Allonge to Revolving Line of Credit Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.44 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.33

Allonge to Revolving Line of Credit Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.45 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.34

Allonge to Convertible Note in favor of First National Bank of Omaha, dated March 7, 2008 (incorporated by reference to Exhibit 10.46 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.35

Allonge to Convertible Note in favor of Metlife Bank, N.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.47 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.36

Allonge to Convertible Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.48 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.37

Allonge to Convertible Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.49 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.38

Allonge to Term Revolving Note in favor of First National Bank of Omaha, dated March 7, 2008 (incorporated by reference to Exhibit 10.50 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.39

Allonge to Term Revolving Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.51 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.40

Allonge to Term Revolving Note in favor of Metlife Bank, N.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.52 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.41

Allonge to Term Revolving Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.53 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.42

Allonge to Convertible Note in favor of Monumental Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.54 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.43

Term Revolving Note in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.55 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.44

Allonge to Term Revolving Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.56 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.45

Convertible Note dated May 2, 2007, in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.57 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.46

Allonge to Convertible Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.58 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.47

Revolving Line of Credit Note in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.59 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.48

Allonge to Revolving Line of Credit Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.60 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.50

Support Services Agreement dated January 30, 2008 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.63 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).

10.51

Amendment No. 01 dated March 9, 2007 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on June 10, 2006).

10.52

Amendment No. 02 dated May 30, 2008 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 10, 2006).

10.53

Base Agreement dated August 27, 2008 between Southwest Iowa Renewable Energy, LLC and Cornerstone Energy, LLC (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 2, 2008).

10.54

Ethanol Purchase Agreement dated December 15, 2008 with Bunge North America, Inc. Portions of the Agreement have been omitted pursuant to a request for confidential treatment (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on December 22, 2008).

10.55

Risk Management Services Agreement dated December 15, 2008 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on December 22, 2008).

10.56

Grain Feedstock Supply Agreement dated December 15, 2008 with AGRI-Bunge, LLC. Portions of the Agreement have been omitted pursuant to a request for confidential treatment (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 22, 2008).

10.57

Subordinated Revolving Credit Note made by Southwest Iowa Renewable Energy, LLC in favor of Bunge N.A. Holdings, Inc. dated effective August 26, 2009 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on September 2, 2009).

10.58

Employment Agreement dated August 27, 2009 between Southwest Iowa Renewable Energy, LLC and Mr. Brian T. Cahill (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on September 2, 2009).

10.59

Amendment to Steam Service Contract by and between Southwest Iowa Renewable Energy, LLC and MidAmerican Energy Company dated effective October 3, 2008. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.61 of Form S-1/A filed by the Company on February 24, 2011)

10.60

Second Amendment to Steam Service Contract by and between Southwest Iowa Renewable Energy, LLC and MidAmerican Energy Company dated effective January 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.62 of Form S-1/A filed by the Company on February 24, 2011)

10.61

Third Amendment to Steam Service Contract by and between Southwest Iowa Renewable Energy, LLC and MidAmerican Energy Company dated effective January 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.63 of Form S-1/A filed by the Company on February 24, 2011)

10.62

Fourth Amendment to Steam Service Contract by and between Southwest Iowa Renewable Energy, LLC and MidAmerican Energy Company dated effective December 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.64 of Form S-1/A filed by the Company on February 24, 2011)

10.63

Separation Agreement and Release of All Claims Agreement between Southwest Iowa Renewable Energy, LLC and Cindy Patterson (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on July 2, 2009).

10.64

Amended and Restated Railcar Sublease Agreement dated March 25, 2009 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on August 14, 2009). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.65

Amended and Restated Credit Agreement by and among Southwest Iowa Renewable Energy, LLC and AgStar Financial Services, PCA, the Banks named therein, dated as of March 31, 2010 (incorporated by reference to Exhibit 99.1 of Form 8-K filed by the Company on April 5, 2010).

10.66

Loan Satisfaction Agreement, by and among Southwest Iowa Renewable Energy, LLC, ICM, Inc., and Commerce Bank, N.A., dated June 17, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 23, 2010).

10.67

Negotiable Subordinated Term Loan Note issued by Southwest Iowa Renewable Energy, LLC in favor of ICM, Inc., dated June 17, 2010 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on June 23, 2010).

10.68

ICM, Inc. Agreement – Equity Matters, by and between ICM, Inc. and Southwest Iowa Renewable Energy, LLC, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on June 23, 2010).

10.69

Subordinated Term Loan Note issued by Southwest Iowa Renewable Energy, LLC in favor of Bunge N.A. Holdings, Inc., dated June 17, 2010 (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on June 23, 2010).

10.70

Bunge Agreement - Equity Matters by and between Southwest Iowa Renewable Energy, LLC and Bunge N.A. Holdings, Inc. date effective August 26, 2009. (incorporated by reference to Exhibit 10.72 of Form S-1/A filed by the Company on February 24, 2011)

10.71

First Amendment to Bunge Agreement – Equity Matters, by and between Bunge N.A. Holdings, Inc. and Southwest Iowa Renewable Energy, LLC, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.5 of Form 8-K filed by the Company on June 23, 2010).

10.72

Subordination Agreement, by and among Bunge N.A. Holdings, Inc., ICM, Inc., and AgStar Financial Services, PCA and acknowledged by Southwest Iowa Renewable Energy, LLC, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.6 of Form 8-K filed by the Company on June 23, 2010).

10.73

Intercreditor Agreement, by and between Bunge N.A. Holdings, Inc. and ICM, Inc. and acknowledged by Southwest Iowa Renewable Energy, LLC, dated as of June 17, 2010. (incorporated by reference to Exhibit 10.7 of Form 8-K filed by the Company on June 23, 2010).

10.74

Southwest Iowa Renewable Energy Equity Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 6, 2010).

10.75

Joint Defense Agreement between ICM, Inc. and Southwest Iowa Renewable Energy, LLC dated July 13, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 16, 2010).

10.76

Tricanter Purchase and Installation Agreement by and between ICM, Inc. and Southwest Iowa Renewable Energy, LLC dated August 25, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K/A filed by the Company on January 12, 2011). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.77

Corn Oil Agency Agreement by and between Bunge North America, Inc. and Southwest Iowa Renewable Energy, LLC effective as of November 12, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on November 30, 2010). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.

10.78

Amendment to Amended and Restated Credit Agreement by and among Southwest Iowa Renewable Energy, LLC and AgStar Financial Services, PCA and the Banks named therein, effective as of March 31, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 5, 2011).

10.79

First Amendment to Ethanol Purchase Agreement by and between Bunge North America, Inc. and Southwest Iowa Renewable Energy, LLC dated March 31, 2011 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on April 5, 2011). Portions of this agreement have been omitted pursuant to a request for confidential treatment.

10.80

Second Amendment to Amended and Restated Credit Agreement by and among the Company and AgStar Financial Services, PCA and the Banks named therein, effective as of June 30, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 6, 2011).

10.81

Form of Trustee Joinder to Intercreditor Agreement by Treynor State Bank dated ___________, 2011. (incorporated by reference to Exhibit 10.80 of Amendment No. 2 to Form S-1 filed by the Company on October 19, 2011)

10.82

Form of Trustee Joinder to Subordination Agreement by Treynor State Bank dated ___________, 2011. (incorporated by reference to Exhibit 10.81 of Amendment No. 2 to Form S-1 filed by the Company on October 19, 2011)

11	Omitted – Inapplicable.

12	Omitted – Inapplicable.

13	Omitted – Inapplicable.

14	Omitted – Inapplicable.

16	Omitted – Inapplicable.

18	Omitted – Inapplicable.

21	Omitted – Inapplicable.

22	Omitted – Inapplicable.

23	Omitted – Inapplicable.

24	Omitted – Inapplicable.

31.1	Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by Chief Executive Officer.

31.2	Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by Principal Financial Officer.

32.1	Certification (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Chief Executive Officer.

32.2	Certification (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Principal Financial Officer.

99	Omitted – Inapplicable.

100	Omitted – Inapplicable.

SIGNATURES

In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHWEST IOWA RENEWABLE ENERGY, LLC

Date: November 22, 2011	/s/ Brian T. Cahill
	Brian T. Cahill, President and Chief Executive Officer

Date: November 22, 2011	/s/ Karen L. Kroymann
	Karen L. Kroymann, Controller and Principal Financial Officer

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

Signature	Date

/s/ Karol D. King	November 22, 2011
Karol D. King, Chairman of the Board

/s/ Theodore V. Bauer	November 22, 2011
Theodore V. Bauer, Director

/s/ Hubert M. Houser	November 22, 2011
Hubert M. Houser, Director

/s/ Michael K. Guttau	November 22, 2011
Michael K. Guttau, Director

/s/ Eric L. Hakmiller	November 22, 2011
Eric L. Hakmiller, Director

/s/ Tom J. Schmitt	November 22, 2011
Tom J. Schmitt, Director

/s/ Gregory P. Krissek	November 22, 2011
Gregory P. Krissek, Director

Attached files

SOUTHWEST IOWA RENEWABLE ENERGY, LLC Reports

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