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 December 31, 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 333-130343
NEDAK ETHANOL, LLC
(Exact name of registrant as specified in its charter)
Nebraska			20-0568230
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)
87590 Hillcrest Road, P.O. Box 391, Atkinson, Nebraska			68713
(Address of principal executive offices)			(Zip Code)
Registrant’s telephone number (402) 925-5570
Securities registered under Section 12(b) of the Exchange Act:			None.
Securities registered under Section 12(g) of the Exchange Act:

Common Membership Units

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

Check 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 £

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

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-K 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 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

As of December 31, 2011, the aggregate market value of the Common Membership Units held by non-affiliates (computed by reference to the most recent offering price of such Common Membership Units) was $48,360,000.

As of March 15, 2012, the Company had 305.5 Class A Preferred Membership Units, 1,052.5 Class B Preferred Membership Units and 5,233 Common Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE—NEDAK 2011 Annual Report, which is attached hereto as Exhibit 13.1 and Proxy Statement relating to the annual meeting of unit holders to be held on June 20, 2012.

TABLE OF CONTENTS

Certain information required to be included in this Form 10-K is incorporated by reference to information contained in (i) NEDAK’s Annual Report to unit holders for its fiscal year ended December 31, 2011 filed as an exhibit to this report on Form 10-K (the “2011 Annual Report”) and (ii) NEDAK’s Proxy Statement relating to its fiscal year ended on December 31, 2011 for the annual meeting to be held on June 20, 2012 (the “2012 Proxy Statement”).  The 2012 Proxy Statement has not yet been filed by NEDAK, but will be filed within 120 days of the fiscal year ended on December 31, 2011.  All sections of the 2011 Annual Report and 2012 Proxy Statement that are not incorporated herein by reference are not required to be included in this Form 10-K and therefore should not be considered a part hereof.

		Form 10-K Page	2011 Annual Report Page
	Part I
Item 1	Business	2
Item 1A	Risk Factors	17
Item 2	Properties	33
Item 3	Legal Proceedings	34
Item 4	Mine Safety Disclosures	35
	Part II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6	Selected Financial Data	36	F-1
Item 7	Management’s Discussion and Analysis of Financial Conditions and Results of Operation	36	7
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8	Financial Statements and Supplementary Data	36
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A	Controls and Procedures	36
Item 9B	Other Information	37
	Part III
Item 10	Directors, Executive Officers and Corporate Governance	37
Item 11	Executive Compensation	37
Item 12	Security Ownership of Certain Beneficial Owners and Management	37
Item 13	Certain Relationships and Related Transactions, and Director Independence	37
Item 14	Principal Accountant Fees and Services	37
	Part IV
Item 15	Exhibits and Financial Statement Schedules	38
Signatures		42

Forward Looking Statements

This report contains forward-looking statements that involve future events, our future performance and our expected future operations and actions.  In some cases you can identify  forward-looking  statements  by the use of words such as “may,” “should,” “anticipate,” “believe,” “expect,” “plan,” “future,” “intend,” “could,” “estimate,” “predict,” “hope,” “potential,” “continue,” or the negative of these terms or other similar expressions.  These forward-looking statements are only our predictions and involve numerous assumptions, risks and uncertainties.  Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the following factors:

· Overcapacity in the ethanol industry;

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

· Availability and costs of products and raw materials, particularly corn and natural gas;

· Our ability to obtain the financing necessary to operate our plant and our ability to meet the associated covenants;

· Changes in our business strategy, capital improvements or development plans;

· Changes in our marketing, procurement and transportation agreements;

· Mechanical difficulties in operation of the plant;

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

· Our ability to hire and retain key employees for the operation of the plant;

· Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agricultural, oil or automobile industries;

· Changes in the weather and economic conditions impacting the availability and price of corn and natural gas;

· 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; and competition from alternative fuel additives;

· Lack of transport, storage and blending infrastructure preventing ethanol from reaching high demand markets;

· Our ability to generate free cash flow to invest in our business and service our debt;

· Volatile commodity and financial markets;

· Changes in interest rates and lending conditions; and

· Results of our hedging strategies.

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”).

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AVAILABLE INFORMATION

Our annual reports are available free of charge on our website at www.nedakethanol.com as soon as reasonably practicable after we file or furnish such information electronically with the Securities and Exchange Commission (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.  Our other reports, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available as discussed in the paragraph below.

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 www.sec.gov.

PART I

Item 1.    Business.

General

NEDAK Ethanol, LLC (the “Company,” or “us,” or “we”), a Nebraska limited liability company, was organized in 2003 and built a plant to produce ethanol and distillers grains on our 73-acre site located near Atkinson, Nebraska.  Our principal business office is located at 87590 Hillcrest Road, Atkinson, Nebraska 68713.  We completed full startup of the ethanol facility in June 2009 and have the annual capacity to process approximately 17 million bushels of corn, through a dry milling process, into approximately 44 million gallons of ethanol per year (mgy).  We also produce approximately 340,000 tons of wet distillers grains (“WDG ”) annually.  We are currently operating at approximately 117%capacity producing approximately 52 million gallons of ethanol per year and approximately 367,000 tons of WDG consuming approximately 18.9 million bushels of corn.

Business Developments

Asset Management Agreement

On December 31, 2011, the Company and Tenaska BioFuels, LLC (“Tenaska”) entered into an Asset Management Agreement, which became effective January 11, 2012 (the “AMA Effective Date”) and has an initial term of seven years. As of December 31, 2011, Tenaska is considered a related party.  The Asset Management Agreement provides that we will provide processing services to Tenaska for the conversion of grains, natural gas and denaturant (the “Feedstocks”) into ethanol and distillers grains (the “Finished Products”).  Tenaska will finance and own all Feedstocks, including the corn inventories, from the time of purchase through the delivery and sale of the Finished Products.  In particular, Tenaska will be responsible for originating all corn used and for paying corn producers and commercial grain merchants providing corn to our facility, as well as providing all necessary working capital for corn inventories and forward contracts.  Tenaska will also originate, provide credit support and pay for all denaturant and natural gas delivered to our facility, as well as all management services required for delivery of the natural gas under our natural gas transportation contract.

Tenaska will own and be responsible for selling all ethanol produced at our facility, including prospecting, contracting and approving credit for all ethanol sales.  Tenaska will own 100% of the distillers grains produced at our facility and, in coordination with the Company, will direct all activities related to sales of distillers grains, including extending credit to third party purchasers under the same terms and conditions as other Tenaska customers.  Tenaska shall provide all transportation of all Finished Products from our facility (not including transportation from our ethanol plant to our rail car loading facility.)

All inputs other than corn, denaturant and natural gas incurred by us for plant operations including, utilities, labor, debt service, insurance, taxes, chemicals, and enzymes, as well as transportation expenses for natural gas, will be provided and paid for by us.  We have agreed to meet or exceed certain guaranteed processing yields and that the inished Products meet certain agreed upon quality specifications.  The corn provided by Tenaska must also meet

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certain quality specifications (subject to agreed upon quality discounts) and we, at our sole discretion, may direct Tenaska not to procure corn that does not meet the specifications.

In return for providing processing services, we will be paid a processing fee based on a crush margin calculation and Tenaska will retain and deduct a fee calculated based on a percentage that corresponds to specified crush margins (the “Tenaska Fee”). The processing fee we receive will be based upon the actual cost of Feedstocks and the revenues received from ethanol and distillers grains, which fee will vary depending on the difference between costs and revenues.  This “net back” fee structure will provide net financial results very similar to when we were operating under earlier marketing agreements. 

Tenaska and the Company have drafted a risk policy to provide guidelines applicable to forward contracts for the purchase of Feedstocks and sale of Finished Products, as well as guidelines for related hedging activities (the “AMA Risk Policy”).  Tenaska will provide the working capital required for all forward contracts and related hedging activities.

 On the AMA Effective Date, we transferred to Tenaska all inventories of Feedstocks and Finished Products (the “Inventories”) and Tenaska paid us $5,326,980.78 for such Inventories, which was based on the prevailing rates in effect on the AMA Effective Date.  As a result, the Company no longer owns any Feedstocks, work in process or Finished Products at our facility.  Tenaska is the exclusive asset manager for us and we no longer process corn into ethanol for any party other than Tenaska during the term of the Asset Management Agreement.   We have also agreed to operate and maintain our facilities in accordance with good operating practices, to maintain agreed upon insurance, to obtain and maintain all necessary government approvals and otherwise comply with applicable laws, and to provide Tenaska with certain periodic reports.

The Asset Management Agreement between Tenaska and the Company constitutes a significant change in the Company’s business model.   The Company no longer owns any of the raw materials, works in process or Finished Products and we no longer process corn into ethanol for our own account.  Under the Asset Management Agreement, Tenaska assumed greater responsibility for the risks associated with our business and as a result, Tenaska has the ability to receive more of the economic rewards of our business operations through the retention and deduction of the Tenaska Fee.   The Asset Management Agreement also replaced or significantly altered the relationships we had in place with Tenaska for the year ended December 31, 2011.  The Company cannot predict at this time the impact of the Asset Management Agreement on its results of operations.

Our Ethanol Plant

Our plant is comprised primarily of a raw material storage and processing area, a fermentation area comprised principally of fermentation tanks, a finished product storage and distillation area, and a drying unit for processing modified wet distillers grains.  We also utilize a transload facility near O’Neill, Nebraska, approximately 16 miles from our plant, where ethanol is held in a storage tank or railcars pending rail shipment.

Principal Products

Our plant uses a dry milling process to produce fuel-grade ethanol as its main product, in addition to the co-product distillers grains.

Ethanol

Ethanol is a chemical produced by the fermentation of sugars found in grains and other biomass. Ethanol can be produced from a number of different types of grains, such as wheat and sorghum, as well as from agricultural waste products such as sugar, rice hulls, cheese whey, potato waste, brewery and beverage wastes and forestry and paper wastes. However, approximately 90 percent of ethanol in the United States today is produced from corn because corn produces large quantities of carbohydrates, which convert into glucose more easily than other kinds of biomass.

Approximately 84% of our total revenue was derived from the sale of ethanol during our fiscal year ended December 31, 2011.  Ethanol sales accounted for approximately 83% of our total revenue for our fiscal year ended December 31, 2010.

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Under the Asset Management Agreement, as of the AMA Effective Date, Tenaska owns all ethanol we produce at our facility.

Ethanol Supply

Annual U.S. ethanol production capacity has continually grown since 1980.  According to the Renewable Fuels Association (the “RFA”), in 1992 ethanol production surpassed one billion gallons in the U. S., and production has steadily grown since then.  In 2002, ethanol capacity in the U.S. surpassed two billion gallons, by 2007, capacity further increased to 6.5 billion gallons and by the end of 2009 capacity topped 13 billion gallons.  However, because of economic difficulties in both the ethanol industry and the world economy, the temporary shutdown of significant portions of that capacity limited production in 2009 to approximately ten billion gallons.  The Renewable Fuels Standard (“RFS”), which was created by the Energy Policy Act of 2005 (the “2005 Act”) established the RFS standard for blending of renewable fuels into automobile fuel in 2011 at 13.95 billion gallons, of which 2.56 billion gallons must come from non-corn based ethanol, leaving a maximum requirement of 11.4 billion gallons of corn based ethanol to be blended in 2011.  The RFS requirement increases incrementally each year until the United States is required to use 36 billion gallons of renewable fuels by 2022. Starting in 2009, the RFS required that a portion of the RFS must be met by certain “advanced” renewable fuels. These advanced renewable fuels include ethanol that is not made from corn, such as cellulosic ethanol and biomass based biodiesel. The use of these advanced renewable fuels increases each year as a percentage of the total renewable fuels required to be used in the United States.

As of December 2011, the RFA reported that there were 209 ethanol plants in operation in the United States with the capacity to produce 14.7 billion gallons of ethanol annually.  An additional nine plants are under construction or expanding, which could add an additional estimated 0.26 billion gallons of annual production capacity.  The RFS for 2012 is approximately 15.2 billion gallons, of which corn based ethanol can be used to satisfy approximately 13.2 billion gallons. Current ethanol production capacity exceeds the 2012 RFS requirement which can be satisfied by corn based ethanol.

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

Most ethanol that is used in the United States is sold in a blend called E10. E10 is a blend of 10% ethanol and 90% gasoline. E10 is approved for use in all standard vehicles. Estimates indicate that gasoline demand in the United States is approximately 135 billion gallons per year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.5 billion gallons per year. This is commonly referred to as the “blending wall,” which represents a theoretical limit where more ethanol annot be blended into the national gasoline pool. This is a theoretical limit because it is believed that it would not be possible to blend ethanol into every gallon of gasoline that is being used in the United States and it discounts the possibility of additional ethanol used in higher percentage blends such as E85 used in flex fuel vehicles. Many in the ethanol industry believe that we reached this blending wall in 2011, since the RFS requirement for 2011 is 14 billion gallons, much of which will come from ethanol. The RFS requires that 36 billion gallons of renewable fuels must be

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used each year by 2022, which equates to approximately 27% renewable fuels used per gallon of gasoline sold. In order to meet the RFS mandate and expand demand for ethanol, management believes higher percentage blends of ethanol must be utilized in standard vehicles.

Distillers Grains

The chief co-product of the ethanol production process is distillers grains, which are the residues that remain after high quality cereal grains have been fermented by yeast. Dry mill ethanol processing creates three primary forms of distillers grains: wet distillers grains, modified wet distillers grains, and dried distillers grains with solubles. Wet distillers grains are processed corn mash that contains a substantial amount of moisture. In the fermentation process, the remaining nutrients undergo a three-fold concentration to yield wet distillers grains to which is added evaporator syrup to create wet distillers grains with solubles, or WDG.  WDG has a short shelf life and is therefore generally marketed primarily to the dairy, beef, sheep, swine and poultry industries within the immediate vicinity of the respective ethanol plant. Modified wet distillers grains are similar to wet distillers grains except it has been partially dried and contains less moisture. Modified wet distillers grains has a shelf life of a maximum of fourteen days, contains less water to transport, is more easily adaptable to some feeding systems, and is sold to both local and regional markets, primarily for both beef and dairy animals. Dried distillers grains with solubles are corn mash that has been dried to approximately 10% moisture. It has an almost indefinite shelf life and may be sold and shipped to any market and to almost all types of livestock.

 Although we have drying capacity to dry up to 80% of our distillers grains volume, we expect to be able to distribute nearly 100% of our output as WDG into the local cattle feed market.It is expected that in the future running the dryer and production of dry distillers grains will be incidental only, with the intent to influence the economies of WDG marketing.

Approximately 16% of our total revenue was derived from the sale of distillers grains during our fiscal year ended December 31, 2011.  Distillers grain sales accounted for approximately 13% of our total revenue for our fiscal year ended December 31, 2010.

Under the Asset Management Agreement, as of the AMA Effective Date, Tenaska owns all distillers grains we produce at our facility and in future periods we will receive a processing fee in accordance with the terms of the Asset Management Agreement.

Distribution and Marketing of Principal Products

Ethanol

Through December 31, 2010, we sold our ethanol through an Ethanol Marketing Agreement with Eco-Energy, Inc. of Franklin, Tennessee (“Eco”), under which Eco purchased all of our ethanol and resold it.  We paid Eco a fee of $0.01 per gallon of ethanol purchased.

During the fiscal year ended December 31, 2011, we sold our ethanol through a non-binding arrangement with Tenaska whereby Tenaska assisted us in locating buyers for our ethanol on the spot market.  We paid Tenaska a fee of $0.02 per gallon of ethanol sold.  This arrangement was replaced with the Asset Management Agreement we entered into with Tenaska on December 31, 2011.  Under the Asset Management Agreement, Tenaska owns and is responsible for selling all ethanol produced at our facility, including prospecting, contracting and approving credit for all ethanol sales.  We are not authorized to enter into sales of ethanol we produce for our own account.  Tenaska will be required to market and sell the ethanol we produce at our facility consistent with the then current AMA Risk Policy to maximize the net proceeds received from ethanol sales.

Distillers Grains

Through February 28, 2011, we sold our WDG through a Marketing Agreement with Distillers Grain Services LLC (“Distillers”), under which Distillers had the exclusive right to purchase from us, and was obligated to market, all distillers grains produced by us at our plant.  Under the Marketing Agreement, we paid Distillers a marketing fee

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of $1.50 per ton of distillers grains sold at $50 per ton or less, and 3.0% of distillers grains tonnage sold over $50 a ton.

From February 28, 2011 through the AMA Effective Date, we marketed our WDG directly to the feeders and incurred no marketing fees.

Under the Asset Management Agreement, Tenaska owns 100% of the distillers grains produced at our facility and, in coordination with the Company, will direct all activities related to sales of distillers grains, including extending credit to third party purchasers under the same terms and conditions as other Tenaska customers. We are not authorized to enter into any distillers grain sales transactions.  Tenaska is required to market and sell the distillers grains we produce at our facility consistent with the then current AMA Risk Policy to maximize the net proceeds from distillers grains taking into account energy and transportation costs.

Principal Product Markets

As described above in “Distribution and Marketing of Principal Products”, Tenaska now owns, markets and distributes all of the ethanol and distillers grains we produce at our facility.  Tenaska will make all decisions with regard to where our products are marketed; provided, such decisions are consistent with the then current AMA Risk Policy. Our ethanol and distillers grains have historically been sold into markets throughout the United States.  Our ethanol is shipped primarily by truck to our transload facility in O’Neill, Nebraska, and then by rail from our transload facility to the customer. Our target markets for ethanol includes local, regional (Nebraska, South Dakota, Kansas, Missouri, Indiana, Colorado, Minnesota, Illinois, Wisconsin and Iowa) and national markets.

Distillers grains are marketed primarily as animal feed for beef and dairy cattle, poultry and hogs.  However, WDG typically has a significantly shorter shelf life than dried distillers grains which results in a much smaller market based on delivery distance and therefore, makes the timing of its sale critical. Further, because of its moisture content, WDG is heavier and more difficult to handle. Customers must be close enough to justify the additional handling and shipping costs. As a result, we have historically sold distillers grains principally to local feedlots and livestock operations.  Various factors affect the price of distillers grains, including, among others, the price of corn, soybean meal and other alternative feed products, the performance or value of distillers grains in a particular feed market, and the supply and demand within the market. Like other commodities, the price of distillers grains can fluctuate significantly.

We do not anticipate any significant change to the market for the ethanol and distillers grains we produce as we implement operations under the Asset Management Agreement or that Tenaska will pursue markets substantially different than those we have historically targeted.  We anticipate Tenaska will explore all markets for the products we produce, which could include potential export markets. However, due to high transportation costs, and the fact that we are not located near a major international shipping port, we expect our products to continue to be marketed primarily domestically.

Current Markets and Future Demand

Federal Energy Policies

The 2005 Act eliminated the oxygen content requirement in reformulated gasoline, making use of oxygenates like ethanol optional for the petroleum industry in meeting clean air standards, and established a larger demand for ethanol, requiring an increase in production of approximately 700 million gallons per year over several years.

The Energy Independence and Security Act of 2007 (the “2007 Act”) modified the 2005 Act which created the RFS. The RFS is a national program that imposes requirements with respect to the amount of renewable fuel produced and used, and applies to refineries, blenders, distributors and importers, and does not restrict the geographic areas in which renewable fuels may be used.  Among other things, the 2007 Act  increased the RFS to require that a larger amount of renewable fuels (from 4.5 billion gallons in 2007 to 36 billion gallons by 2022) be used in the fuel refining industry, including 14 billion gallons of renewable fuels in 2011, and increased the RFS for renewable fuels to 15 billion gallons by 2015, while determining that the balance of the RFS production will come from other types of fuels, such as advanced biofuel, cellulosic biofuel and biomass-based diesel.

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The federal government encourages ethanol production primarily by taxing it at a lower rate.  The Volumetric Ethanol Excise Tax Credit (“VEETC”) is a tax credit of $0.45 per gallon of ethanol. Gasoline distributors apply for this credit, however this tax credit expired on December 31, 2011.   As of the date of this Report on Form 10-K, it is unknown how the expiration of the VEETC will affect our operation or future results.  We believe that the VEETC primarily benefited ethanol blenders, as opposed to producers, and as a result, the failure to extend the VEETC will have a negative impact on ethanol demand, but we do not anticipate any such negative impact will be material to us, and may be offset by corresponding political benefits.  We expect the RFS to continue to drive demand for ethanol.

Changes in Corporate Average Fuel Economy (“CAFE”) standards have also benefited the ethanol industry by encouraging use of E85 fuel products. CAFE provides an effective 54% efficiency bonus to flexible-fuel vehicles running on E85. This variance encourages auto manufacturers to build more flexible-fuel models, particularly in trucks and sport utility vehicles that are otherwise unlikely to meet CAFE standards.

In response to a request by Growth Energy, an ethanol industry trade association, under section 211(f)(4) of the Clean Air Act, the Environmental Protection Agency (“EPA”) has granted a partial waiver to allow fuel and fuel additive manufacturers to introduce gasoline that contains more than 10 volume percent (vol%) ethanol and up to 15 vol% ethanol (“E15”) for use in model year (“MY”) 2001 and newer light-duty motor vehicles, subject to several conditions. On October 13, 2010, the EPA granted a partial waiver for E15 for use in MY2007 and newer “light-duty vehicles.”  “Light-duty vehicles” include cars, light-duty trucks and medium-duty passenger vehicles. On January 21, 2011, the EPA granted a partial waiver for E15 for use in MY2001-2006 “light-duty vehicles.” These decisions were based on test results provided by the U.S. Department of Energy (“DOE”) and other information regarding the potential effect of E15 on vehicle emissions. Taken together, the two actions allow, but do not require, E15 to be introduced into commerce for use in MY2001 and newer light-duty vehicles if conditions for mitigating, misfueling and ensuring fuel quality are met. The EPA is in the process of completing work on regulations that would provide a more practical means of meeting the conditions.

State Incentives

Some states also provide various tax and production incentives, including reduced tax rates of state motor fuel tax, that combined with the federal incentive provide incentive for marketers to buy ethanol products.  Several state programs require gasoline to contain a specified percentage of ethanol.  The prospect of more states adopting a local requirement that either directly or indirectly requires ethanol is uncertain—primarily because of a decrease in political support of the production of ethanol.

Environmental and Other Regulation

Our ethanol production is subject to environmental and other regulations. We obtained environmental permits to construct and operate our ethanol plant.

Ethanol production involves the emission of various airborne pollutants, including particulate, carbon dioxide, oxides of nitrogen, hazardous air pollutants and volatile organic compounds. In 2007, the U.S. Supreme Court 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. On February 3, 2010, the EPA released its final regulations on the Renewable Fuels Standard, or RFS 2. We believe these final regulations grandfather our plant at its current operating capacity, though expansion of our plant will need to meet a threshold of a 20% reduction in green house gas (“GHG”) emissions from a baseline measurement to produce ethanol eligible for the RFS 2 mandate. In order to expand capacity at our plant, we may be required to obtain additional permits, install advanced technology such as corn oil extraction, or reduce drying of certain amounts of distillers grains.

Separately, the California Air Resources Board has adopted a Low Carbon Fuel Standard requiring a 10% reduction in GHG emissions from transportation fuels by 2020. An Indirect Land Use Change component is included in this lifecycle GHG emissions calculation, though this standard is being challenged by numerous lawsuits.

Part of our business is regulated by environmental laws and regulations governing the labeling, use, storage, discharge and disposal of hazardous materials. Other examples of government policies that can have an impact on our business include tariffs, duties, subsidies, import and export restrictions and outright embargos.

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Clean Air Programs

Ethanol has been used primarily as a gasoline extender and is added in 10 percent volume blends to extend fuel supplies. It also is used as an octane enhancer due to the fact that 10 percent ethanol blends add three points of octane. In addition to a demand as a gasoline additive for reasons of supply and octane, ethanol has an established value as an oxygenate. Provisions in the Clean Air Act Amendments of 1990 resulted in the establishment of two fuel formulations that changed the entire marketing outlook for ethanol. The first of these is designed to combat carbon monoxide and requires that wintertime fuels in certain areas contain an oxygen content that could only be met by ethanol or an MTBE.

The second key program utilizing oxygenates deals with ozone, or summertime smog, and is the Federal Reformulated Gasoline Program. Nine U.S. cities, by federal law, and more than a dozen others, by local ordinance, have elected to use the RFG recipe for gasoline that controls a number of fuel properties such as vapor pressure and toxic content. Importantly, this formulation also requires a minimum oxygen content which could be met by using ethanol.

E10 Plus

Unleaded gasoline with a 10% blend of ethanol accounts for the majority of ethanol consumption in the U.S.  In 2008, production capacity in the U.S. surpassed the demand for ethanol and is expected to remain in surplus until the maximum blend for all highway gasoline powered vehicles is raised.  The United States Department of Agriculture (“USDA”) recently published comments discussing the potential for increasing the maximum ethanol blend as high as 20%.  As noted above, the EPA has granted partial waivers to the 10% limit that allow distribution of E15 and is in the process of completing work on regulations that would provide more practical guidance.

E85

Demand for ethanol has been affected by the increased consumption of E85 fuel. E85 fuel is a blend of 85% ethanol and 15% gasoline. According to the Energy Information Administration, E85 consumption is projected to increase from a national total of 11 million gallons in 2003 to 47 million gallons in 2025. E85 can be used as an aviation fuel, as reported by the National Corn Growers Association, and as a hydrogen source for fuel cells. While the number of vehicles able to use E85 and the number of suppliers able to deliver it has increased each year, the consumption of ethanol in this form remains a relatively small percentage of the total demand for ethanol.  In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it and the consumer needs to perceive an economic benefit from using 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.

Cellulosic Ethanol

Due to the volatile corn prices, discussion of cellulose-based ethanol has increased over the last few years. 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.  This could decrease demand for our product or result in competitive disadvantages for our ethanol production process.

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Sources and Availability of Raw Materials

Corn Requirements

Our plant needs approximately 18 million bushels of corn per year, or approximately 52,000 bushels per day, as the feedstock for its dry milling process.  The grain supply for our plant has historically been obtained primarily from local markets.  During the fiscal year ended December 31, 2011, we utilized the services of a third party agent on an at-will basis for nearly all contracts with local producers for the delivery of corn and paid the agent a service fee of $0.04 per bushel of grain delivered (plus $0.02 per bushel to reduce balance payable for fees not paid during the first two years of plant start-up pursuant to agreement with the third party agent), and we executed contracts directly with producers for some of our corn.  We also purchased more corn through an arrangement with Tenaska.  Under this arrangement, Tenaska sold us corn netted against their receivable for marketed ethanol.  This arrangement ceased when the Asset Management Agreement with Tenaska became effective on January 12, 2012.

Under the Asset Management Agreement, Tenaska is responsible for contracting with third parties to provide sufficient corn to our facility as needed for production which corn must meet applicable quality specifications.  We are not authorized to purchase corn on behalf of Tenaska; however, in the event that we determine that specifications of corn proposed by Tenaska are too low, we have the right, in our sole discretion, to instruct Tenaska not to procure that corn for processing at our facility.  Tenaska is also responsible for procuring all transportation related to transporting corn to our plant.

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.  As of March 2, 2012, spot price for corn on the Chicago Board of Trade (“CBOT”) was $6.59 per bushel.

On January 12, 2012, the United States Department of Agriculture (“USDA”) released its Crop Production report, which estimated the 2011 grain corn crop at 12.36 billion bushels. The January 12, 2012 estimate of the 2011 corn crop is approximately 1.0% below the USDA's estimate of the 2010 corn crop of 12.45 billion bushels. Corn prices can be volatile as a result of a number of factors, the most important of which are weather, current and anticipated stocks, domestic and export prices and supports and the government's current and anticipated agricultural policy. The price of corn was volatile during our 2011 fiscal year and we anticipate that it will continue to be volatile in the future. Increases in the price of corn significantly increase our cost of goods sold. If these increases in cost of goods sold are not offset by corresponding increases in the prices Tenaska receives from the sale of the products we produce, these increases in cost of goods sold can have a significant negative impact on our financial performance.

Although the area surrounding our plant produces a significant amount of corn and we do not anticipate Tenaska will encounter problems sourcing corn, a shortage of corn could develop, particularly if there were an extended drought or other production problems.  Poor weather can be a major factor in increasing corn prices. Tenaska can mitigate fluctuations in the corn and ethanol markets by locking in a favorable margin through the use of hedging activities, including forward contracts. We recognize that Tenaska may not always have the opportunity to lock in a favorable margin and that our plant's profitability may be negatively impacted during periods of high grain prices.

Energy Requirements

The production of ethanol is a very energy intensive process which uses significant amounts of electricity and natural gas.  Water supply and quality are also important considerations.  Presently, about 40,000 BTUs of energy are required to produce a gallon of ethanol.

Natural Gas

Our plant requires a natural gas supply of approximately 1.1 to 1.7 billion cubic feet per year.

Supply.  During the year ended December 31, 2011, we had an arrangement with Tenaska pursuant to which Tenaska acted as a purchasing agent for us in connection with obtaining our required supply of natural gas.  Under

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this arrangement, we were responsible for the costs associated with the purchase of the natural gas.  Under the Asset Management Agreement, Tenaska is required to purchase an appropriate amount of natural gas to be delivered to our plant sufficient to sustain the conversion of corn, natural gas and natural gasoline into ethanol and distillers grains.  In connection with the transfer of responsibility for procuring natural gas for our plant to Tenaska, we assigned our transportation capacity on the Kinder Morgan Pipeline to Tenaska.

Transportation. We receive distribution services for all of our natural gas from Source Gas.  We entered into a Negotiated Rate Agreement for Distribution Transportation Service (“Negotiated Rate Agreement”) with Source Gas which establishes the minimum and maximum quantities of natural gas to be delivered to us under a separate Transportation Service Agreement.  We agreed to pay Source Gas a distribution fee per therm delivered to us for the first five years of the Negotiated Rate Agreement, and such rate automatically increases thereafter according to a formula based upon the GDP Implicit Price Deflator published by the U.S. Department of Commerce.

To access sufficient supplies of natural gas to operate the plant, a connection to a distribution pipeline approximately six miles from our site was constructed.  We have entered into two Firm Transportation Service Agreements with Kinder Morgan Interstate Gas Transmission LLC under which we have agreed to pay monthly reservation fees for guaranteed interstate pipeline transportation.  In conjunction with the second Firm Transportation Agreement, we have agreed to pay a monthly Facility Reimbursement Fee in addition to the normal reservation fee.

 Although Tenaska is responsible for procuring the natural gas supply for our plant, we continue to be responsible for all costs associated with natural gas transportation, including, but not limited to, the costs associated with the Negotiated Rate Agreement and the Firm Transportation Service Agreements as well as any other reservation charges, fuel charges and injection and withdrawal charges assessed by the transportation provider.

Electricity

Our plant requires a continuous supply of 1.3 kilovolt-ampere, 12,400 volt electrical energy, which we purchase from the Nebraska Public Power District.  We continue to be responsible for purchasing a sufficient supply of energy under the Asset Management Agreement to power the operation of our facility and the processing of corn, natural gas and natural gasoline into ethanol.

Water

Our plant requires approximately 400 gallons of fresh water per minute.  While much of the water used in an ethanol plant is recycled back into the process, boiler makeup water and cooling tower water must be fresh.  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 can be recycled back into the process, which will minimizes the effluent, which can have the long-term effect of lowering waste water treatment costs.  Many new plants today are zero or near zero effluent facilities.  We anticipate that there should be no more than 40 gallons per minute of non-contaminated water required.  The water from the cooling tower and the boiler blowdown water are put in a pond and released to the environment either through evaporation, or by discharge into the Elkhorn River pursuant to our discharge permit.  Our water requirements are supplied through wells, though allocations of future water resources for the Upper Elkhorn District will be set by the Upper Elkhorn Natural Resources District (“NRD”).

Risk Management

Because our financial performance has historically been based on commodity prices, and will continue to be based on commodity prices under the Asset Management Agreement, one of the most important facets of our industry is risk management, focused on maintaining balance in the sale of ethanol and the purchase of corn.  Historically, and to the extent we had available working capital, we used commodity forward-contract marketing.  The preferred position was to purchase corn and sell a matching amount of ethanol for future delivery when the

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margins are profitable.  When corn was forward-contracted and ethanol cannot be sold to balance, we would face the risk that corn prices would fall, followed by ethanol, leaving the plant with excessive expenses in corn purchases, pushing the cost of ethanol above the market price.  Even if the decision was made to shut down the plant, rather than operate at a loss, the purchase and resale of that corn would also result in a loss.  In the past, because of our limited working capital, we were limited to using nearby spot purchases of corn and sales of ethanol for prompt delivery.

As part of the Asset Management Agreement with Tenaska, all transactions for the purchase of corn, natural gasoline and natural gas will be balanced with transactions for the sale of equivalent amounts of distillers grains and ethanol in accordance with yield targets that are mutually agreed upon by the Company and Tenaska.  If the purchases and sales are not balanced, Tenaska will enter into financial derivative contracts to hedge the corresponding exposures; however, Tenaska will not engage in speculation with respect to such hedging transactions.  The Company and Tenaska have developed the AMA Risk Policy to provide guidelines for the volume and tenor of any hedging transactions.  Tenaska is solely responsible for providing any required credit support and/or margin to any applicable trading exchange or counterparty for such hedging transactions.  Realized gains and losses from any derivatives entered into by Tenaska under the AMA will impact the net processing fee we receive from Tenaska.

Tenaska will provide the working capital necessary for forward contracting and hedging, which will allow us to take advantage of the periodic short windows of opportunity that present themselves in the ethanol commodity marketplace when there is profitable margin to capture between the cost of corn and the price of ethanol.   In 2010 and 2011, other ethanol producers have proven profitable in the marketplace by performing the risk management programs that we will now be able to put into place. Of course, there is no assurance that the marketplace will provide similar opportunities or that we will actually generate profits in the future, but we are now in a position to do so if the opportunities present themselves.

 Ethanol Competition

General Competition

We are in direct competition with numerous ethanol producers, many of whom have greater resources than we do. While management believes we are a lower cost producer of ethanol, larger ethanol producers may be able to take advantages of economies of scale due to their larger size and increased bargaining power with both customers and raw material suppliers. 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.

Following the significant growth in the ethanol industry during 2005 and 2006, the ethanol industry has grown at a much slower pace. As of January 3, 2012, the RFA estimates that there are 209 ethanol production facilities in the United States with capacity to produce approximately 14.7 billion gallons of ethanol and another eight plants under expansion or construction with capacity to produce an additional 261 million gallons. However, the RFA estimates that approximately 3.4% of the ethanol production capacity in the United States was not operating as of January 3, 2012. The ethanol industry is continuing to experience a consolidation where a few larger ethanol producers are increasing their production capacities and are controlling a larger portion of United States ethanol production. The largest ethanol producers include Archer Daniels Midland, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, each of which are capable of producing significantly more ethanol than we produce.

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

U.S. FUEL ETHANOL PRODUCTION CAPACITY BY TOP PRODUCERS

Producers of Approximately 400 million gallons per year (mmgy) or more

Company	Current Capacity (mmgy)
Archer Daniels Midland	1,750.0
POET Biorefining	1,629.0
Valero Renewable Fuels	1,130.0
Green Plains Renewable Energy	740.0
Avertine Renewable Energy, LLC	460.0

Source: Renewable Fuels Association - Updated: March 8, 2012

Below is the U.S. ethanol production by state in millions of gallons for the ten states with the most total ethanol production as of January 2012:

State	Nameplate	Operating	Under Construction / Expansion	Total
Iowa	3,625.0	3,625.0	115	3,740.0
Nebraska	2,108.0	1,973.0	0	2,108.0
Illinois	1,486.0	1,486.0	0	1,486.0
Minnesota	1,147.0	1,129.1	0	1,147.1
Indiana	1,147.0	1,147.0	0	1,147.0
South Dakota	1,009.0	1,009.0	0	1,009.0
Ohio	538.0	478.0	0	538.0
Kansas	491.5	411.5	25	516.5
Wisconsin	504.0	504.0	0	504.0
North Dakota	393.0	383.0	0	393.0
Total	12,448.5	12,145.6	140	12,588.6

Source: Renewable Fuels Association, January 2012

Because Nebraska is one of the top producers of ethanol in the U.S., we face increased competition because of the location of our ethanol plant in Nebraska, including several plants owned or operated by the top producers identified in the table above entitled “U.S. Fuel Ethanol Production Capacity by Top Producers.”  These plants are significantly larger than us and have significantly greater financial, technical and marketing resources.  Therefore, we compete with other Nebraska ethanol producers both for markets in Nebraska and markets in other states.

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Nebraska Competition

The Nebraska Ethanol Board reports that there are currently 24 active ethanol production plants in Nebraska, with a combined production capacity of over 2 billion gallons of ethanol each year, and these facilities require more than 700 million bushels of corn each year to operate.  We contribute nearly 2.5% of the total produced volume in Nebraska.

Although the Nebraska legislature has historically provided incentives to ethanol producers in Nebraska, we do not qualify for any existing incentives. Only plants that were in production on June 30, 2004 are eligible for such incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years.  Producers qualifying for this incentive have a competitive advantage over us.

The ten counties surrounding our production facility produced 112 million bushels of corn in 2010.  Specifically, Holt County, where we are located, is the second largest producer of those ten counties with an average corn production of 24 million bushels per year over the last 10 years and 26 million bushels in 2010. This large production in a region with limited demand has pressed the corn price down below the national average for the last 20 years at an average of 40-45 cents per bushel.  Our annual demand of more than 18 million bushels is more than 16% of production in the ten county region and almost 70% in Holt County.

We believe we have an advantage due to our westernmost location which lowers the cost of delivery from our plant into the western U.S. markets.  Conversely, we are at a disadvantage delivering our product into the larger markets of the eastern U.S.California is a significant market for fuel ethanol, both due to its large population and blending mandates resulting in E10 penatration of nearly 100%.  In addition, California is among the top states when considering the number of flexible fuel vehicles.  Our location in the western corn belt provides us a transportation advantage for shipments of ethanol to California and the other western states.  More than 90% of our ethanol sales in 2011 was delivered to California, New Mexico, Texas and the other western states.  In contrast, the large number of competing ethanol plants located to the east of our plant in the eastern corn belt, can more cheaply deliver ethanol to the eastern United States.  As a result, only a small portion of our ethanol was delivered to the eastern and southeastern states in 2011.

Competition from Alternative Renewable Fuels

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

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

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Foreign Competition

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. Several large companies produce ethanol in Brazil. For example, in August 2010, Royal Dutch Shell formed a joint venture with Cosan, which produces approximately 450 mmgy of sugar-based ethanol per year.

Ethanol produced in certain foreign countries and imported into the United States was historically subject to an import tariff of $0.54 per gallon. The $0.54 cent per gallon tariff expired December 31, 2011. This could lead to an increase in ethanol produced in foreign countries being marketed in the United States, especially in areas of the United States that are easily accessible by international shipping ports. Ethanol imported from other countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably. If market prices make importing ethanol to the United States profitable for foreign producers, we could see an influx of imported ethanol on the domestic ethanol market which could have a significant negative impact on domestic ethanol prices and our profitability.  Depending on feed stock prices, ethanol imported from Caribbean Basin countries may be less expensive than domestically-produced ethanol though transportation and infrastructure constraints may temper the market impact on the United States.

Competition from Alternative Fuel Additives

Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development by ethanol and oil companies with far greater resources than we have. 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.

Distillers Grain’s Competition

Ethanol plants in the Midwest produce the majority of distillers grains and primarily compete with other ethanol producers in the production and sale of distillers grains. According to the Renewable Fuels Association's Ethanol Industry Outlook 2011, ethanol plants produced more than 29 million metric tons of distillers grains in 2009/2010 and 31 million metric tons in 2010/2011. The primary customers of distillers grains are dairy and beef cattle, according to the Renewable Fuels Association's Ethanol Industry Outlook 2011. In recent years, an increasing amount of distillers grains have been used in the swine and poultry markets.

The amount of distillers grains produced annually in North America is expected to increase significantly as the number of ethanol plants increase. We compete with other producers of distillers grains products both locally and nationally, with more intense competition for sales of distillers grains among ethanol producers in close proximity to our ethanol plant. 

Additionally, distillers grains compete with other feed formulations, including corn gluten feed, dry brewers’ grain and mill feeds. The primary value of these products as animal feed is their protein content. Dry brewers’ grain and distillers grains have about the same protein content, and corn gluten feed and mill feeds have slightly lower protein contents. Distillers grains contain nutrients, fat content, and fiber that we believe will differentiate our distillers grains products from other feed formulations. However, producers of other forms of animal feed may also have greater experience and resources than we do and their products may have greater acceptance among producers of beef and dairy cattle, poultry and hogs.

Seasonality Sales

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

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to natural depletion in the size of cattle feed lots.   We expect the seasonality of demand for the products we produce to continue to apply to our operations under the Asset Management Agreement and the sale of ethanol and distillers grains by Tenaska.

Transportation and Storage

In order to capitalize on low land acquisition costs, local corn costs, and a number of other factors associated with locating our plant in Atkinson, we transport our ethanol by truck to a transload facility approximately 16 miles from our plant.  We entered into a Transportation Agreement (the “Carrier Transportation Agreement”) with Western Oil Trans Inc. (“Carrier”), under which Carrier ships our ethanol to our rail facility.  The term of the Carrier Transportation Agreement will continue until July 29, 2012 and automatically renew for successive one year periods.  The Carrier Transportation Agreement may be terminated by either party upon providing notice 180 days prior to the end of the then-current term, if the Carrier’s authority to provide shipping services is modified, upon mutual agreement, or upon the discontinuance of either party’s business.

We entered into an Industry Track Agreement (“NENE Track Agreement”) with the Nebraska Northeastern Railway Company (“NENE”), under which we constructed a rail line (“Track”) over NENE’s property located near the center of the City of O’Neill, Nebraska.  The NENE Track Agreement has an initial term of five years, expiring July 24, 2012, and will automatically continue thereafter until terminated by either party upon 30 days’ notice.  The NENE Track Agreement may also be terminated in the event we are unable to cure certain specified defaults, if NENE is authorized to abandon its line which connects to the Track, or if NENE is no longer able to operate over the Track.  Under the NENE Track Agreement, we are responsible for, among other things, maintaining all permits required to operate the Track, and maintain the Track; and NENE has agreed to provide rail service to transport our ethanol over the Track.

We entered into a Track Lease Agreement (the “Track Agreement”) with the Nebraska Game and Parks Commission (the “Commission”), under which we lease from the Commission a parcel of land (the “Property”) to use as a rail spur track over which we transport our ethanol.  The Track Agreement has a term of ten years, expiring June 19, 2017, and will automatically renew for additional ten year terms unless one party notifies the other at least nine months prior to the expiration date of its intention to not renew.  We pay an annual rental fee of $10,000 for use of the Property.  Additionally, we are responsible for any public assessments respecting the maintenance or use of the Property.  The Track Agreement provides that we are responsible to maintain the track on the Property and are solely responsible for our operations on the Property and complying with applicable laws regarding our use of the Property.

As of December 31, 2011 we were leasing 97 rail cars with a lease cost of approximately $88,000 per month.  The average cost per car is $711.  In addition, the Company has entered into month to month leases at varying costs. This market is changing dramatically and rapidly.  Going into the winter of 2011, our average cost was above market, but today that price is competitive and it is changing from month to month.  January 2012 rail car lease costs were more than $135,000 and may exceed $145,000 in February.  Also increasing is the number of rail cars required because of changing turn-around times with the rail roads.

Dependence on Tenaska

As discussed above, the Asset Management Agreement makes Tenaska the exclusive procurement, marketing, sales and distribution agent for our raw materials and the products we produce. We are therefore, dependent on Tenaska for the successful marketing of our products and the cost-effective procurement of required raw materials.

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, construction and operating permits, some of which are discussed below.

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Our failure to obtain and maintain the permits discussed below or other similar permits which are required and those which may be required in the future could force us to make material changes to our business or to shut down altogether.

Environmental Regulations and Permits

We are subject to regulations on emissions from the U.S. Environmental Protection Agency (“EPA”) and the Nebraska Department of Environmental Quality (“NDEQ”). The EPA’s and NDEQ’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.

NDEQ Air Quality Permit

We received an Air Quality Operating Permit from NDEQ that allows us to operate our business.  As previously reported, we received Notices of Violation (“NOV”) from the NDEQ arising from failures of emission equipment designed and installed by our design builder, Delta-T Corporation (“Delta-T”) under the Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T (the “Delta-T Contract”).  

That equipment included the plant’s regenerative thermal oxidizer (“RTO”) used to control emissions from the dryer and the CO2 Scrubber used to control emissions from the ethanol process.  The RTO had not performed according to the design specified in the Delta-T Contract, and the CO2 Scrubber failed in original compliance testing.  Equipment modifications and process adjustments were made, including chemical injection, to remediate the issue.  During the startup operations of the plant beginning in January 2009 and continuing through the date of the original compliance testing, Delta-T had operated the plant without these modifications and as a result, the Company received an NOV in January 2010 which asserted that due to the failure of the CO2 Scrubber, the Company’s operation of the plant violated the operating permit issued by the NDEQ.

Since the end of 2010, management believed it had resolved all of the operational shortfalls cited in the NOVs; however, we previously disclosed that although we believed we had resolved the matter, it was possible the NDEQ or the Nebraska Office of the Attorney General (the “AG Office”) could assess fines against us as a result of having operated the plant with the equipment before it was operating in compliance.  On January 4, 2012, the Company received a letter from the AG Office relating to the prior NOVs and assessing penalties for such violations and two additional violations for emissions related to a leaky pressure value and uncovered bolt hole and failure to observe and report visible emissions.  We have reached an agreement with the AG Office which agreement provides that we will pay a penalty of $25,000 in full satisfaction of all of the NDEQ claims.  In order to formally resolve this matter, after the parties reached the above agreement, on March 7, 2012, the AG Office filed a complaint against us in the District Court of Holt County, Nebraska for the sole purpose of obtaining a Consent Decree to officially close the matter within the AG Office. The Court entered a Consent Decree on March 12, 2012 and the AG Office filed a Satisfaction of Judgment with the Court on March 19, 2012 in full satisfaction of all of the NDEQ claims against the Company.

Other Permits

A General Stormwater Permit for Industrial Activity has been obtained from NDEQ under which we are presently operating and we have implemented a Storm Water Pollution Prevention Plan for monitoring the storm water leaving the site.  We also obtained a permit for non-process wastewater which governs the discharge of noncontact water used in the production of ethanol. There are presently three separate wells near our plant that provide us with our water supply.   All three wells have been registered with the Nebraska Department of Natural Resources (“NDNR”) and their status is registered as “commercial.”  The operation of the wells has also received the approval of the NRD.  Any new or additional wells necessary for the operation of the facility will require registration and approval by the NRD.

Nuisance

We could be subject to environmental nuisance or related claims by employees, property owners or residents near our ethanol plant arising from air or water discharges.  Ethanol production has been known to produce an odor

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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 increase our operating costs.

Operational Safety Regulations

We are also subject to federal and state laws regarding operational safety.  Risks of substantial compliance costs and liabilities are inherent in ethanol production, and 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 construction or operation could result in substantial costs and liabilities.

Research and Development

We may conduct limited research and development to improve our operational efficiency and performance, but we have not determined the scope of such research and development.

New Products and Services

We have not introduced any new products or services during this fiscal year.

Employees

As of December 31, 2011, we had 36 employees, including salaried and hourly employees, and five full time management independent contractors.  We renewed an Employment Agreement with Jerome Fagerland as of November 1, 2009, under which Mr. Fagerland serves as our President and General Manager.  Mr. Fagerland devotes substantially all of his time to our business.  Our Board Chairman, Everett Vogel, Vice Chairman, Richard Bilstein and our Secretary-Treasurer, Timothy Borer, each devote about 15 hours per week to our business.  See “Compensation of Directors and Executive Officers” in our 2012 Proxy Statement.

We have entered into a Plant Operating Agreement with HWS Energy Partners, L.L.C. (“HWS”), under which HWS manages our ethanol plant.  HWS provides, for the employment by us, a sufficient number of employees to operate our plant.  While all employees excepting HWS’s key management personnel are our employees, HWS is responsible for timely identifying employee candidates and assuring that vacancies are filled.

Item 1A.     Risk Factors.

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

RISKS ASSOCIATED WITH OUR MEMBERSHIP UNITS AND CAPITAL STRUCTURE

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

We do not expect an active trading market for our Common Membership Units, Class A Preferred Membership Units or Class B Preferred Membership Units (collectively, “Membership Units”) to develop. To maintain our partnership tax status, our Membership Units may not be publicly traded. We will not apply for listing of the Membership Units on any stock exchange or on the NASDAQ Stock Market. As a result, Members may not sell Membership Units readily. Transfer of Membership Units is also restricted by our Fifth Amended and Restated Operating Agreement dated January 1, 2012 (the “Operating Agreement”) and subject to the procedures contained therein. Transfers without the approval of our Board of Directors or a legal opinion are not permitted and are invalid. Furthermore, the Board of Directors will not approve transfer requests unless they fall within “safe harbors” contained in the publicly-traded partnership rules under the Internal Revenue Code of 1986, as amended (the

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“Code”).  The fair value of our Membership Units will likely be lower because they are illiquid. Members may be required to bear the economic risks associated with an investment in us for an indefinite period of time.

If we issue additional Membership Units in the future this will result in dilution to our existing Members.

On December 31, 2011, we completed a private offering of up to 1,500 Class B Preferred Membership Units (the “Class B Units”) pursuant to which we sold 1,052.50 Class B Units of the Company. Class B Units receive 12% cumulative annual distributions payable upon the earliest of (i) redemption of the Class B Units, (ii) a liquidation, dissolution or winding up of the Company, or (iii) when and if declared by the Board.  The Class B Units are also convertible into our Common Membership Units based on a 12:1 ratio at any time at the holder’s election.  During 2011 and 2010, we also issued Class A Preferred Membership Units (the “Class A Units”) which receive 10% cumulative annual distributions payable upon the earliest of (i) redemption of the Class A Units, (ii) a liquidation, dissolution or winding up of the Company, or (iii) when and if declared by the Board.   Our Board of Directors may choose to issue additional units, including additional Class A Units, Class B Units or different classes of units, which could have different rights, powers and preferences (including, without limitation, voting rights and distribution preferences), which could be superior to those of existing Members.  The issuance of additional units could be at prices lower than Membership Units previously sold to provide additional financing in the near term or in the future. The issuance of any such additional Membership Units may result in a reduction of the book value or fair value of the outstanding Membership Units. If we do issue any such additional units, such issuance also will cause a reduction in the proportionate ownership and voting power of all other Members.

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

Distributions on our Membership Units are payable at the sole discretion of our Board, subject to the provisions of the Nebraska Limited Liability Company Act (the “Act”), our Operating Agreement and our loan agreements.  Cash distributions are not assured even if we generate taxable income to our Members, 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 our ethanol plan, 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 Operating Agreement contains restrictions on members’ rights to participate in corporate governance of our affairs, which limits their ability to influence management decisions.

We are managed by a Board of Directors and our members are not involved in the governance and day-to-day operations of the Company. Our Board directs the business and affairs and exercises all of the powers of the Company, except to the extent the Operating Agreement expressly gives the members decision-making power. Our Operating Agreement provides that a member or members owning at least thirty percent of the outstanding Membership 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 use of a staggered Board of Directors and the establishment of Director appointment rights may reduce the ability of members to affect the composition of the Board.

Our Board of Directors currently consists of fourteen Directors consisting of twelve elected Directors and two appointed Directors. The seats on our Board that are not subject to a right of appointment will be elected by the members without appointment rights.  An appointed Director serves indefinitely at the pleasure of the member appointing him or her (so long as such member continues to hold a sufficient number of Membership Units to maintain the applicable appointment right) until a successor is appointed, or until the earlier death, resignation or removal of the appointed Director.

The elected seats on our Board of Directors are divided into three classes, with each class serving a staggered three-year term, with the term of one class expiring each year. As the term of each class expires, the successors to the Directors in that class will be elected for additional terms of three years.  The classification of the elected

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members of our Board of Directors will make it more difficult for members to change the composition of the Board because only a minority of the Directors can be elected at one time. If a vacancy develops in our Board of Directors for any reason other than removal or expiration of a term, the remaining Directors would fill it.

The effect of classification of our Board of Directors also makes it more difficult for a third party to acquire, or may discourage a third party from acquiring, control of us and may discourage attempts to change our management, even if an acquisition or these changes would be beneficial to our members.

Our Directors have other business and management responsibilities which may cause conflicts of interest in the allocation of their time and services to the Company.

Since our project is currently managed both by our officers and to some extent by the Board of Directors (rather than completely by a professional management group), the devotion of the Directors’ time to the project is critical.  However, the Directors have other management responsibilities and business interests apart from our business.  As a result, our Directors may experience conflicts of interest in allocating their time and services between us and their other business responsibilities.  We have adopted a related party transaction policy and a Code of Ethics, but there can be no assurance that these policies will fully alleviate conflicts of interest that could impact the Company.

RISKS ASSOCIATED WITH OUR FINANCING STRUCTURE

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 our credit facility, we have made certain customary representations and we are subject to customary affirmative and negative covenants, including restrictions on our ability to incur debt, create liens, dispose of assets, pay distributions and to make capital expenditures, and customary events of default (including payment defaults, covenant defaults, cross defaults, construction related defaults and bankruptcy defaults).  The credit facility also contains financial covenants including minimum tangible net worth and minimum owners’ equity ratio as of December 31, 2011 and in the future.  These requirements, in addition to our obligations to repay principal and interest on the credit facility, make us more vulnerable to economic or market downturns. If we are unable to service our debt or modify our covenants, we may be forced to reduce or delay planned capital expenditures, sell assets, restructure our indebtedness or seek additional equity capital.

Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial debt.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which to a certain extent is subject to economic, financial, competitive and other factors beyond our control. As of December 31, 2011, we had approximately $32.6 million of total debt outstanding under our credit agreements. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to service our debt, our lenders may accelerate our indebtedness and may seize the assets that secure our indebtedness, causing us to lose control of our business.  If we are unable to generate sufficient cash flow to service our debt obligations, we could be required to sell assets, restructure our existing indebtedness or seek additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations. If we are unable to service our debt, our lenders may accelerate our indebtedness and may seize the assets that secure our indebtedness, causing us to lose control of our business. 

We operate in capital intensive businesses and rely on cash generated from operations and external financing. Limitations on access to external financing could adversely affect our operating results.

Some ethanol producers have faced financial distress, culminating with bankruptcy filings by several companies. This, in combination with continued volatility in the capital markets has resulted in reduced availability of capital for the ethanol industry generally. Construction of our plant and anticipated levels of required working capital were funded under our long-term credit facility. Further increases in liquidity requirements could occur due

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to, for example, increased commodity prices. Our operating cash flow is dependent on our ability to profitably operate our business and overall commodity market conditions. In addition, we may need to raise additional financing to fund our operations. In this market environment, we may experience limited access to financing. This could cause us to reduce our business activity or, if we are unable to meet our debt repayment schedules, cause a default in our existing debt agreements. These events could have a material adverse effect on our operations and financial position.

Our ability to repay current and anticipated future indebtedness will depend on our financial and operating performance and on the successful implementation of our business strategies. Our financial and operational performance depends on numerous factors including prevailing economic conditions, volatile commodity prices, and financial, business and other factors beyond our control. If we cannot pay our debt service, we may be forced to sell assets, restructure our indebtedness or seek additional capital. If we are unable to restructure our indebtedness or raise funds through sales of assets, equity or otherwise, it may have a negative impact on our liquidity, our ability to operate could be harmed and the value of our Membership Units could be significantly reduced.

We may be required to write down our long-lived assets and these impairment charges would adversely affect our operating results.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount on 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 assets at the time of the impairment.  Future impairment could be significant and could have a material adverse effect on our reported financial results for the period in which the charge is taken.

RISKS ASSOCIATED WITH OUR OPERATION

Our sales will decline, and our business will be materially harmed if Tenaska does not effectively market or sell the ethanol and distillers grains we produce.

We have entered into an Asset Management Agreement with Tenaska under which Tenaska is the exclusive asset manager for us and we no longer process corn into ethanol for any party other than Tenaska. Tenaska is an independent business that we do not control. We cannot be certain that Tenaska will market or sell our ethanol and distillers’ grains effectively. Our success in achieving revenue from the sale of ethanol and distillers’ grains will depend upon the continued viability and financial stability of Tenaska, and their ability to devote the necessary resources to provide effective sales and marketing support of the ethanol and distillers grains we produce. Our financial success will depend primarily upon the success of Tenaska in operating its businesses and effectively managing its obligations under the Asset Management Agreement. If Tenaska does not effectively market and sell our ethanol and distillers’ grains, our revenues will decrease and our operations, liquidity and financial condition will be harmed.

Our results of operations and ability to operate at a profit are largely dependent on managing the spread among the prices of corn, natural gas, ethanol and distillers grains, the prices of which are subject to significant volatility and uncertainty.

The results of our current ethanol production business are highly impacted by commodity prices, including the spread between the cost of corn and natural gas that we must purchase, and the price of ethanol and distillers grains that we sell, which is known in the industry as the “crush spread.” Prices and supplies are subject to and determined by market forces over which neither the Company or Tenaska have control, such as weather, domestic and global demand, shortages, export prices, and various governmental policies in the United States and around the world. As a result of price volatility for these commodities, our operating results may fluctuate substantially. Increases in corn prices or natural gas or decreases in ethanol or distillers grains prices may make it unprofitable to operate our ethanol plant.  No assurance can be given that Tenaska will be able to purchase corn and natural gas at, or near, current prices and that Tenaska will be able to sell ethanol or distillers grains at, or near, current prices. Consequently, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol and distillers grains.

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In early 2006, the spread between ethanol and corn prices was at historically high levels, driven in large part by oil companies removing a competitive product, methyl tertiary butyl ether, or MTBE, from the fuel stream and replacing it with ethanol in a relatively short time period. However, since that time, this spread has fluctuated widely and narrowed significantly. Fluctuations are likely to continue to occur. A sustained narrow spread or any further reduction in the spread between ethanol and corn prices, whether as a result of sustained high or increased corn prices or sustained low or decreased ethanol prices, would adversely affect our results of operations and financial position. Further, combined revenues from sales of ethanol and distillers grains could decline below our marginal cost of production, which could cause us to suspend production of ethanol and distillers grains at our ethanol plant.

The prices of these commodities are volatile and beyond our control. For example, from January 1, 2010 through December 31, 2011, spot corn prices on the CBOT ranged from $3.25 to $7.86 per bushel, while CBOT ethanol prices ranged from $1.47 to $3.07 per gallon during the same period. However, the volatility in corn prices and the volatility in ethanol prices are not necessarily correlated, and as a result, the crush spread, as measured by CBOT prices, and an assumed yield of 2.8 gallons of ethanol per bushel of corn fluctuated widely throughout 2010, ranging from $0.02 per gallon to $0.54 per gallon, and during 2011, ranging from ($0.11) per gallon to $0.60 per gallon. The actual commodity margins we realize may not be the same as the crush spreads reflected by CBOT market prices as a result of various factors, including differences in geographic basis paid for corn, varying ethanol sales prices in different markets and the timing differential between when we purchase corn and when we sell our products.

Although Tenaska will purchase our corn and natural gas and sell our ethanol and distillers grains, we cannot predict when or if crush spreads will fluctuate again or if the current margins will improve or worsen. If crush spreads were to remain at current levels for an extended period of time, despite Tenaska’s assistance, we may expend all of our sources of liquidity, in which event we would not be able to pay principal and interest on our debt. We expect fluctuations in the crush spread to continue. Any further reduction in the crush spread may cause our operating margins to deteriorate resulting in the consequences described above.

We have limited working capital, which could result in losses that will affect the value of Membership Units or members’ investment return.

We cannot make representations about our future profitable operation or our future income or losses. If our plans prove to be unsuccessful, members will lose all or a substantial part of their investment. There can be no assurance that the funds we received in our equity offerings, combined with debt incurred, will be sufficient to allow us to operate our plant until profits are attained.

We may be at a competitive disadvantage compared to other ethanol producers because of our distance from a railhead, which increases our costs and could reduce the value of Membership Units or members’ investment return.

Our plant is approximately 16 miles from the nearest railhead. We have constructed a transload facility near the railhead and truck our ethanol to the transload facility. Many ethanol producers have a railhead located at their ethanol production facility and as a result, these producers do not incur additional trucking costs required to transport ethanol from their plant to the railhead.  The additional costs we incur in connection with the trucking of our ethanol from our plant to our railhead could put us at a disadvantage compared to our competitors, which could adversely affect our financial performance and the value of our Membership Units.

We are dependent upon our plant management company to hire and retain competent personnel.

We have entered into a Plant Operating Agreement with HWS, under which HWS manages all facets of our plant’s operations and provides, for the employment by us, employees to operate our plant. We have 36 paid persons operating our business. Our success will depend in part on the ability of HWSto attract and retain competent personnel who will be able to help us achieve our goals. It may be difficult to attract qualified employees to Atkinson, Nebraska, a rural and sparsely populated area. If HWS is unable to retain productive and competent personnel, our ability to produce and sell ethanol could be adversely affected.

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Casualty losses may occur for which we have not secured adequate insurance.

We have acquired insurance that we believe to be adequate to prevent loss from foreseeable risks. However, events occur for which no insurance is available or for which insurance is not available on terms that are acceptable to us. Loss from such an event, such as, but not limited to, earthquake, tornados, war, riot, terrorism or other risks, may not be insured and such a loss may have a material adverse effect on our operations, cash flows and financial performance.

Our business is not diversified and this could reduce the value of Membership Units if our revenues from our primary products decrease.

Our business consists solely of ethanol and distillers grains 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 and distillers grains 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 in 2003 through December 31, 2011, we incurred an accumulated net loss of approximately $18,900,000.   There is no assurance that we will be successful in operating the plant profitably.

If there are defects in our plant, it may negatively affect our ability to operate the plant.

There is no assurance that defects in materials and/or workmanship in our plant will not occur. Such defects occurred in 2009 and could cause us to halt or discontinue the plant’s operations.  We have released Delta-T from any further responsibility for any construction defects or warranty claims under our settlement with Delta-T.  Accordingly, we will be required to pay for any such defects should they occur.  Any such event may have a material adverse effect on our operations, cash flows and financial performance.

The internal controls over financial reporting we have developed may not be adequate, which could have a significant and adverse effect on our business and reputation.

We have designed and tested our internal controls over financial reporting.  We expect to incur ongoing additional expenses to comply with applicable law, which will negatively impact our financial performance and our ability to make distributions.  This process may also divert management’s time and attention.  Our management is required to report on our internal controls over financial reporting pursuant to Sections 302 and 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) and rules and regulations of the SEC thereunder in this report on Form 10-K.  We are required to review on an annual basis our internal controls over financial reporting, and on a quarterly and annual basis to evaluate and disclose changes in our internal controls over financial reporting.  There can be no assurance that our quarterly and annual reviews will not identify material weaknesses or that we will successfully resolve all issues which may arise under any such evaluations.

Disruption or difficulties with our information technology could impair our ability to operate.

Our business depends on the effective and efficient use of information technology. A disruption or failure of these systems could cause system interruptions, delays in production and a loss of critical data that could severely affect our ability to conduct normal business operations.

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. There are no assurances that we will continue to have a sufficient supply of water to sustain our ethanol plant in the future, or that we can obtain the necessary permits to obtain water directly from the Elkhorn River as an alternative to our wells.  As a result, our ability to make a profit may decline.

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Hedging transactions, which are intended to stabilize our corn costs, also involve risks and costs that could reduce our profitability.

In an attempt to mitigate the effects of the volatility of corn costs on operating profits, Tenaska may take hedging positions in corn futures markets.  Hedging means protecting the price at which Tenaska buys corn and the price at which Tenaska will sell the products we produce in the future. It is a way to attempt to reduce the risk caused by price fluctuation. The effectiveness of hedging activities is dependent upon, among other things, the cost of corn and their ability to sell sufficient amounts of ethanol and distillers grains to utilize all of the corn subject to the futures contracts. Hedging activities result in costs such as brokers’ commissions and other transaction costs.  If there are significant swings in corn prices, or if Tenaska purchases more corn for future delivery than we can process, and if the margin between what Tenaska purchases our corn at is not positive when compared to the margin for which Tenaska can sell the ethanol we produce, Tenaska may have to pay to terminate a futures contract, resell unneeded corn inventory at a loss, or produce ethanol at a loss, all of which would have a material adverse effect on our financial performance.

Liquidity can be affected when margin account balances are insufficient to cover the margin requirements of these hedging transactions.  These accumulated differences in value on these derivatives are marked to market as of the last day of every month and the change in value over the period is recorded in the income statement as a loss or profit each recording period.  These financial statement charges can cause large swings in profitability.

The Dodd-Frank Act could result in an increase in the cost of hedging, which could decrease our results of operations.

The regulations of “over-the-counter” derivatives introduced by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) could adversely impact our hedging strategy through Tenaska.  Through its comprehensive new regulatory regime for derivatives, the Dodd-Frank Act will impose mandatory clearing, exchange-trading and margin requirements on many derivatives transactions (including formerly unregulated over-the-counter derivatives) in which we may engage. The Dodd-Frank Act also creates new categories of regulated market participants who will be subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements. The details of these requirements and the parameters of these categories remain to be clarified through rulemaking and interpretations by the Commodities Futures Trading Commission, the SEC, the Federal Reserve and other regulators in a regulatory implementation process, which is expected to take a year or more to complete.  Nonetheless, based on information available as of the date of this prospectus, the possible effect of the Dodd-Frank Act will be to increase the overall costs of derivatives transactions that Tenaska enters into on our behalf. In particular, new margin requirements, position limits and capital charges, even if not directly applicable to us, may cause an increase in the pricing of derivatives transactions sold by market participants to whom such requirements apply.

Administrative costs, due to new requirements such as registration, recordkeeping, reporting, and compliance, even if not directly applicable to us, may also be reflected in higher pricing of derivatives. New exchange-trading and trade reporting requirements may lead to reductions in the liquidity of derivative transactions, causing higher pricing or reduced availability of derivatives, adversely affecting the performance of our hedging strategies. The Dodd-Frank Act could result in the cost of executing our hedging strategy increasing significantly, which could potentially result in an undesirable decrease in the amount of corn and ethanol we hedge. If our hedging costs increase and we are required to post cash collateral, our business would be adversely affected as a result of reduced cash flow and reduced liquidity.  Additionally, in the event that we hedge lower quantities in response to higher hedging costs and increased margin requirements, our exposure to changes in commodity prices would increase, which could result in decreased cash flows.

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. If Tenaska is unable to obtain a natural gas supply on terms that are satisfactory, the adverse impact on our plant and operations could be material. In addition, natural gas and electricity prices have historically fluctuated significantly. Increases in the price of natural gas or electricity would

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harm our business by increasing our energy costs. We will need to purchase significant amounts of electricity to operate our plant. The prices which we will be required to pay for electrical power will have a direct impact on our costs of producing ethanol and our financial results.

Changes and advances in ethanol production technology could require us to incur costs to update our plant or could otherwise hinder our ability to compete in the ethanol industry or operate profitably.

Advances and changes in the technology of ethanol production are expected to occur.Such advances and changes may make the ethanol production technology installed in our plant less desirable or obsolete.These advances could also allow our competitors to produce ethanol at a lower cost than 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.

We are exposed to potential business disruption from factors outside our control, including natural disasters, seasonality, severe weather conditions, accidents, and unforeseen plant shutdowns, any of which could adversely affect our cash flows and operating results.

Potential business disruption in available transportation due to natural disasters, significant track damage resulting from a train derailment, or strikes by our transportation providers could result in delays in procuring and supplying raw materials to our ethanol plant, or transporting ethanol and distillers grains to our customers. We also run the risk of unforeseen operational issues that may result in an extended shutdown of our ethanol plant. Such business disruptions would cause the normal course of our business operations to stall and may result in our inability to meet customer demand or contract delivery requirements, as well as the potential loss of customers.

Corn procurement for our ethanol plant is dependent on weather conditions. Adverse weather may result in a reduction in the sales of fertilizer or pesticides during typical application periods, a reduction in grain harvests caused by inadequate or excessive amounts of rain during the growing season, or by overly wet conditions, an early freeze or snowy weather during the harvest season. Additionally, corn stored in an open pile may become damaged by too much rain and warm weather before the corn is dried, shipped, consumed or moved into a storage structure.

If exports to Europe are decreased due to the recent European anti-dumping investigation, it may negatively impact ethanol prices in the United States.

The European Union recently commenced an anti-dumping investigation related to ethanol produced in the United States and exported to Europe. The purpose of the investigation is to determine whether the European Union will impose a tariff on ethanol which is produced in the United States and exported to Europe. If exports of ethanol to Europe decrease as a result of this anti-dumping investigation, it could negatively impact the market price of ethanol in the United States. Any decrease in ethanol prices or demand may negatively impact our ability to profitably operate the ethanol plant.

Technology in our industry evolves rapidly, potentially causing our plant to become obsolete, and we must continue to enhance the technology of our plant or our business may suffer.

We expect that technological advances in the processes and procedures for processing ethanol will continue to occur. It is possible that those advances could make the processes and procedures that we utilize at our ethanol plant less efficient or obsolete. These advances could also allow our competitors to produce ethanol at a lower cost than we are able. If we are unable to adopt or incorporate technological advances, our ethanol production methods and processes could be less efficient than those of our competitors, which could cause our ethanol plant to become uncompetitive.

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Ethanol production methods are constantly advancing. 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 and municipal solid waste. 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 that are unable to grow corn. Another trend in ethanol production research is to produce ethanol through a chemical or thermal process, rather than a fermentation process, thereby significantly increasing the ethanol yield per pound of feedstock. Although current technology does not allow these production methods to be financially competitive, new technologies may develop that would allow these methods to become viable means of ethanol production in the future. If we are unable to adopt or incorporate these advances into our operations, our cost of producing ethanol could be significantly higher than those of our competitors, which could make our ethanol plant obsolete. Modifying our plant to use the new inputs and technologies would likely require material investment.

If ethanol fails to compete successfully with other existing or newly-developed oxygenates or renewable fuels, our business will suffer.

Alternative fuels, additives and oxygenates are continually under development. Alternative fuels and fuel additives that can replace ethanol are currently under development, which may decrease the demand for ethanol. Technological advances in engine and exhaust system design and performance could reduce the use of oxygenates, which would lower the demand for ethanol, and our business, results of operations and financial condition may be materially adversely affected.

RISKS ASSOCIATED WITH THE ETHANOL INDUSTRY

Increased ethanol industry penetration by oil companies or other multinational companies may adversely impact our margins.

We operate in a very competitive environment. In 2010 and 2011, significant investment in ethanol production was made by large oil distribution companies through the acquisition of failing organizations.  Prior to that, the ethanol industry  has been primarily comprised of smaller entities that engage exclusively in ethanol production and large integrated grain companies that produce ethanol along with their base grain businesses. We face competition for capital, labor, corn and other resources from these companies. Until recently, oil companies, petrochemical refiners and gasoline retailers have not been engaged in ethanol production to a large extent. These companies, however, form the primary distribution networks for marketing ethanol through blended gasoline. During the past few years, several large oil companies have entered the ethanol production market. If these companies increase their ethanol plant ownership or other oil companies seek to engage in direct ethanol production, there will be less of a need to purchase ethanol from independent ethanol producers like us. This negative factor may also lead to increasing capacity for ethanol production if new plants are built or existing plants expanded by those oil companies.  Such a structural change in the market could result in a material adverse effect on our operations, cash flows and financial position.

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.

Industry distress may adversely impact our ability to access credit necessary to operate.

The ethanol industry has faced significant industry distress in the past several years, with many producers filing bankruptcy.  Furthermore, the overall capital markets in the United States have been less liquid and volatile.  These conditions make it extremely difficult to secure credit, to refinance credit or negotiate forbearance terms with lenders.  Although we have essentially fully drawn on our credit facility, we need to renegotiate the terms of our credit agreement.  Given the market conditions, we may not be able to access credit or procure necessary waivers,

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which could cause us to have to reduce or shut down our operations and would have a material adverse effect on our operations and financial performance.

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., POET and Valero, among others, are capable of producing a significantly greater amount of ethanol than we produce.  Furthermore, ethanol from certain Central American or Caribbean 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.  As of December 2011, the RFA reported that there were 209 ethanol plants in operation in the United States with the capacity to produce 14.7 billion gallons of ethanol annually.  An additional nine plants are under construction or expanding, which could add an additional estimated 0.26 billion gallons of annual production capacity.  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.

Compared to the RFS2 standard for 2011, there is marginal oversupply in the United States.  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 the price of ethanol will likely remain low relative to costs.  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 Membership Units and Members’ investment return.

Future demand for ethanol is uncertain and may be affected by changes to federal mandates, public perception and consumer acceptance, any of which could negatively affect demand for ethanol and our results of operations.

To support any expansion of the ethanol industry, domestic ethanol consumption must increase. Additionally, public opinion must be supportive of continued or increased mandates in order to maintain the preferred status of ethanol in public policy. The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline. At the present rate of expansion, it is probable that ethanol production will exceed levels set by federal mandate. Additionally, it is possible that ethanol production will exceed domestic blending capacity.

Ethanol production from corn has not been without controversy. There have been questions of overall economic efficiency and sustainability, given the industrialized and energy-intensive nature of modern corn agriculture. Additionally, ethanol critics frequently cite the moral dilemma of redirecting corn supplies from international food markets to domestic fuel markets. The controversy surrounding corn ethanol is dangerous to the industry because ethanol demand is largely dictated by federal mandate. If public opinion were to erode, it is possible that the federal mandates will lose political support and the ethanol industry will be left without a market.

Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, including the recently-released EPA regulations on the RFS program, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels and potentially depleting water resources. Some studies have suggested that corn-based ethanol is less efficient than ethanol produced from switchgrass or wheat grain and that it negatively impacts consumers by causing prices for dairy, meat and other foodstuffs from livestock that consume corn to increase. Additionally, ethanol critics contend that corn supplies are redirected from international food markets to domestic fuel markets. If negative views of corn-based ethanol production gain acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of federal mandates which would adversely affect the demand for ethanol. These views could also negatively impact public perception of the ethanol industry and acceptance of ethanol as an alternative fuel.

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Beyond the federal mandates, there are limited markets for ethanol. Discretionary blending is an important secondary market. However, consumer acceptance of E85 fuels and flexible-fuel technology vehicles is needed before there will be any significant growth in market share. International markets offer possible opportunities.  Ethanol has foreseeable applications as an aviation or locomotive fuel. Limited markets also exist for use of ethanol as an antiseptic, antidote or base compound for further chemical processing. Unfortunately, all these additional markets are undeveloped.

At present, we cannot provide any assurance that there will be any material or significant increase in the demand for ethanol beyond the increases in mandated gasoline blending. Increased production in the coming years is likely to lead to lower ethanol prices. Additionally, the increased production of ethanol could have other adverse effects as well. For example, the increased production could lead to increased supplies of by-products from the production of ethanol, such as distillers grains. Those increased supplies could lead to lower prices for those by-products. Also, the increased production of ethanol could result in a further increase in the demand for corn. This could result in higher prices for corn creating lower profits. There can be no assurance as to the price of ethanol, corn, or distillers grains in the future. Adverse changes affecting these prices may have a material adverse effect on our operations, cash flows and financial performance.

Consumer resistance to the use of ethanol based on the belief that ethanol is expensive, adds to air pollution, harms engines and/or takes more energy to produce than it contributes may affect the demand for ethanol.

Certain individuals believe that the use of ethanol will have a negative impact on gasoline prices at the pump. Many also believe that ethanol adds to air pollution and harms car and truck engines. Still other consumers believe that the process of producing ethanol actually uses more fossil energy, such as oil and natural gas, than the amount of energy that is produced. These consumer beliefs could potentially be wide-spread and may be increasing as a result of recent efforts to increase the allowable percentage of ethanol that may be blended for use in conventional automobiles. If consumers choose not to buy ethanol based on these beliefs, it would affect the demand for the ethanol we produce which could negatively affect our profitability and financial condition.

Competition from the advancement of alternative fuels may lessen 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 decrease fuel costs, lessen 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 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.  Although current technology is not sufficiently efficient to be competitive, a report dated August 25, 2000 by the U.S. Department of Energy entitled “Outlook for Biomass Ethanol Production and Demand” indicated that new conversion technologies may be developed in the future.  If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively.  We do not believe it will be cost-effective to convert our Facility into a plant which will use cellulose-based biomass to produce ethanol.  If we are unable to

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produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue will be negatively impacted and members’ investment could lose value.

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

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 record high corn prices in the spring of 2009 resulted in lower profit margins for the production of ethanol, and market conditions generally do not allow us to pass along increased corn costs to our customers.  If the demand for corn returned to the levels of spring 2009 and drove 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 Membership Units and Members’ investment return.

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.  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.  Any penetration of ethanol imports into the domestic market may have a material adverse effect on our operations, cash flows and financial position.

Our revenue from the sale of distillers grains depends upon its continued market acceptance as an animal feed.

Distillers grain is a co-product from the fermentation of various crops, including corn, to produce ethanol. The U.S. Food and Drug Administration’s (“FDA”) Center for Veterinary Medicine has expressed concern about potential animal and human health hazards from the use of distillers grains as an animal feed. As a result, the market value of this co-product could be diminished if the FDA were to introduce regulations that limit the sale of distillers grains in the domestic market or for export to international markets, which in turn would have a negative impact on our profitability. In addition, if public perception of distillers grains as an acceptable animal feed were to change or if the public became concerned about the impact of distillers grains in the food supply, the market for distillers grains would be negatively impacted, which would have a negative impact on our profitability.

Specifically, in the past, Escherichia coli (“E. coli”) outbreaks in beef cattle have been attributed to use of distillers grains as a cattle feed. At present, there is no conclusive causal relationship between E. coli and distillers grains. However, despite the current lack of scientific evidence, this continued controversy could have an adverse impact on distillers grains markets. Any connection, whether based on scientific evidence or popular opinion, between distillers grains and E. coli could have a material adverse effect on our operations, cash flows and financial performance, a result which is unlikely to change even if we enter into a more comprehensive arrangement with Tenaska.

The price of distillers grains is affected by the price of other commodity products, such as soybeans and corn, and decreases in the price of these commodities could decrease the price of distillers grains, which will decrease the amount of revenue we may generate.

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Distillers grains compete with other protein-based animal feed products. The price of distillers grains may decrease when the prices of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the commodities from which these products are derived. Downward pressure on commodity prices, such as soybeans and corn, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers grains. Decreases in the price of distillers grains will result in lower revenues.

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.

RISKS ASSOCIATED WITH GOVERNMENT REGULATION AND SUBSIDIZATION

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

Although the Nebraska legislature has historically provided incentives to ethanol producers in Nebraska, and may do so in the future, we do not qualify for any existing incentives. Only plants that were in production on June 30, 2004 are eligible for such incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years.

The ethanol industry is highly dependent on government usage mandates affecting ethanol production and any changes to such regulation could adversely affect the market for ethanol and our results of operations.

The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline.  The RFS mandate level for 2012 of 15.2 billion gallons approximates current domestic production levels.  Future demand will be largely dependent upon the RFS and other policy regarding renewable energy.  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.

The American Jobs Creation Act of 2004 created the volumetric ethanol excise tax credit (“VEETC”), which provided companies with a tax credit to blend ethanol with gasoline, expired on December 31, 2011.   Since the expiration of VEETC, we believe we are experiencing some negative impacts on the price of ethanol and the demand for ethanol in the market due to reduced discretionary blending of ethanol.

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.

To the extent that such federal or state laws are modified, the demand for ethanol may be reduced, which could negatively and materially affect our ability to operate profitably. There has been an increase in the number of claims against the use of ethanol as an alternative energy source. Many of such claims attempt to draw a link between recently increasing global food prices and the use of corn to produce ethanol. Others claim that the production of

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ethanol requires too much energy. Such claims have led some, including members of Congress, to urge the modification of current government policies which affect the production and sale of ethanol in the United States. Similarly, several states which currently have laws which affect the production and sale of ethanol, such as mandated usage of ethanol, have proposed to modify or eliminate such mandates. To the extent that such state or federal laws were modified, the demand for ethanol may be reduced, which could negatively and materially affect our ability to operate profitably.

Increased federal support of cellulosic ethanol may result in reduced incentives to corn-derived ethanol producers.

Recent legislation, such as the American Recovery and Reinvestment Act of 2009 and the 2007 Act, provides numerous funding opportunities in support of cellulosic ethanol, which is obtained from other sources of biomass such as switchgrass and fast growing poplar trees. In addition, the amended RFS mandates an increasing level of production of biofuels that are not derived from corn. Federal policies suggest a long-term political preference for cellulosic processes using alternative feedstocks such as switchgrass, silage, wood chips or other forms of biomass. Cellulosic ethanol has a smaller carbon footprint because the feedstock does not require energy-intensive fertilizers and industrial production processes. Additionally, cellulosic ethanol is favored because it is unlikely that foodstuff is being diverted from the market. Several cellulosic ethanol plants are under development. As research and development programs persist, there is the risk that cellulosic ethanol could displace corn ethanol. In addition, any replacement of federal incentives from corn-based to cellulosic-based ethanol production may reduce our profitability.

We handle potentially hazardous materials in our businesses. If environmental requirements become more stringent or if we experience unanticipated environmental hazards, we could be subject to significant costs and liabilities.

A significant part of our business is regulated by environmental laws and regulations, including those governing the labeling, use, storage, discharge and disposal of hazardous materials. Because we use and handle hazardous substances in our businesses, changes in environmental requirements or an unanticipated significant adverse environmental event could have a material adverse effect on our business. There is no assurance that we have been, or will at all times be, in compliance with all environmental requirements, or that we will not incur material costs or liabilities in connection with these requirements. Private parties, including current and former employees, could bring personal injury or other claims against us due to the presence of, or exposure to, hazardous substances used, stored or disposed of by us, or contained in our products. In addition, changes to environmental regulations may require us to modify our existing plant and processing facilities and could significantly increase the cost of those operations.

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 will be subject to regulations on emissions from the EPA and the NDEQ. The EPA’s and NDEQ’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.

As discussed elsewhere in this report, we must maintain a variety of permits and approvals from federal, state and local governmental authorities.  Our failure to maintain any one of those permits or approvals could materially harm our financial performance.

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. As our business grows, we will have to develop and 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 may also restrict our production and distribution operations. We could incur significant costs to comply with applicable laws and regulations as production and distribution activity increases. Protection of the environment will require us to incur expenditures for equipment or processes.

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We could be subject to environmental nuisance or related claims by employees, property owners or residents near the proposed ethanol plant 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 should mitigate 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 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 ethanol plant 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 Nebraska 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 our ethanol plant profitably, which may decrease the value of our Membership Units and Members’ investment return.

Our business is affected by the regulation of GHG, and climate change. New climate change regulations could impede our ability to successfully operate our business.

Our ethanol plant emits carbon dioxide as a by-product of the ethanol production process. On February 3, 2010, the EPA released its final regulations on the RFS program, or RFS 2. We believe these final regulations grandfather our ethanol plant at its current operating capacity, though expansion of our ethanol plant would need to meet a threshold of a 20% reduction in GHG emissions from a baseline measurement for the ethanol over current capacity to be eligible for the RFS 2 mandate. Additionally, legislation is pending in Congress on a comprehensive carbon dioxide regulatory scheme, such as a carbon tax or cap-and-trade system. If we sought to expand capacity at our ethanol plant, we would have to apply for additional permits, install advanced technology such as corn oil extraction, or reduce drying of certain amounts of distillers grains. We may also be required to install carbon dioxide mitigation equipment or take other steps unknown to us at this time in order to comply with other future law or regulation. Compliance with future law or regulation of carbon dioxide, or if we choose to expand capacity, compliance with then-current regulation of carbon dioxide could be costly and may prevent us from operating our ethanol plant as profitably, which may have a material adverse impact on our operations, cash flows and financial position.

The California Low Carbon Fuel Standard may decrease demand for corn based ethanol which could negatively impact our profitability.

Recently, California passed a Low Carbon Fuels Standard (“LCFS”). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which are measured using a lifecycle analysis. Management believes that these new regulations could preclude corn based ethanol produced in the Midwest from being used in California.   On December 29, 2011, the U.S. District Court for the Eastern District of California issued an injunction which states that the California Air Resources Board cannot enforce the LCFS while certain litigation is pending. The California Air Resources Board then requested a stay on the injunction, but its request was denied and on January 26, 2012 the California Air Resources Board filed another appeal with the Ninth Circuit Court of Appeals. While the LCFS standard is currently being challenged by various

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lawsuits, implementation of such a standard may have an adverse impact on our market for corn-based ethanol in California.  California represents a significant ethanol demand market, and if we are unable to supply ethanol to California, it could significantly reduce demand for the ethanol we produce. Any decrease in ethanol demand could negatively impact ethanol prices which could reduce our revenues and negatively impact our ability to profitably operate the ethanol plant.

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 a Nebraska 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 treated as ordinary dividend income to the extent of our earnings and profits, and the payment of distributions 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 is 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 contained in the Facility 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.

If our allocations of income and deduction are not respected by the IRS, Members may be required to recognize additional taxable income.

We allocate items of income, gain, loss, deduction or credit, if any, consistent with the requirements of Code Section 704(b) of the Code.  We maintain capital accounts in a manner which falls within the “safe harbor” standards for substantial economic effect under Treasury Regulations adopted under the Code, and we believe that our allocations of income and deduction are consistent with each Member’s interest in the Company and will be respected by the IRS.  Nevertheless, if our allocations of income and deduction are not respected by the IRS, the Members may be required to recognize additional taxable income.

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Risk of IRS audit.

An entity organized as a limited liability company and taxed as a partnership is likely to be subject to a greater risk of audit by the IRS than are other business entities.  Certain tax aspects of our operations may be challenged upon audit by the IRS.  Any adjustment resulting from an audit by the IRS also could result in adjustments to the tax returns of an individual member and may lead to an examination of other items unrelated to the Company in such returns or an examination of prior tax returns of the members.  Moreover, we could incur substantial legal and accounting costs in connection with any challenge by the IRS of the position taken by us on our tax returns regardless of the outcome of such a challenge.

The foregoing is not intended to be an exhaustive discussion of all the risks that may be associated with an investment in us.  Moreover, because there are many inherent risks that may not be anticipated by us, you should be aware that there are additional risks inherently associated with our Company and which are not presently foreseen by us.

Item 2. Properties.

Our plant requires the use of four parcels of property.  Each parcel is vital in bringing our ethanol product to market.  The following is a brief description of each parcel, and how it relates to our ethanol production procedure.  We believe that all of our properties are adequately covered by insurance.  All of our properties are subject to first priority security interests we granted to our lender to secure our repayment of our obligations under our credit facility.

Plant Site

This 73.28 acre parcel of land is devoted to our ethanol production and is located in the City of Atkinson, Holt County, Nebraska.  The nearest rail road access to this property is approximately 16 miles away in O’Neill, Nebraska.  The cost to extend rail track to our production facility was excessive when compared to the operating costs of trucking our ethanol product to O’Neill.  Therefore, the other three properties are required for delivery of our product to market.

Transload Facility

Our transload facility, on 10.97 acres, is in the City of O’Neill, Holt County, Nebraska.  Trucked from our Atkinson production facility, our ethanol product is loaded into a 1,000,000 gallon storage tank at our transload facility and from that tank into rail cars.

Cowboy Trail

The Cowboy Trail is an abandoned rail road track that has been converted to a public park riding/walking trail across Holt County, Nebraska.  It is owned by the State of Nebraska, Nebraska Game and Parks Commission (“NGP”).  A portion of The Cowboy Trail separates our Transload Facility from the nearest end of the active rail track, which is owned and operated by NENE.

The NGP has authorized our use by lease of approximately one and a half miles of the Cowboy Trail (the “Property”) on which we have constructed a rail spur to connect with the NENE rail track.  We entered into the Track Agreement with the NGP, under which we lease the portion of the Cowboy Trail property to use as a rail spur track over which we transport our ethanol.  The Track Agreement has a term of ten years and will automatically renew for additional ten year terms unless one party notifies the other at least nine months prior to the expiration date of its intention to not renew.  The annual rental cost to the Company is $10,000 for use of the Property.  Additionally, we are responsible for any public assessments respecting the maintenance or use of the Property.  The Track Agreement provides that we are responsible to maintain the track on the Property and are solely responsible for our operations on the Property and complying with applicable laws regarding our use of the Property.

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O’Neill NENE Property

NENE owns property located in the City of O’Neill, Holt County, Nebraska.  As this property approaches the center of O’Neill, Nebraska, our rail diverges off the Cowboy Trail, and runs through the center of town in an easterly direction for approximately six blocks.  We have entered into the NENE Track Agreement with NENE.  Under the NENE Track Agreement, NENE allows us to construct, maintain and operate the Track over NENE’s property.  The Track links with existing rail owned and operated by NENE.  The NENE Track Agreement has an initial term of five years and will automatically continue thereafter until terminated by either party upon 30 days’ notice.  The NENE Track Agreement may also be terminated if NENE is authorized to abandon its line which connects to the Track, or if NENE is no longer able to operate over the Track.  Under the NENE Track Agreement, we are responsible for, among other things, maintaining the Track; and NENE has agreed to provide rail service to transport our ethanol over the Track.

Item 3. Legal Proceedings.

TIF Lawsuit

In June 2007, the City of Atkinson, Nebraska ("City") issued a tax increment financing Note (the "TIF Note"), the net proceeds of which in the amount of $4,939,925 were paid to us to reimburse us for certain infrastructure improvements relating to our plant.  Repayment of the TIF Note is guaranteed by us, but was originally expected to be retired from incremental property tax revenue we pay the City, which are based on the added value of our land and buildings.  The TIF Note serves as collateral for a loan with an outstanding principal balance of $6,579,000 (the "Loan") as of December 31, 2011.  We received the net proceeds of the Loan under a Loan Agreement with the lead lending agent, Arbor Bank ("TIF Lender"), under which we loaned the proceeds to the City in exchange for the TIF Note.  This liability has been classified as a current liability, and will remain so until the resolution of the TIF Lawsuit described below.

On August 12, 2010, the TIF Lender filed a lawsuit against us in the District Court of Douglas County, Nebraska alleging that we failed to make certain payments due under the TIF Note and failed to maintain the required debt service reserve fund.  In addition, the lawsuit stated that the TIF Lender accelerated the maturity of the TIF Note.  The TIF Lender sought in the lawsuit repayment of $7,039,126 due as of August 9, 2010, plus such additional amounts as become due and owing under the TIF Note, with interest accruing after August 9, 2010 at the rate of 9.5% until the judgment is paid.  On April 20, 2011, the Court granted summary judgment in favor of the TIF Lender and issued a preliminary order finding that the Company defaulted on the TIF Loan in the amount of $6,864,000.  The order of the Court requires a hearing to determine the Company’s liability for interest and costs before a final order is issued.

We entered into a Forbearance and Standstill Agreement with the TIF Lender on June 30, 2011 (the “Forbearance Agreement”) where the TIF Lender filed for a withdrawal of hearing request and a stay of proceedings of the Suit in exchange for the Company causing certain payments to be made to the TIF Lender on the date the Forbearance Agreement pursuant to the terms of the Forbearance Agreement.  Under the Forbearance Agreement, the TIF Lender agreed to forebear from enforcing its rights until November 30, 2011 or earlier in the event of certain conditions.

On December 31, 2011, the Company and the TIF Lender, entered into the First Amendment to Loan Agreement (the “First Amendment”) and an Amended and Restated Promissory Note (the “Restated Note” and collectively with the First Amendment, the “Restated TIF Loan Agreements”) pursuant to which the parties agreed  to amend the original Loan Agreement dated June 19, 2007 (the “Original TIF Agreement”).

Pursuant to the terms of the Restated TIF Loan Agreements, the TIF Lender waived and released the defaults described in the TIF Lawsuit and all other defaults that had occurred under the Original TIF Agreement and related loan documents as of December 31, 2011.  The TIF Lender also agreed to request the Court to set aside the summary judgment granted in favor of the TIF Lender and dismiss the TIF Lawsuit with prejudice and delivered to the Company a signed Stipulation for Dismissal with Prejudice with regards to the TIF Lawsuit.  On January 12, 2012, the Court entered an Order dismissing the TIF Lawsuit with prejudice.

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NDEQ Notice of Violations

As previously reported, we received Notices of Violation (“NOV”) from the NDEQ arising from failures of emission equipment designed and installed by our design builder, Delta-T Corporation (“Delta-T”) under the Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T (the “Delta-T Contract”).  

That equipment included the plant’s regenerative thermal oxidizer (“RTO”) used to control emissions from the dryer and the CO2 Scrubber used to control emissions from the ethanol process.  The RTO had not performed according to the design specified in the Delta-T Contract, and the CO2 Scrubber failed in original compliance testing.  Equipment modifications and process adjustments were made, including chemical injection, to remediate the issue.  During the startup operations of the plant beginning in January 2009 and continuing through the date of the original compliance testing, Delta-T had operated the plant without these modifications and as a result, the Company received an NOV in January 2010 which asserted that due to the failure of the CO2 Scrubber, the Company’s operation of the plant violated the operating permit issued by the NDEQ.

Since the end of 2010, management believed it had resolved all of the operational shortfalls cited in the NOVs; however, we previously disclosed that although we believed we had resolved the matter, it was possible the NDEQ or the Nebraska Office of the Attorney General (the “AG Office”) could assess fines against us as a result of having operated the plant with the equipment before it was operating in compliance.  On January 4, 2012, the Company received a letter from the AG Office relating to the prior NOVs and assessing penalties for such violations and two additional violations for emissions related to a leaky pressure value and uncovered bolt hole and failure to observe and report visible emissions.  We have reached an agreement with the AG Office which agreement provides that we will pay a penalty of $25,000 in full satisfaction of all of the NDEQ claims.

In order to formally resolve this matter, after the parties reached the above agreement, the AG Office filed a complaint against us in the District Court of Holt County, Nebraska for the sole purpose of obtaining a Consent Decree to officially close the matter within the AG Office.  As a result, on March 7, 2012, a complaint was filed against the Company in the District Court of Holt County, Nebraska by the State of Nebraska, ex rel., and Michael J. Linder, Director of the Nebraska Department of Environmental Quality.   On March 12, 2012, the Court entered a Consent Decree accepting the agreement reached between the Company and the AG Office and a Satisfaction of Judgment was filed with the Court on March 19, 2012 in full satisfaction of all of the NDEQ claims against the Company.

Item 4. Mine Safety Disclosures

Not applicable

PART II

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

Market Information.  There is no public trading market for our Membership Units, and our Operating Agreement contains significant restrictions on the transfer of our Membership Units to ensure that the Company is not deemed a “publicly traded partnership” and thus taxed as a corporation.  Additionally, pursuant to the Operating Agreement, the Board has developed a Unit Transfer Policy which imposes conditions on the transfer of Membership Units.

Holders.  As of March 7, 2012, there were 1,057, 37 and 179 holders of record of our Common Membership Units, Class A Preferred Membership Units and Class B Preferred Membership Units, respectively.

Distributions.  Subject to the provisions of the Act, distributions are payable at the discretion of our Board of Directors as provided in our Operating Agreement.  The Board has no obligation to distribute profits, if any, to members.  We have not declared or paid any distributions on our Membership Units to date, and distributions on our Common Units are first subject to preferential distributions on our Class A Units and Class B Units.  If our financial performance and loan covenants permit, our Board of Directors will consider cash distributions at times and in

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amounts that will permit Unit holders to make income tax payments.  However, the Board may elect to retain future profits to provide operational financing for the plant, debt retirement and possible plant expansion.

Sale of Unregistered Securities.    Information with respect to equity securities of the Company sold by the Company during the period covered by this Annual Report and thereafter through the date of the filing of this Annual Report with the SEC that were not registered under the Securities Act has previously been provided in the Company’s Current Report on Form 8-K filed with the SEC on January 6, 2012.

Item 6. Selected Financial Data

Not applicable.

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

Information in response to this Item is incorporated by reference to pages 5 through 16 of the 2011 Annual Report.

Item 7A.   Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 8.    Financial Statements and Supplementary Data.

Information in response to this Item is incorporated by reference to pages F-1 through F-17 of the 2011 Annual Report.

Item 9.   Change In and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A.      Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, including our President and Chief Executive Officer (our principal executive officer) along with our Chief Financial Officer (our principal financial officer) have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amended, the “Exchange Act”), as of December 31, 2011.  Based upon this review and evaluation, these officers concluded that our disclosure controls and procedures are presently effective.

Our management, including our principal executive officer and our principal financial officer, have reviewed and evaluated any changes in our internal control over financial reporting that occurred in our fourth quarter of fiscal 2011 and there has been no change that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting.  Our internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, and effected by our Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP and includes policies and procedures that:

(i)	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our financial transactions,
(ii)	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our revenues and expenditures are being made only in accordance with authorizations of our management and directors, and

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

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

Management assessed our internal control over financial reporting as of December 31, 2011.  Management based its assessment on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Management’s assessment included an evaluation of such elements as the design and operating effectiveness of key financial reporting controls, process documentation, accounting policies and our overall control environment.

Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2011.  This annual report is not required to include an attestation report of our independent registered public accounting firm regarding our internal control over financial reporting.

Item 9B.     Other Information.

None.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

Information in response to this Item is incorporated by reference to the information under the captions “Election of Directors” and “Corporate Governance” of the 2012 Proxy Statement.

Item 11.     Executive Compensation.

Information in response to this Item is incorporated by reference to the information under the captions “Compensation of Directors and Executive Officers,” “Summary Compensation Table” and “Director Compensation” of the 2012 Proxy Statement.

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

Information in response to this Item is incorporated by reference to the information under the caption “Voting, Voting Securities and Principal Unit Holders” of the 2012 Proxy Statement.

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

Information in response to this Item is incorporated by reference to the information under the caption “Certain Relationships and Related Party Transactions” of the 2012 Proxy Statement.

Item 14. Principal Accountant Fees and Services

Information in response to this Item is incorporated by reference to the information under the caption “Independent Registered Public Accounting Firm Information” of the 2012 Proxy Statement.

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PART IV

Item 15.         Exhibits, Financial Statement Schedules

(a) Documents filed as part of this Report in Exhibit 13.1:

Balance Sheets as of December 31, 2011 and 2010

Statements of Operations for the years ended December 31, 2011 and 2010

Statements of Changes in Members' Equity for the years ended December 31, 2011 and 2010

Statements of Cash Flows for the years ended December 31, 2011 and 2010

Notes to Financial Statements

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

3(i).1	Articles of Organization and First Amendment thereto (incorporated by reference to Exhibit 3.1 of the registrant’s Registration Statement on Form SB-2, filed December 15, 2005)
3(i).2	Second Amendment to Articles of Organization (incorporated by reference to Exhibit 3 (i) of registrant’s Current Report on Form 8-K filed January 23, 2007).
4(i).1	Fifth Amended and Restated Operating Agreement dated January 1, 2012 (incorporated by reference to Exhibit 3(ii).1 to registrant’s Current Report on Form 8-K filed January 18, 2012)
4(i).2	Form of Membership Unit Certificate (incorporated by reference to Exhibit 4.1 of the Registrant’s Registration Statement on Form SB-2, filed December 15, 2005)
10.1	Amended and Restated Master Credit Agreement dated December 31, 2011 with AgCountry Farm Credit Services, FLCA (successor by merger to Farm Credit Services of Grand Forks, FLCA) (filed herewith)
10.2	First Supplement to the Amended and Restated Master Credit Agreement with AgCountry Farm Credit Services, FLCA (successor by merger to Farm Credit Services of Grand Forks, FLCA)  dated December 31, 2011 (filed herewith)
10.3	Amended and Restated Term Loan Note payable to with AgCountry Farm Credit Services, FLCA (successor by merger to Farm Credit Services of Grand Forks, FLCA)  dated December 31, 2011 (filed herewith)
10.4	Second Amendment to Deed of Trust, Security Agreement, Assignment of Leases and Rents and Fixture Financing Statement dated February 14, 2007 in favor of Lawyers Title Insurance Corporation for the benefit of AgCountry Farm Credit Services, FLCA (successor by merger to Farm Credit Services of Grand Forks, FLCA) (filed herewith)
10.5	Security Agreement dated February 14, 2007 with Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.12 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.6	Deed of Trust, Security Agreement, Assignment of Leases and Rents and Fixture Financing Statement dated February 14, 2007 in favor of Lawyers Title Insurance Corporation for the benefit of Farm Credit Services of Grand Forks, FLCA (filed herewith)
10.7	Form of Guaranty in favor of AgCountry Farm Credit Services, FCA (incorporated by reference to Exhibit 10.12 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.8	Collateral Assignment dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of AgCountry Farm Credit Services, FCA (incorporated by reference to Exhibit 10.14 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.9	Control Agreement dated April 11, 2008 between AgCountry Farm Credit Services, FCA, NEDAK Ethanol, LLC and Jerome Fagerland (incorporated by reference to Exhibit 10.15 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.10	Purchase Letter dated June 19, 2007 from NEDAK Ethanol, LLC to the City of Atkinson, Nebraska (filed herewith)
10.11	Loan Agreement dated June 19, 2007 between NEDAK Ethanol, LLC and Arbor Bank (filed herewith)
10.12	First Amendment to Loan Agreement dated December 31, 2011 between NEDAK Ethanol, LLC and Arbor Bank (filed herewith)
10.13	Amended and Restated Promissory Note dated December 31, 2011 payable by NEDAK Ethanol, LLC to Arbor Bank (filed herewith)

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10.14	Promissory Note dated June 19, 2007 made by NEDAK Ethanol, LLC in favor of Arbor Bank (incorporated by reference to Exhibit 10.5 to registrant’s Current Report on Form 8-K filed June 25, 2007)
10.15	Security Agreement dated June 19, 2007 made by NEDAK Ethanol, LLC in favor of Arbor Bank (incorporated by reference to Exhibit 10.4 to registrant’s Current Report on Form 8-K filed June 25, 2007)
10.16	Redevelopment Contract dated June 19, 2007 between NEDAK Ethanol, LLC and the City of Atkinson, Nebraska (incorporated by reference to Exhibit 10.6 to registrant’s Current Report on Form 8-K filed June 25, 2007)
10.17	Intercreditor Agreement dated December 31, 2011 between AgCountry Farm Credit Services, FLCA and Arbor Bank and Acknowledged by NEDAK Ethanol, LLC (filed herewith)
10.18+	Asset Management Agreement dated December 31, 2011 between NEDAK Ethanol, LLC and Tenaska BioFuels, LLC (filed herewith)
10.19	Assignment of Asset Management Agreement dated December 31, 2011 between NEDAK Ethanol, LLC and AgCountry Farm Credit Services FLCA (formerly Farm Credit Services of Grand Forks, FLCA) (filed herewith)
10.20+	Letter Agreement dated December 30, 2011 between NEDAK Ethanol, LLC and TNDK, LLC (filed herewith)
10.21	Precedent Agreement dated September 27, 2007 between NEDAK Ethanol, LLC and Kinder Morgan Interstate Gas Transmission LLC (incorporated by reference to Exhibit 10.2 to registrant’s Current Report on Form 8-K filed November 2, 2007)
10.22	Plant Operating Agreement dated July 11, 2007 and amended July 16, 2007, between NEDAK Ethanol, LLC and HWS Energy Partners, L.L.C.  (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed July 16, 2007).  Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.23	Base Agreement dated February 7, 2006 between NEDAK Ethanol, LLC and Cornerstone Energy, Inc. (incorporated by reference to Exhibit 10.5 of Pre-Effective Amendment No. 3 to the Registrant’s Registration Statement on Form SB-2, filed June 5, 2006)
10.24	Firm Transportation Service Agreement dated May 8, 2006 with Kinder Morgan Interstate Gas Transmission LLC (incorporated by reference to Exhibit 10.2 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.25	Ethanol Marketing Agreement dated November 15, 2006 with Eco-Energy, Inc. (incorporated by reference to Exhibit 10.3 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.26	Grain Procurement Agreement dated December 14, 2006 with J.E. Meuret Grain Co., Inc. (incorporated by reference to Exhibit 10.4 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.27	Marketing Agreement dated January 22, 2007 with Distillers Grain Services LLC (incorporated by reference to Exhibit 10.5 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.28	Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T Corporation (incorporated by reference to Exhibit 10.2 of Report on Form 10-QSB filed November 20, 2006).  Portions of the Contract have been omitted pursuant to a request for confidential treatment.
10.29	Negotiated Rate Agreement for Distribution Transportation Services dated June 5, 2006 between NEDAK Ethanol, LLC and Kinder Morgan Inc. (incorporated by reference to Exhibit 10.12 of Report on Form 10-KSB filed on April 2, 2007)
10.30	Option to Lease Real Estate Agreement dated January 15, 2007 with Dennis Grain, Inc. (incorporated by reference to Exhibit 10.13 of Report on Form 10-KSB filed on April 2, 2007)
10.31	Transportation Service Agreement on Transporter’s Distribution System dated June 15, 2006 between NEDAK Ethanol, LLC and Kinder Morgan Inc. (incorporated by reference to Exhibit 10.14 of Report on Form 10-KSB filed on April 2, 2007)
10.32	Industry Track Agreement dated July 24, 2007 between NEDAK Ethanol, LLC and the Nebraska Northeastern Railway Company (incorporated by reference to Exhibit 10.2 on Form 8-K filed July 25, 2007)
10.33	NEDAK Track Lease Agreement dated June 19, 2007 between NEDAK Ethanol, LLC and the Nebraska Game and Parks Commission (incorporated by reference to Exhibit 10.1 on Form 8-K filed June 25, 2007)

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10.34	Amendment dated March 5, 2008 between NEDAK Ethanol, LLC and SourceGas Distribution, LLC (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed March 13, 2008)
10.35	Second Letter of Commitment and Intent between NEDAK Ethanol, LLC and Delta-T Corporation dated August 4, 2008 (incorporated by reference to Exhibit 10.4 to registrant’s Current Report on Form 8-K filed August 6, 2008)
10.36	Amendment No. 3 to Engineering, Procurement and Construction Services Fixed Price Contract between NEDAK Ethanol, LLC and Delta-T Corporation dated April 11, 2008 (incorporated by reference to Exhibit 10.3 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.37	Guaranty dated April 11, 2008 made by Bateman  Litwin NV in favor of NEDAK Ethanol, LLC (incorporated by reference to Exhibit 10.9 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.38	Deed of Trust dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of Delta-T Corporation (incorporated by reference to Exhibit 10.10 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.39	Promissory Note dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of Delta T Corporation (incorporated by reference to Exhibit 10.13 to registrant’s Current Report on Form 8-K filed April 15, 2008)
10.40	Facility Agreement between NEDAK Ethanol, LLC and Kinder Morgan Inc. dated June 15, 2006 (incorporated by reference to Exhibit 10.8 to registrant’s Current Report on Form 8-K filed February 20, 2007)
10.41	Transportation Agreement between NEDAK Ethanol, LLC and Western Oil Trans Inc. dated July 19, 2007 (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed July 25, 2007)
10.42	Precedent Agreement between NEDAK Ethanol, LLC and Kinder Morgan Interstate Gas Transmission LLC dated September 27, 2007 (incorporated by reference to Exhibit 10.2 to registrant’s Current Report on Form 8-K filed November 2, 2007)
10.43	Change Orders dated October 25, 2006, November 20, 2006 and December 14, 2006 to Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T Corporation (incorporated by reference to Exhibit 10.6 to registrant’s Current Report on Form 8-K filed February 20, 2007).
10.44	Form of Amended Promissory Note made by NEDAK Ethanol, LLC in favor of certain Directors (incorporated by reference to Exhibit 10.1 to registrant’s Quarterly Report on Form 10-Q filed May 15, 2009).
10.45	Amendment Number Three to Engineering, Procurement and Construction Services Fixed Price Contract between Delta-T Corporation and NEDAK Ethanol, LLC (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed September 4, 2009).
10.46	Settlement Agreement and Mutual Release Between Delta-T Corporation, Bateman Engineering Inc., Bateman-Litwin N.V. and NEDAK Ethanol, LLC entered on March 19, 2010 (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed March 24, 2010).
10.47*	Employment Agreement dated October 30, 2007 between NEDAK Ethanol, LLC and Jerome Fagerland  (incorporated by reference to Exhibit 10.1 to registrant’s Current Report on Form 8-K filed November 2, 2007)
13.1	Annual Report to Security Holders (filed herewith)
14.	Code of Ethics (incorporated by reference to Exhibit 14 to registrant’s Annual Report on Form 10-KSB filed April 2, 2007).
31.1	Rule 13a-14(a)/15d-14(a) Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by Chief Executive Officer. (filed herewith)
31.2	Rule 15d-14(a) Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by Chief Financial Officer. (filed herewith)
32.1.**	Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Chief Executive Officer. (furnished herewith)
32.2**	Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Chief Financial Officer. (furnished herewith)
101.XML  XBRLInstance Document (filed herewith)
101.XSD   XBRL Taxonomy Schema (filed herewith)

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101.CAL  XBRL Taxonomy Calculation Database (filed herewith)

101.LAB  XBRL Taxonomy Label Linkbase (filed herewith)

101.PRE   XBRL Taxonomy Presentation Linkbase (filed herewith)

101.DEF  XBRL Taxonomy Definition Linkbase (filed herewith)

+ Material has been omitted from this exhibit pursuant to a request for confidential treatment pursuant to Rule 24b-2 promulgated under the Securities and Exchange Act of 1934 and such material has been filed separately with the Securities and Exchange Commission.

* Denotes exhibit that constitutes a management contract, or compensatory plan or arrangement.

** This certification is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference.

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 SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NEDAK ETHANOL, LLC

By:	/s/ Jerome Fagerland
	Jerome Fagerland, President and Chief Executive Officer
	(Principal executive officer)
Date:	March 30, 2012
By:	/s/ Timothy Borer
	Timothy Borer
	(Principal financial officer and principal accounting officer)
Date:	March 30, 2012

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Name	Date	Name	Date
/s/ Jeff Lieswald	March 30, 2012	/s/ Todd Shane	March 30, 2012
Jeff Lieswald, Director		Todd Shane, Director
/s/ Kirk Shane	March 30, 2012	/s/ David Neubauer	March 30, 2012
Kirk Shane, Director		David Neubauer, Director
/s/ Everett Vogel	March 30, 2012	/s/ Richard Bilstein,	March 30, 2012
Everett Vogel, Director, Chairman of the Board, Vice President		Richard Bilstein, Director, Vice Chairman of the Board
/s/ Kenneth Osborne	March 30, 2012	/s/ Robin Olson	March 30, 2012
Kenneth Osborne, Director		Robin Olson, Director
/s/ Clayton Goeke	March 30, 2012	/s/ Steve Dennis	March 30, 2012
Clayton Goeke, Director		Steve Dennis, Director
/s/ Paul Corkle	March 30, 2012	/s/ Todd Jonas	March 30, 2012
Paul Corkle, Director		Todd Jonas, Director
/s/ Jerome Fagerland	March 30, 2012	/s/ Timothy Borer	March 30, 2012
Jerome Fagerland, Director, President and Chief Executive Officer (principal executive officer)		Timothy Borer, Director (principal financial officer and principal accounting officer)

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