UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 0-50714

Western Plains Energy, L.L.C.

(Exact name of registrant as specified in its charter)

Kansas		48-1247506
(State or other jurisdiction of		(I.R.S. Employer Identification No.)
incorporation or organization)

3022 County Road 18, Oakley, Kansas		67748
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (785) 672-8810

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Class A Capital Units

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

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

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

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

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

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

Large accelerated filer o		Accelerated filer o

Non-accelerated filer ¨		Small reporting company x

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

The aggregate market value of the capital units held by non-affiliates of the registrant as of March 31, 2010 was $44,690,000, computed by reference to the price at which membership units were last sold prior to that date. There is no established public trading market for our securities.

As of December 23, 2010, 16,002 Class A Capital Units, 12,068 Class B Capital Units and 350 Class C Capital Units of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

Table of Contents

TABLE OF CONTENTS

		Page
	PART I

ITEM 1:	BUSINESS	1
ITEM 1A:	RISK FACTORS	9
ITEM 1B:	UNRESOLVED STAFF COMMENTS	13
ITEM 2:	PROPERTIES	13
ITEM 3:	LEGAL PROCEEDINGS	14
ITEM 4:	RESERVED	14

	PART II

ITEM 5:	MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	14
ITEM 6:	SELECTED FINANCIAL DATA	15
ITEM 7:	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
ITEM 8:	FINANCIAL STATEMENTS	24
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	37

ITEM 10:	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	37
ITEM 11:	EXECUTIVE COMPENSATION	40
ITEM 12:	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	41
ITEM 13:	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	42
ITEM 14:	PRINCIPAL ACCOUNTING FEES AND SERVICES	43

	PART IV

ITEM 15:	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	43

	SIGNATURES	44

	EXHIBIT INDEX

Additional Information

Descriptions in this report are qualified by reference to the contents of any contract, agreement or other document described herein and are not necessarily complete. Reference is made to each such contract, agreement or document filed as an exhibit to this report, or incorporated by reference as permitted by regulations of the Securities and Exchange Commission (“SEC”). For more information regarding these documents, see the section titled “Exhibits” in this report.

Special Note Regarding Forward-Looking Statements

Please see the note under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of special factors potentially affecting forward-looking statements included in this report.

Table of Contents

PART I

Item 1. Business.

Overview.

Our business focuses on the production and sale of ethanol and its co-products. Ethanol is a type of alcohol which in the United States, which we refer to as the U.S., is typically produced from corn, but may be produced from other grains and biomass. Ethanol is primarily used as a blend component for gasoline, and is typically added by refiners or distributors to increase octane and reduce tailpipe emissions from vehicles. The ethanol industry in the U.S. experienced significant growth between 2003 and 2008. However, during 2009, ethanol production decreased due to the overall economic downturn and diminishing profit margins. According to the Renewable Fuels Association (“RFA”), production capacity during 2010 in the U.S. has increased to 13.4 billion gallons annually from 190 operating plants. We believe that E85 and other gasoline blends greater than 10% (see “Our Products and Their Markets,” below) will also become increasingly important over time as an alternative to unleaded gasoline. We produce a small percentage of the ethanol sold annually in the U.S.

We produce fuel grade ethanol at our plant located in Gove County, Kansas by processing corn and milo by utilizing what is known as “dry-milling” technology. The grain is received by semitrailer truck, weighed and cleaned of rocks and debris before it is conveyed to storage silos. The grain is then transported to a hammer mill or grinder where it is ground into flour and conveyed into a slurry tank for processing. We add water, heat and enzymes to break the ground grain into a mash. The mash is heat sterilized and pumped into a tank where other enzymes are added to convert the starches into glucose sugars. Next, the mash is pumped into one of five fermenters, where yeast is added to begin a 48 to 55 hour batch fermentation process. A distillation process vaporizes the alcohol from the mash. The alcohol is further dried in a rectifier and molecular sieve. The resulting 200 proof-alcohol is then pumped to shift tanks and blended to achieve a mixture consisting of approximately 97.8% ethanol and 2.2% gasoline as it is pumped into denatured ethanol storage tanks.

Grain mash exiting the distillation process is pumped into one of several centrifuges. Water from the centrifuges, called thin stillage, is condensed into a thicker syrup called condensed solubles. The solids that exit the centrifuge are called distillers wet grains (“WDGS”). The majority of these distillers wet grains are sold in that form and a portion are subsequently dried and mixed with condensed solubles to produce distillers grains with solubles, which may be used as animal feed and are known as distillers dry grains (“DDGS”). See “Our Products and Their Markets,” below. During our 2010 fiscal year, which ended September 30, 2010, we produced 49,013,332 gallons of fuel grade ethanol, 368,313 tons of WDGS and 14,491 tons of DDGS.

History.

We were organized as a Kansas limited liability company in 2001. We completed the initial public distribution of our membership units in 2003, raising proceeds of $19,330,000. In 2008, we declared a forward split of our outstanding units on a seven (7) for one (1) basis.

We constructed our facility, located in western Kansas, during 2003 and began production of ethanol in January 2004. Our initial nameplate (estimated) production capacity was 30 million gallons of ethanol per year. During our 2005 fiscal year, we completed construction of an expansion of our facility to give us nameplate capacity of 40 million gallons of ethanol per year. During our 2007 fiscal year, we completed capital improvements to our plant giving us increased storage capacity for grain which enables us to further manage our increased production capacity. During our 2010 fiscal year, we added a fifth fermenter and made several improvements to our process system in the plant. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.

Recent Developments.

During 2010, we continued to focus on improving our ethanol production process and strengthening our position as a low cost ethanol producer. We installed a fifth fermenter at our plant to provide our product a longer residence time during production. We also upgraded our energy center and certain processing equipment. Although our intent was not necessarily to increase our plant’s nameplate capacity, our improvements resulted in a slight increase in our production without additional input. We have continued to research and explore new technologies and production methodologies that affect various aspects of the production process.

Over the past year, the ethanol industry continued the very slow recovery from the effects of the financial crisis which began in late 2008. There have been no significant new announcements regarding new construction projects. The vast majority of the production capacity that was idled in 2009 came back online, along with the completion of some construction projects to add a small amount of new capacity, in late 2010. Even with this added production capacity, the recovery has lagged. The amount of capacity in

Table of Contents

the ethanol industry today is very close to the mandated levels provided in the Energy Independence and Security Act of 2007, which we refer to as EISA. We think the growth rate of the ethanol industry will much more closely match these requirements as we move into the future.

Consolidation in the industry has been widespread, as assets of bankrupt entities have been acquired by healthier companies from both inside the ethanol industry as well as the petroleum industry. A few large ethanol producers expanded their businesses by acquiring additional ethanol plants in new markets. Additionally, there have been numerous purchases of stressed ethanol assets by companies in the petroleum industry. Valero, Murphy Oil, Flint Hills Resources, and Sunoco are all examples of petroleum companies acquiring ethanol companies in order to fulfill their ethanol blending requirements under EISA as well as to diversify their refining operations.

The availability of credit remains an issue for weaker companies as a result of the severe downturn experienced by U.S. financial markets beginning in 2008. A contraction in the local, national and global economies resulted from this downturn. This situation, coupled with increased production capacity in our industry, caused a wide array of businesses, including some of our competitors, suppliers and customers, to experience difficulty in continuing operations. We believe our conservative business model and lack of debt place us in a very favorable position in the market as we continue through this recovery period.

One bright spot for the industry was the recent approval by the United States Environmental Protection Agency, which we refer to as the EPA, of the use of gasoline blended with 15% ethanol, or E15, as fuel in vehicles manufactured in 2007 or later. The blend rate for gasoline was originally capped at 10% ethanol. The waiver for newer vehicles to use E15 will likely increase domestic demand for ethanol for blending purposes.

Although the markets seem to be stabilizing following the financial crisis, the demand for fuels on a global scale remains repressed. The ethanol industry appears to have stabilized and moderate profitability has returned to the industry in general. However, the uncertainty concerning recovery in the financial system and its lasting effects requires us to take a conservative view of the marketplace moving forward.

Our Competitive Strengths.

Plant technology and efficiency. At September 30, 2010, our plant was producing ethanol at or above nameplate capacity, primarily due to capital improvements we made in addition to our plant expansion. We have continued to focus on finding ways to improve the production process and will upgrade equipment as necessary in order to achieve maximum production goals. We believe we will continue to compete as a low-cost producer of ethanol in the future, due to the improved efficiency from our equipment upgrades. We continue to focus upon per gallon improvements to costs on all inputs, targeting larger gross operating margins.

For the past several years, we have utilized a variety of corn developed by a major seed company which contains an enzyme required in our ethanol production process. In fiscal 2010, we refined and optimized the technology for use within our production process. We believe this technology holds a great deal of promise for our operating efficiencies. The United States Department of Agriculture, which we refer to as the USDA, continues to review the technology to possibly deregulate its use. If deregulated, we are positioned favorably to use the technology on a commercial scale.

Absence of significant debt. The term loans related to the original construction of our plant as well as the expansion project completed during fiscal 2005 were paid in full at June 2006. While we maintain a revolving line of credit, the absence of term debt positions us favorably vis-a-vis other competitors who have long-term debt and who are required to service that debt from operations. As a result of our reduced leverage, we may be less sensitive to fluctuations in revenue as a result of changes in the price of ethanol or the costs of our raw materials as compared to similarly-situated ethanol plants that are required to make payments under long-term debt contracts. Additionally, our cash flow allows us to have more flexibility in determining how to use working capital.

Plant expansion and improvements. We expanded the nameplate capacity of our ethanol plant in fiscal 2005 to 40 million gallons per year. The expansion included, among other things, a 750,000 gallon beer well, expansion of our existing cooling towers by one cell, a new cooling pump, a new style burner and a new centrifuge. The expansion was built on our existing plant site and did not require the acquisition of any additional property. Our expansion was placed into service during the second quarter of fiscal 2005. In 2006 and 2007, we also increased our grain storage capacity by approximately 1.5 million bushels by purchasing the grain elevator adjacent to our plant and constructing two 250,000 bushel grain bins. We believe our increase in production and storage capacity positions us favorably in the marketplace and provides increased operating flexibility. Additionally, a fifth fermenter was added during fiscal 2010 as well as certain upgrades in our energy center and process equipment. The addition of the fermenter was intended to increase the operating efficiency of the existing fermenters by lengthening the amount of residence time of our product per fermenter and also resulted in the increase in nameplate capacity. The results of the added fermenter were very much as expected.

Table of Contents

Additionally, as per gallon margins for ethanol increased, we were able to produce more ethanol without losing the gained efficiencies. The upgrades to the energy center and process equipment are intended to increase efficiency and safety.

Proximity to grain. The proximity of our plant to producers of the grain we utilize to produce ethanol favors us over some of our competitors. Local growers generally produce more than enough grain to meet our requirements, and the close proximity for delivery can result in competitively favorable prices for us. Additionally, many local grain producers are members of our company who supply us at competitive prices.

Our Products and Their Markets.

Ethanol. We produce ethanol to be used as a fuel component that serves as:

· An octane enhancer in fuels;

· An oxygenated fuel additive that can reduce carbon monoxide vehicle emissions; and

· A non-petroleum-based gasoline extender.

Ethanol in its primary form is mostly used for blending with unleaded gasoline and other fuel products. The implementation of the federal Clean Air Act has made ethanol fuels an important domestic renewable fuel additive. According to the American Coalition for Ethanol, approximately 70% of all gasoline sold in the U.S. is blended with ethanol. Most of the ethanol is blended as E10, a mixture of 10% ethanol and 90% petroleum gasoline. This fuel is covered by warranty for use in all makes and models of vehicles. Some ethanol is blended as E85, a mixture of 85% ethanol and 15% gasoline. This mixture is used in flexible fuel vehicles (“FFVs”), which are increasingly available to consumers as auto companies produce more FFV models. Recently, the EPA approved the use of gasoline with a 15% blend of ethanol for all vehicles manufactured in 2007 and later following studies using higher than 10% blend of ethanol in these vehicles. The EPA is currently conducting additional testing that could extend the 15% blend to vehicles manufactured after 2001. In our opinion, if the EPA approves the 15% blend for the older vehicles, there will be a modest but important increase in demand for ethanol for blending purposes. Used as a fuel oxygenate, ethanol provides a means to reduce carbon monoxide vehicle emissions.

The principal purchasers of ethanol are generally the refined and wholesale gasoline marketer or blender. The principal end markets for our ethanol are petroleum terminals primarily on the east and west coasts of the U.S. During our 2010 fiscal year, 84% of our net revenue was derived from the sale of ethanol, and we expect the sale of ethanol to comprise a substantial majority of our revenue in the future. The remainder of our revenue is derived from the sale of distillers grains, discussed in more detail below.

Distillers Grains. A principal co-product of the ethanol production process is distillers grains, which is a high-protein, high-energy animal feed supplement primarily marketed to the dairy and beef industry. By using the dry-milling ethanol production process with a dryer system that can produce two moisture levels, we are able to produce both WDGS and DDGS. WDGS are processed grain mash and condensed solubles that contain approximately 65% moisture. It has a shelf life slightly longer than three days and is sold to markets in proximity to our plant. DDGS are mash that has been dried to 10% moisture. It has an almost indefinite shelf life and is sold and shipped via truck or railcar to many markets regardless of their vicinity to our ethanol plant. During the 2010 fiscal year, approximately 16% of our net revenue was derived from the sale of distillers grains, and we expect the sale of distillers grains to continue to comprise a minority of our revenue in the future as compared to our revenue from ethanol.

The demand for meat products during fiscal 2009 reduced the number of animals being maintained on feed. As a result, demand for distillers grains decreased from fiscal 2009. In recent months, demand has slowly risen as the effects of the financial crisis of 2009 have somewhat stabilized. The number of animals being placed on feed saw steady increase in fiscal 2010. We anticipate this trend to continue into fiscal 2011.

Raw Materials.

Grain Procurement. Ethanol in the U.S. is made primarily from grain, principally corn. We have the advantage of having access to and the ability to utilize sorghum or milo, the latter of which we often can obtain at a lower price than corn. During the 2010 fiscal year, we used approximately 17.8 million bushels of corn and milo to produce ethanol. We obtained a majority of this grain from producers in western Kansas, where our plant is located. We have agreements with several local producers and grain elevators to acquire grain at a contracted rate tied to “spot” prices established on CBOT upon delivery to our plant.

We believe that grain producers in proximity to our plant will produce sufficient grain for our needs for the foreseeable future. In the event such producers are unable to fulfill our requirements, we believe an adequate supply is available from producers in other states, such as Nebraska and Colorado.

Table of Contents

The increase in the number of ethanol plants in the nation that was adversely affecting the availability and price of corn, milo and other grain products during fiscal 2008 stabilized during fiscal 2009. As a result, the pressure on local grain markets was greatly reduced which allowed for a greater supply of grains in the local market during fiscal 2010. According to the RFA, the number of ethanol plants producing fuel grade ethanol in the U.S. increased to 190 during fiscal 2010, which brings current total production capacity in the U.S. to 13.4 billion gallons annually.

We enter into hedging transactions in an effort to stabilize the price that we pay for grain. Hedging involves the acquisition of option and futures contracts, designed as hedges of specific volumes of grain expected to be used in our production process. We also use derivative financial instruments to manage the exposure to price risk related to grain purchases. At September 30, 2010, we had open long and short positions in option contracts, which positions were recorded in our financial statements at fair value. As a result, we recorded $239,348 of unrealized losses for the year ended September 30, 2010 with respect to option and future contracts.

Production processes using feed stocks other than grain to make ethanol are continually being developed. We expect to continue to focus our production using grain for the foreseeable future. However, we are monitoring the developments in the industry regarding the economic viability of alternative feedstocks and may consider converting from grain-based ethanol at some future date.

The price and availability of corn and milo are subject to significant fluctuations depending upon a number of factors which affect grain commodity prices in general, including crop conditions, pestilence, weather, supply and demand, speculation, government programs and foreign purchases. Ethanol prices are becoming more tied to the price of the grain used to produce it,yet ethanol producers are generally still not able to compensate for increases in the cost of grain through adjustments and prices charged for ethanol because the marginal increase on grain tends to be higher than the resulting marginal increase on ethanol prices. For example, if average corn prices increase by $0.03, we may see average ethanol prices increase by $0.01. The price for distillers grains also tends to track with corn prices, and generally we are able to increase the price we charge for our distillers grains concurrent with increased corn prices.

The overall volatility of grain prices eased in fiscal 2010. Although grain prices trended upward in fiscal 2010 compared to the previous year, they did not move as dramatically as in the prior years. For a more detailed discussion, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.

The ability to purchase and store large quantities of grain helps us manage our grain costs. We completed an expansion of our storage facilities in 2007 and the new storage capacity enables us to take advantage of lower grain prices by allowing us to acquire a significant portion of our requirements during times when prices are favorable. In addition, we completed our fourth grain receiving pit and related conveyance equipment to enhance our grain receiving ability from the local farmers during the corn and milo harvests. Construction of the receiving pit was completed just prior to the start of the fall harvest.

Drought and other environmental occurrences could adversely affect the production and availability of corn, milo and other grain products in the future. Because of its relative aridity, the western United States is more susceptible to drought than certain other areas of the country. Although locally we have enjoyed above or near average precipitation the past two crop years, fall 2010 has been drier than normal. If this trend continues in fiscal 2011, it could have an adverse affect on crop yields and consequently increase the cost of our feedstock.

All of the corn and milo we purchase is tested and must meet high quality control standards to ensure the efficient operation and quality production of our plant. We use the USDA’s grade requirements for U.S. Number Two Corn and U.S. Number Two Grain Sorghum. From time to time, we also accept grain that does not meet the criteria for U.S. Number Two Corn or U.S. Number Two Grain Sorghum or is otherwise substandard. When we do, we discount the price or make other allowances to account for the lesser grade quality or condition at delivery.

Other Raw Materials. The other critical raw materials for the production of ethanol are water and natural gas. Water is mixed with the processed grain to begin the fermentation process. Natural gas is used to heat the resulting mixture in conjunction with the fermentation process.

An adequate supply of water is important to our ethanol business. We currently have water wells to the north and east of our plant site from which we pipe water to our facility. We believe that we have sufficient water to operate our plant. However, should we require more water, we believe that we can obtain it from the existing wells on our property. See “Item 2. Properties.” We have received all necessary permits to obtain water and believe that we currently are operating in compliance with all regulations of the Kansas Department of Agriculture, Division of Water Resources.

In order to be assured of a steady source of natural gas, we entered into a Natural Gas Service Agreement with Midwest Energy, Inc. (“Midwest”) in September 2003 pursuant to which they deliver natural gas to our plant. We purchase the gas from

Table of Contents

another third party. This agreement supplements a previous agreement with Kinder Morgan Energy Partners and Kinder Morgan Interstate Gas Transmission LLC to deliver the gas to Midwest. In exchange for our agreement not to bypass its local gas distribution system, Midwest agreed to install and maintain a gas main directly to our property in Gove County, Kansas. We pay a monthly charge based on the amount of gas utilized each month. The rates were fixed through December 31, 2008, and are subject to change thereafter based on increases or decreases applicable to distribution services generally and subject to review by the Kansas Corporation Commission. Our contract with Midwest has been extended through December 31, 2013.

We also contract with Post Rock Gas, LLC (“PRG”) to acquire the gas that is transported by Midwest to our plant. Our agreement with PRG commenced in December 2003 and is terminable by either party on not less than 30 days’ advance notice. The price we paid for gas during the 2010 fiscal year was determined by reference to a published “spot” price. We believe our agreements with PRG, Kinder Morgan and Midwest will provide an ample supply of natural gas for the foreseeable future.

Our agreement with PRG helps us manage our risk from natural gas price fluctuations. Due to uncertainty in gas prices, we periodically evaluate our gas requirements and expectations of future prices and may purchase forward contracts and implement derivative instruments on a portion of our requirements to allow us to benefit in the event natural gas prices decline. In fiscal 2010, other than the traditional winter month increases, prices were stable and trended lower through the year. We showed realized losses on natural gas hedges of $431,660 for fiscal 2010. We currently have no contracts in place for natural gas for fiscal year ending September 30, 2011.

We have entered into an agreement with U.S. Energy Service, Inc. under which U.S. Energy Service provides consulting services to us to help us manage our energy use and costs. The agreement was effective through August 31, 2010 and automatically renewed through August 31, 2011. The agreement will renew for additional one-year terms unless terminated by either party with 30 days advance notice.

Customers.

We sell essentially all of our products to two marketing firms, which in turn sell to other purchasers. We have executed an exclusive marketing agreement to market the ethanol produced at our plant with Ethanol Products LLC d/b/a POET Ethanol Products (“POET-Ethanol Products”) of Wichita, Kansas. Under the terms of the agreement which commenced February 1, 2009, POET-Ethanol Products has agreed to purchase all of the ethanol that is produced at our plant and is solely responsible for determining the price and terms at which the ethanol acquired from our plant is sold and to whom it will be sold. The administrative fee paid to POET-Ethanol Products will equal 1% of the net-back sales price per gallon of ethanol sold. The agreement is for a five-year term and is automatically renewable for subsequent five-year terms unless terminated by either party prior to expiration. In the event that our relationship with POET-Ethanol Products is interrupted for any reason, we believe that we would be able to locate another entity to market our ethanol. However, any interruption could temporarily disrupt the sale of our principal product and adversely affect our operating results.

We have also executed an exclusive agreement to market all of our distillers grains with United Bio Energy Ingredients, LLC (“UBE”). Under the terms of that agreement, we receive the gross selling price of all distillers grains sold by UBE, less applicable transportation costs and a fee of 2-2 1/2 % of the gross selling price depending on whether we sell DDGS or WDGS. The agreement with UBE expires September 30, 2011 and is automatically renewed each year thereafter unless the agreement is terminated by either party following 90 days advance written notice. As with the marketing arrangement with POET-Ethanol Products, any interruption in our relationship with UBE could temporarily affect our business, although we believe that we could find another entity to market our grains.

Transportation and Delivery.

The grain that we receive is delivered by trucks. Due to our proximity to Interstate 70, transportation to and from the plant is efficient. Distillers grains are transported exclusively by semitruck. UBE, as our exclusive purchaser of distillers grains, selects the carrier.

Our plant was designed with a rail spur and connection to the Union Pacific railway system, which facilitates transporting our ethanol to national markets. Our plant is also located adjacent to Interstate 70. We ship our ethanol by rail and by truck, determined with reference to a review and analysis of the geographic destination, current market conditions, transportation costs and applicable environmental regulations. The target for rail-transported ethanol includes the State of California, the southwest and eastern United States. Ethanol targeted for more proximate markets is transported by truck.

Table of Contents

Legislation and Federal and State Supports or Subsidies.

Legislation. Existing federal legislation will likely maintain or enhance the use of ethanol as a fuel additive for the foreseeable future. The Energy Policy Act enacted in 2005 established the first ever Renewable Fuel Standard (“RFS”) in federal law which mandated certain levels of usage of biofuels in the domestic fuel supply beginning in 2006 and continuing through 2012. In December 2007, EISA was enacted which extended the mandates of the EPA. This legislation further increased the amount of mandated biofuel usage to a maximum of 36 billion gallons a year by 2022. For illustration purposes, the U.S. domestically produced approximately 9 billion gallons of fuel ethanol in 2008. Pursuant to the Energy Policy Act and EISA, the EPA has promulgated rules requiring refineries, blenders, distributors and importers to introduce or sell volumes of biofuels, including corn-based ethanol and biodiesel fuel, into commerce in accordance with the annual RFS. The following table describes minimum biofuel use mandated for years 2010 through 2015:

Year		Biofuel usage (in billions of gallons)
2010		12.95
2011		13.95
2012		15.20
2013		16.55
2014		18.15
2015		20.50

Under the RFS as modified by EISA, the mandate for corn-based ethanol is capped at 15 billion gallons in 2015 and continues at that level through 2022. The remaining amount of biofuel required by the RFS must be derived from non-corn-based ethanol.

The EPA is currently reviewing a request to allow for blending of up to 15% ethanol into gasoline for normal use. In October 2010, the EPA did grant a partial waiver allowing E15 to be used in vehicles manufactured in 2007 and later. The EPA has indicated they will rule on the compatibility of E15 in vehicles manufactured in 2001 and later sometime before January 2011. Although so far the EPA has only granted partial waivers for use of E15 in U.S. vehicles, these actions could positively impact demand for ethanol as E15 may partially replace E10 as the base blend of ethanol in the nation’s fuel supply. Additionally, the EPA is in the process of promulgating rules in connection with the implementation of EISA.

The American Jobs Creation Act of 2004 contained the Volumetric Ethanol Excise Tax Credit (“VEETC”). This law amended the federal gasoline excise tax structure effective January 1, 2005. As amended, the law creates a new volumetric ethanol excise tax credit of $0.46 per gallon of ethanol blended into unleaded gasoline. The credit provided by VEETC replaced an exemption which allowed ethanol blended fuel to be taxed at a lower rate than regular gasoline. The use of ethanol as a fuel additive is enhanced by the availability of a credit from the federal gasoline excise tax. The credit is scheduled to expire at the end of 2010. An extension of the VEETC through 2011 was included in the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 recently adopted by Congress and signed by the president. If the VEETC expires after 2011, the likelihood of discretionary blending of ethanol beyond the volumes mandated under EISA become much more unclear.

In addition to the legislation discussed above, ethanol sales have been favorably affected by other legislation, including the Clear Air Act Amendments of 1990, particularly the federal oxygenation program, which became effective November 1, 1992. The program requires the sale of oxygenated motor fuels during the fall and winter months in certain major metropolitan areas to reduce carbon monoxide pollution. Ethanol use also has increased due to a second Clean Air Act program, the Reformulated Gasoline Program (“RFG”). This program became effective January 1, 1995, and requires the sale of reformulated gasoline in certain major urban areas to reduce pollutants, including those that contribute to ground level ozone, better known as smog. Under new rules expected to be implemented by the EPA in December 2010, the number of large metropolitan areas that may be required to transition to RFG may increase by as many as 50 cities.

The use of ethanol as an oxygenate to blend with fuel to comply with federal mandates also has been aided by federal tax policy. The Energy Tax Act of 1978 exempted ethanol blended gasoline from the federal gas tax as a means of stimulating the development of a domestic ethanol industry and mitigating the United State’s dependence on foreign oil. As amended, the federal gasoline tax credit currently allows the market price of ethanol to compete with the price of domestic gasoline. Although the federal tax credit is not directly available to us, it allows us to sell our ethanol at prices that are competitive with other less expensive additives and gasoline.

In some states, fuel grade ethanol typically sells for a higher price per gallon than wholesale gasoline because of the aforementioned federal gasoline tax credit. Historically, fuel grade ethanol prices also have reflected a premium due to the oxygenate and octane enhancing properties of this motor fuel additive.

Federal Ethanol Supports. A federal tax credit for small ethanol producers is generally available to our company and its members. Eligibility to receive the credit is based upon plant capacity. The Energy Policy Act increased the capacity limit from 30

Table of Contents

million to 60 million gallons of production. Ethanol producers that qualify for the credit can deduct from their federal income tax $0.10 per gallon on the first 15 million gallons produced annually. We also qualify for a new federal subsidy available to biofuel producers known as the Advanced Biofuel Payment Program. The program was instituted during 2009 and provides a total of $25,000,000 for allocation among U.S. biofuel producers. We qualify for the program as a result of our use of milo as our feedstock from time to time. We received payments from the federal programs during fiscal 2010 totaling $1,073,704, of which $700,000 was accrued and recorded as income during fiscal 2009. Subsequent to our 2010 fiscal year end, we received an additional payment of $374,079 which will be recorded as income in the first quarter of fiscal 2011.

Due to the pass-through nature of our partnership taxation structure, we expect the tax credit will be passed through to our members. However, the amount of any such credit received by our members must also be included in his or her gross income, which could result in taxation on the amount of the credit passed through to the member. Also, the use of the credit by our members may be limited, so each member should consult his or her tax advisor. This tax credit and the biofuel production payments may foster additional growth in ethanol plants of a larger size and increase competition in this particular plant size category.

State Ethanol Supports. The State of Kansas provides an incentive payment to ethanol producers. The production incentive available to Kansas ethanol producers that commence production after July 1, 2001 and sell at least 5 million gallons consists of a direct payment of $0.075 per gallon for up to 15 million gallons per year. Accordingly, the maximum amount a Kansas ethanol producer can currently receive in a year is $1,125,000. These incentive payments are available for the first seven years of production. The available statewide funding for these incentive payments is $3.5 million per year for 2005-2011 plus any excess balance carried over from the prior year’s current production account. Any shortfall in the available funds will result in a pro rata decrease in the incentives paid to the individual ethanol producers. Because the number of ethanol plants participating in the program increased, the maximum amount available to us during fiscal 2010 and 2009 was subject to proration. During the 2010 and 2009 fiscal years, we were entitled to $514,860 and $131,601, respectively. We received a payment of $514,860 from the state program in August 2010.

We are unable to predict what effect, if any, expiration or termination of federal and state subsidies will have on the market or price for our ethanol in the future. However, either event may adversely affect our business. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information relating to supports and subsidies.

Environmental Matters.

The construction and expansion of our plant required various state and local permits to comply with existing governmental regulations designed to protect the environment and worker safety. While we are also subject to regulations on emissions by the EPA, current EPA rules did not require us to obtain any permits or approvals in connection with the construction of our plant or operation of our business. Additional expenditures which may be required to achieve or maintain compliance with future laws and more stringent standards for environmental matters may also limit our operating flexibility.

Our ethanol production requires us to emit a significant amount of carbon dioxide into the air. Current Kansas law regulating emissions does not restrict or prevent us from emitting carbon dioxide gas into the air, but this could change in the future. However, the EPA has promulgated National Emissions Standards for Hazardous Air Pollutants (“NESHAP”), under the Clean Air Act and it could apply to our facility if the emissions of hazardous air pollutants exceed certain thresholds. If our facility is authorized to emit hazardous air pollutants above the threshold level, then we are required to comply with NESHAP for our manufacturing process and would be required to come into compliance with another NESHAP standard applicable to boilers and process heaters. We could also be subject to environmental or nuisance claims from adjacent property owners or residents in the area based on foul smells or other air or water discharges from the plant.

California has implemented a low-carbon fuel standard that impacts the amount carbon content permissible in ethanol for blending in fuel available for sale within the state. Beginning January 1, 2011, California fuel refiners and marketers will be required to meet the standard, under which the allowable amount of carbon content in fuel available for sale will progressively decrease. Under California’s program, different types of fuel are assigned a “carbon value” based upon the perceived amount of carbon emitted during the production, transportation, and consumption of the fuel in California. To the extent our ethanol is assigned a higher carbon value, it will negatively impact our ability to sell ethanol to fuel refiners in California in the future. California is currently considering certain amendments that could reduce the carbon value of Midwestern produced corn ethanol which would likely allow us to retain these California markets, however, it is uncertain at this time whether these amendments will be approved.

We obtained what we believe are all the necessary air and water permits to operate our plant before we commenced operations, including a permit to discharge wastewater from our plant. Under normal conditions, our plant utilizes a closed system and will not discharge process wastewater, but we obtained a permit to discharge wastewater in case of emergency failure of our wastewater treatment equipment. We also obtained a permit to discharge water used in our cooling tower and boiler.

Table of Contents

In addition to the foregoing regulations affecting air and water quality, we are subject to regulation for our fuel storage tanks. If we are found to have violated federal, state or local environmental regulations in the future, we could incur liability for clean-up costs, damage claims from third parties and civil or criminal penalties that could adversely affect our business.

Competition.

We are in direct competition with numerous other ethanol producers, many of which have greater resources than we do. According to the Kansas Association of Ethanol Processors, 12 producers in the State of Kansas have the capacity to produce approximately 519.5 million gallons of fuel grade ethanol annually and additional ethanol production facilities are currently under construction. Currently, there are 190 producing ethanol plants in the U.S. with a total capacity of approximately 13.4 billion gallons annually, according to the RFA. Our ethanol plant competes with other ethanol producers on the basis of price and, to a lesser extent, delivery service. We believe we can compete favorably with other ethanol producers due to our proximity to ample corn and milo supplies at competitive prices.

Several large ethanol producers are structured as corporations and have securities which are publicly traded on a national securities exchange. These producers may have an advantage over us with respect to access to capital, as it is typically easier to obtain additional financing as a publicly traded company. While we are required to file reports with the SEC, our securities are presently not traded on an exchange, thus we may have more limited access to capital markets.

The largest ethanol producers include Abengoa Bioenergy Corp., Archer Daniels Midland Company, Aventine Renewable Energy, LLC, Cargill, Inc., Hawkeye Renewables, LLC, and New Energy Corporation, all of which are capable of producing more ethanol than we produce. Producers of this size may have an advantage over us from economies of scale and negotiating position with purchasers. In addition, there are many regional, farmer-owned entities recently formed, or in the process of formation, of a similar size and with similar resources to ours. Most ethanol plants also produce distillers grains.

Technological advances in and government initiatives for using biomass in lieu of grain to produce ethanol, known as cellulosic ethanol production, will create additional competitors to our business in the future unless we were to convert our operations from traditional grain based production to cellulosic production. Across the U.S., construction of several new production facilities is underway to take advantage of the rapidly commercializing technologies that utilize alternative feedstocks to produce ethanol. The forms of feed stock for cellulosic ethanol production include algae, wood chips, switch grass and various plant wastes.

We may also compete with international ethanol producers from countries such as Brazil, who may at times have lower production costs and comparable transportation costs to coastal markets and countries like Costa Rica and El Salvador and others subject to favorable tariff treatment by the U.S. under the Caribbean Basin Initiative.

We also compete with non-ethanol oxygenates which may cost less to produce than ethanol. Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development by ethanol and oil companies with far greater resources than we have. Development of new products and methods of ethanol production by larger and financially more viable competitors could provide them with significant competitive advantages over us and thus could harm our business. These companies, some of which are publicly traded on national securities exchanges, generally have access to larger capital and financing markets and thus may be able to obtain financing easier and at more favorable terms than us.

Research and Development.

During the 2010 fiscal year, we participated in research and development programs sponsored by our suppliers. This research was focused primarily on energy reduction and other issues related to plant operation and production methods to develop more efficient methods of producing ethanol. A primary focus in 2010 was delivery of enzymes into the production process through the grain. This process is in the final stages of development. It is anticipated that if its use is deregulated by the USDA, we will contract directly with local growers to grow the quantities of the grain required for use by the company.

Employees.

As of the date of this report, we have 37 full-time employees. These include a chief executive officer, chief accounting officer, plant manager who oversees plant operations and production, a commodities manager to oversee grain acquisition and risk management, a safety director, a lab manager, a maintenance manager, and an administrative assistant. The remainder of our employees includes administrative, production and maintenance support personnel. None of our employees are the subject of collective bargaining by labor unions, and we believe that we enjoy excellent relations with our employees.

Table of Contents

From time to time, we also retain the services of outside consultants to supplement the services provided by our employees. These include engineering, construction, legal, accounting and financial advisors. We believe that we can obtain the services of all personnel necessary to operate our business.

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 below are not the only risks 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 Related to Our Business

Our financial performance is significantly dependent on grain and natural gas prices. Our results of operations and financial condition are significantly affected by the cost and supply of grain and natural gas. If our region becomes saturated by ethanol plants, the grain required for ethanol could consume a significant portion of the total grain production in our region, which would likely drive up local prices. If more corn-based ethanol plants are constructed or existing plants expand their capacity, the increase in demand for local corn and natural gas may drive up the prices of those commodities. Generally, we cannot pass on increases in input prices to our customers. Changes in the price and supply of grain and natural gas are subject to and determined by market forces over which we have no control.

Grain costs significantly impact our cost of goods sold. Our gross margins are principally dependent upon the spread between ethanol and grain prices, which has fluctuated significantly in 2010 and may continue to do so in the future due to volatile commodity prices. Any reduction in the spread between ethanol and grain prices, whether as a result of an increase in corn prices or a reduction in ethanol prices, would adversely affect our results of operations and financial condition.

Corn, as with most other crops, is affected by weather, disease and other environmental conditions. The price of corn is also influenced by general economic, market and government factors. These factors include weather conditions, farmer planting decisions, domestic and foreign government farm programs and policies, global demand and supply and quality. Changes in the price of corn can significantly affect our business. The annualized price of corn decreased approximately 8% in fiscal 2010 when compared to fiscal 2009. Corn prices as reflected on the Chicago Board of Trade began increasing at the beginning of fiscal 2011 and have increased approximately 13.7% during the first quarter of fiscal 2011 from their levels at the end of September. If a period of high corn prices is sustained for some time, such pricing may reduce our ability to generate profits because of the higher cost of operating and may make ethanol uneconomical to use in fuel markets. We cannot offer any assurance that we will be able to offset any increase in the price of corn by increasing the price of our products. If we cannot offset increases in the price of corn, our financial performance may be materially and adversely affected and we may be forced to curtail production.

Our revenues will be greatly affected by the price at which we can sell our ethanol and distillers grains. The prices of ethanol and distillers grains can be volatile as a result of a number of factors. These factors include the overall supply and demand, the price of gasoline, level of government support, and the availability and price of competing products. The recent increase in ethanol prices may also affect our operations by decreasing the demand for our ethanol for permissive blending which will reduce revenues.

We engage in hedging transactions that may be costly and ineffective. We are exposed to market risk from changes in commodity prices. Exposure to commodity price risk results from our dependence on corn and natural gas in the ethanol production process. We seek to minimize the risks from fluctuations in the prices of corn and natural gas through the use of hedging instruments. The effectiveness of our hedging strategies is dependent in part upon the cost of corn and natural gas and our ability to sell sufficient products to use all of the corn and natural gas for which we have futures contracts. There is no assurance that our hedging activities will successfully reduce the risk caused by price fluctuation which may leave us vulnerable to high corn and natural gas prices. Alternatively, we may choose not to engage in hedging transactions in the future. As a result, our results of operations and financial conditions may also be adversely affected during periods in which corn and/or natural gas prices increase.

Hedging activities themselves can result in costs because price movements in corn and natural gas contracts are highly volatile and are influenced by many factors that are beyond our control. There are several variables that could affect the extent to which our derivative instruments are impacted by price fluctuations in the cost of corn or natural gas. However, it is likely that current commodity cash prices will have the greatest impact on those derivative instruments with the nearest maturity dates. If cash prices are significantly different than our contracted prices, we may incur costs related to hedging activities and they may be significant.

Our business is not diversified. Our success depends largely upon our ability to profitably operate our ethanol plant. We do not have any other lines of business or other sources of revenue if we are unable to operate our ethanol plant and manufacture ethanol and distillers grains. If economic or political factors adversely affect the market for ethanol, the company has no other line of business to

Table of Contents

rely on if the ethanol business declines. Our business would also be significantly harmed if our ethanol plant could not operate at full capacity for any extended period of time.

We operate in an emerging growth industry. We commenced production of ethanol at our plant in January 2004. Accordingly, we have a limited operating history from which you can evaluate our business and prospects. Our operating results have fluctuated significantly in the past and could fluctuate significantly in the future as a result of a variety of factors, including those discussed throughout this report. Many of these factors are outside our control. As a result of these factors, our operating results may not be indicative of future operating results and you should not rely on them as indications of our future performance. In addition, our prospects must be considered in light of the risks and uncertainties encountered by an early-stage company and in rapidly growing industries, such as the ethanol industry, where supply and demand may change substantially in a short amount of time.

The price of natural gas is also affected by market and environmental conditions and other factors beyond our control. The prices for and availability of natural gas are subject to volatile market conditions, including supply shortages and infrastructure incapacities. Seasonal changes tend to affect the price of natural gas and increases during colder months tend to increase our costs of production. Significant disruptions in the supply of natural gas could impair our ability to manufacture ethanol for our customers. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial condition.

Advances in ethanol production technology could require us to incur costs to update our plant or could otherwise hinder our ability to compete or operate profitably. Advances and changes in the technology of ethanol production are expected to occur and we presently do not focus our resources on developing alternative ethanol production methods. 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 assure you that third-party licenses will be available or, once obtained, will continue to be available on commercially reasonable terms, if at all. Additionally, we will likely be at a competitive disadvantage due to the lag in time behind our competitors in utilizing new technologies. These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income.

We sell all of the ethanol we produce to POET-Ethanol Products under our ethanol marketing agreement. POET-Ethanol Products is the sole marketer of all of our ethanol, and we rely heavily on its marketing efforts to sell our product. Because POET-Ethanol Products sells ethanol for a number of other producers, we have limited control over its sales efforts. Our financial performance is dependent upon the financial health of POET-Ethanol Products, as a significant portion of our accounts receivable are attributable to customers of POET-Ethanol Products. If POET-Ethanol Products breaches the ethanol marketing agreement or is not in the financial position to market all of the ethanol we produce, we could experience a material loss and we may not have any readily available means to sell our ethanol, and our financial performance will be adversely and materially affected. If our agreement with POET-Ethanol Products terminates, we may seek other arrangements to sell our ethanol, including selling our own product, but we give no assurance that our sales efforts would achieve results comparable to those achieved by POET-Ethanol Products.

As a result of federal regulations related to the RFS and under the terms of the new marketing agreement with POET-Ethanol Products, title to our ethanol will pass to POET-Ethanol Products when it leaves our plant. However, we do not receive payment until the ethanol reaches the end customer. As a result, we bear a risk of loss during the transporting of our product to our customers. We have attempted to mitigate this risk by requiring POET-Ethanol Products to include us as an additional insured, however we have no assurance we will be sufficiently compensated for any lost product we may suffer during transport.

We sell all of the distillers grains we produce to UBE under our distillers grains marketing agreement. UBE is the sole buyer of all of our distillers grains that we sell locally, and we rely heavily on its marketing efforts to successfully sell our product. Because UBE sells distillers grains for a number of other producers, we have limited control over its sales efforts. Our financial performance is dependent in part upon the financial health of UBE, as a significant portion of our accounts receivable are due from UBE. If UBE breaches the distillers grains marketing agreement or is not in the financial position to purchase and market all of the distillers grains we produce, we could experience a material loss and we may not have any readily available means to sell our distillers grains, and our financial performance will be adversely and materially affected. If our agreement with UBE terminates, we may seek other arrangements to sell our distillers grains, including selling our own product, but there is no assurance that our sales efforts would achieve results comparable to those achieved by UBE.

Table of Contents

Risks Related to Ethanol Industry

Decreasing gasoline prices will negatively impact our business. A significant portion of the demand for ethanol results from what is known as “permissive blending” by wholesalers. Historically, ethanol has enjoyed a price advantage compared to gasoline, thus encouraging wholesalers to blend gasoline with ethanol. If gasoline prices decrease significantly to levels lower than that of ethanol prices, it is likely that these permissive blenders will find it less attractive to blend gasoline with ethanol. As a result, the demand for ethanol may decrease, which will increase the available market supply and make it more difficult to sell all of our ethanol.

Increase in supply from new plants or decreases in the demand for ethanol may result in excess production capacity which may lead to lower ethanol prices. The supply of domestically produced ethanol is at an all-time high. Domestic fuel grade ethanol production is estimated to be 13.4 billion gallons in 2010. If the industry maximized production capacity, it would likely surpass the anticipated domestic demand for ethanol for 2011. There are at least 190 production facilities currently operating in the United States. Excluding our facility, Kansas currently has 11 other ethanol plants operating. Excess capacity in the ethanol industry would have an adverse impact on our results of operations, cash flows and general financial condition. If the demand for ethanol does not grow at the same pace as increases in supply, we would expect the price for ethanol to decline. Ethanol prices could decline to a level that is inadequate to generate sufficient cash flow to cover our costs.

The increased production of ethanol could have other adverse effects. For example, the increased production could lead to increased supplies of co-products from the production of ethanol, such as distillers grains. Those increased supplies could outpace demand, which would lead to lower prices for those by-products. There can be no assurance as to the price of ethanol or distillers grains in the future. Any decrease in the price of ethanol and/or distillers grains may result in less income which would decrease our revenue and profitability.

We operate in a competitive industry and compete with larger, better financed entities. There is significant competition among ethanol producers with numerous producer and privately owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. The number of ethanol plants being developed and constructed in the United States continues to increase. The passage of the Energy Policy Act of 2005 and EISA included a renewable fuels mandate that we expect will further increase the number of domestic ethanol production facilities. The largest ethanol producers include Abengoa Bioenergy Corp., Archer Daniels Midland Company, Aventine Renewable Energy, LLC, Cargill, Inc., Hawkeye Renewables, LLC, and New Energy Corp., each of which are capable of producing more ethanol than we expect to produce. Larger, better financed ethanol producers may be able to expand their production capacity and adapt to new technologies easier than us. Archer Daniels Midland is currently the largest ethanol producer in the U.S. and controls a significant portion of the ethanol market. If the demand for ethanol does not grow at the same pace as increases in supply, we expect that lower prices for ethanol will result which may adversely affect our ability to generate profits and our financial condition.

We compete with other gasoline additives. Our ethanol plant also competes with producers of other gasoline additives made from raw materials other than corn having similar octane and oxygenate values as ethanol, including but not limited to methyl tertiary butyl ether (“MTBE”). Alternative fuels, gasoline oxygenates and alternative ethanol production methods are also continually under development. The major oil companies have significantly greater resources than we have to market MTBE, to develop alternative products, and to influence legislation and public perception of MTBE and ethanol. These companies also have significant resources to begin production of ethanol should they choose to do so. Companies such as Valero, Murphy Oil, and Sunoco have all purchased ethanol assets and begun to produce at least a portion of their ethanol requirements under EISA.

Competition from the advancement of alternative fuels and hybrid vehicles may lessen the demand for ethanol. Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells 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, resulting in lower ethanol prices that might adversely affect our results of operations and financial condition.

In addition, hybrid and electric vehicles are growing in popularity amongst U.S. consumers. Hybrid vehicles significantly reduce the amount of gasoline required to operate the vehicles by relying in part on electricity to power the vehicle and two automakers expect to release fully electric vehicles, which use little to no gasoline, in 2011. As hybrid and electric vehicles become more prevalent, it is likely the demand for gasoline, including gasoline blended with ethanol, will decrease. This may result in a corresponding decrease in the demand for ethanol, which may in turn affect our results of operations.

Table of Contents

Corn-based ethanol may compete with cellulose-based ethanol in the future. Especially in the Midwestern U.S., most ethanol is currently produced from corn and other raw grains, such as milo or sorghum. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. The Energy Policy Act of 2005 and EISA included incentives designed to boost production of cellulose-based ethanol. Although current cellulose technology is not sufficiently efficient to be competitive, new conversion technologies may be developed in the future and one of our competitors recently announced it was beginning construction of a facility slated to be cellulose-based. 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 ethanol plant into a plant which will use cellulose-based biomass to produce ethanol. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue and financial condition will be negatively impacted.

Ethanol imported from Caribbean basin countries and Brazil may be a less expensive alternative to our ethanol. Ethanol produced or processed in certain countries in Central America and the Caribbean region is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative. Large ethanol producers, such as Cargill, have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would convert ethanol into fuel-grade ethanol for shipment to the United States. Ethanol imported from Caribbean Basin countries may be a less expensive alternative to domestically produced ethanol. Competition from ethanol imported from Caribbean Basin countries may affect our ability to sell our ethanol profitably, adversely affect our results of operations and financial condition.

Brazil is currently the world’s largest exporter of ethanol. In Brazil, ethanol is produced primarily from sugarcane, which is also used to produce food-grade sugar. Ethanol imported from Brazil may be a less expensive alternative to domestically produced ethanol, which is primarily made from corn. Tariffs presently protecting U.S. ethanol producers may be reduced or eliminated. Competition from ethanol imported from Brazil may affect our ability to sell our ethanol profitably and our financial condition.

Consumer beliefs may affect the demand for ethanol. We believe that certain consumers perceive the use of ethanol to have a negative impact on gasoline prices at the pump. Some consumers 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 ethanol that is produced. These consumer beliefs could potentially be widespread. If consumers choose not to buy ethanol, it would affect the demand for the ethanol we produce which could lower demand for our product and negatively affect our profitability and financial condition.

Risks Related to Regulation and Governmental Action

Regulations in California may severely limit the amount of ethanol we may be able to sell in that state. Through our marketer, we sell a majority of the ethanol we produce in California, which has recently proposed new regulations aimed at reducing the carbon content of fuel sold within that state through implementation of a low-carbon fuel standard (LCFS). Beginning January 1, 2011, California fuel refiners and marketers will be required to meet the standard, under which the allowable amount of carbon content in fuel available for sale will progressively decrease. Under California’s program, different types of fuel are assigned a “carbon value” based upon the perceived amount of carbon emitted during the production, transportation, and consumption of the fuel in California. We believe that grain-based ethanol produced in the Midwestern United States will be assigned a higher carbon value than grain-based ethanol produced in California, ethanol imported from countries such as Brazil, and other fuels such as gasoline. Because of the higher carbon value assigned to our product, fuel refiners and marketers in California will have a more difficult time meeting the LCFS if they use our ethanol instead of other ethanol with a lower carbon value. As a result, the sale of our ethanol to refiners and marketers in California may decrease. California is currently considering certain amendments that could reduce the carbon value of Midwestern produced corn ethanol which would likely allow us to retain these California markets.

A change in government policies favorable to ethanol may cause demand for ethanol to decline. Growth in demand for ethanol may be driven primarily by federal and state government policies, such as state laws banning MTBE and the national renewable fuels standard. The continuation of these policies is uncertain, which means that demand for ethanol may decline if these policies change or are discontinued. A decline in the demand for ethanol is likely to cause lower ethanol prices which in turn will negatively affect our results of operations, financial condition and cash flows.

Government incentives for ethanol production may be eliminated in the future. The ethanol industry and our business are assisted by various federal ethanol tax incentives. Additionally, we presently qualify for a portion of an annual incentive payment offered by the State of Kansas, which is prorated based on the number of producers. We have no assurance any of these tax credits or subsidies will continue to be offered in the future, and one federal support, known as the VEETC, is scheduled to expire at the end of

Table of Contents

2011. The elimination or reduction of tax incentives to the ethanol industry could reduce the market for ethanol, which could reduce prices and our revenues by making it more costly or difficult for us to produce and sell ethanol.

Most likely to have the greatest impact on the ethanol industry is the creation of the RFS in the Energy Policy Act, which was subsequently increased by EISA. Biofuel usage mandates began with 4 billion gallons in 2006 and increase to 36 billion gallons by 2022. However, a new Congressional delegation and presidential administration will likely affect the nation’s energy policy. While we have no present indication that there are plans to revise the RFS in the future, we have no assurance the RFS will remain as presently drafted. Additionally, the State of Kansas may pass state legislation setting its own renewable fuel standard in the foreseeable future. The RFS helps support a market for ethanol that might disappear without this incentive. If the federal incentives are eliminated or sharply curtailed, we believe that a decreased demand for ethanol will result, which could negatively affect our profitability and financial condition.

Changes in environmental regulations or violations of the regulations could reduce our profitability. We are subject to extensive air, water and other environmental laws and regulations. In addition some of these laws require our plant to operate under a number of environmental permits. These laws, regulations and permits can often require expensive pollution control equipment or operating changes to limit actual or potential impacts to the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, damages, criminal sanctions, permit revocations and/or plant shutdowns. We cannot assure you that we have been, are or will be at all times in complete compliance with these laws, regulations or permits or that we have had or have all permits required to operate our business. We cannot assure you that we will not be subject to legal actions brought by environmental advocacy groups and other parties for actual or alleged violations of environmental laws or our permits. Additionally, any changes in environmental laws and regulations, both at the federal and state level, could require us to invest or spend considerable resources in order to comply with future environmental regulations. The expense of compliance could be significant enough to reduce our profitability and negatively affect our financial condition. Congress and the EPA continue to discuss possible regulations of carbon dioxide. Regulations that are unfavorable to our business operations or that call for implementation on a short timetable may cause difficulty for us to come into compliance. This may result in potential negative consequences to our company, such as fines or other sanctions.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

We currently own 411 acres of real property in the state of Kansas, most of which is currently undeveloped. In October 2003, we completed an industrial revenue bond financing with Gove County that provides and will provide us with property tax savings on our plant site until 2014. As part of the financing, title to our plant site and all of our facilities have been transferred to Gove County as security for the repayment of the bonds. We are leasing back the site for an amount that is equal to the amount of the principal and interest that is payable on the bonds. The term of the lease is 30 years or as long as the bonds are outstanding. Also under the terms of the lease, we can repurchase the site for a nominal amount upon repayment of the bonds.

We initially acquired a 53.5 acre parcel of partially developed land in Gove County for the purpose of constructing our plant. Our plant was developed on approximately 20 acres of the 53.5 acre parcel. In February 2002, we acquired a 137 acre parcel approximately one and a half miles east of the parcel where our plant is located. In December 2004, we acquired a 141 acre parcel of land immediately to the east of our plant site. In December 2005, we acquired an 80 acre parcel which had previously separated the land surrounding our plant site from the 137 acre parcel acquired in 2002. We now own a contiguous parcel of property in Gove County.

We acquired water appropriation rights for two wells when we purchased the 137 acre parcel and one well when we purchased the 80 acre parcel. We applied to the Kansas Department of Agriculture, Division of Water Resources to change the type of water use from agricultural irrigation use to industrial use for the well on the 80 acre parcel and constructed an irrigation system for delivery of water from that well to our plant. We anticipate the same undertaking if we decide to utilize the wells on the 137 acre parcel, which would be likely to occur in the event we further expand our plant capacity. We have agreed to lease the 137 acre property back to one of the sellers for a period of five years with the amount of rent based on the portion of the land that is dry land acres and the portion that is irrigated acres, with the seller expressly recognizing that the water available for irrigation may be dramatically reduced, and possibly eliminated, if we use the water from this property in our ethanol plant operations. On February 6, 2007, we purchased 340 acre feet of water rights on property adjacent to one of our parcels for $340,308. We have filed with the State of Kansas to convert the classification of these water rights from agriculture to industrial use and have received approval for 252 acre feet per year for industrial use.

Table of Contents

In addition to our ethanol plant, we also own an administrative building adjacent to the plant. The administrative building consists of approximately 3,000 finished square feet (including a partially finished basement) and provides offices for our administrative staff. We are currently considering bids to construct additional office space as we have outgrown our existing administration building.

In October 2006, we acquired a grain elevator located on a neighboring parcel which we utilize for grain storage. The underlying land is owned by Union Pacific Railroad and we assumed the prior owner’s lease with the railroad. To further increase our storage capacity for grain, we constructed 500,000 bushels of additional storage bins near our ethanol plant including two hammer mills and necessary infrastructure for the conveyance of the grain. In addition, during the last quarter of fiscal 2009, we added another grain receiving pit with the necessary infrastructure enhancing the number of trucks we can receive during harvest. This project was fully operational in October 2009.

We contracted with ICM Inc. to construct an additional fermenter. The new fermenter was not intended to increase our overall nameplate capacity. Instead, it is anticipated to increase our overall operating efficiencies by increasing the total fermentation time during the production process. We believe this additional fermentation time has also increased ethanol yield during production.

Item 3. Legal Proceedings.

From time to time we may be subject to litigation that is incidental to our business. However, we are not currently a party to any pending legal proceedings that are not routine litigation incidental to our business.

Item 4. Reserved.

PART II

Market Information

There is no public trading market for our capital units. Article 4 of our Third Amended and Restated Operating Agreement (“Operating Agreement”) provides a number of restrictions on the transfer of capital units by our members. In essence, any proposed transfer must be approved by our Board of Managers.

In addition to the restrictions on transfer contained in our operating agreement, we are also subject to limitations imposed by the United States Internal Revenue Code (“Code”). In order to maintain our status as a partnership for income tax purposes, we must not be treated as a “publicly traded partnership” under relevant provisions of the Code. Generally, the Code provides that a publicly traded partnership will be taxed as a corporation. In order to comply with these rules, we do not intend to list any of our capital units on a stock exchange or apply for quotations in any electronic trading system.

During the 2008 fiscal year, we implemented a private matching service for our members, also called an alternative trading system (“ATS”), which is operated and maintained by a third party. The ATS offers an online electronic bulletin board that provides information to prospective sellers and buyers of our capital units. Trading on the ATS in fiscal 2010 and 2009 was extremely limited.

In addition to sales between willing buyers and sellers facilitated through the ATS, the holders of our capital units who locate a purchaser or receive an offer to purchase can sell the capital units to the purchaser subject to the approval of the Board of Managers. Our Operating Agreement also allows transfer of the capital units by:

· Gift;

· Last will or the laws of descent;

· Transfers between members of a family; and

· “Block” transfers.

A block transfer is a transfer by a member and any related person, as defined in the Code, of membership interests representing in the aggregate more than 2% of the total interest in our capital or profits in one or more transactions during any 30 calendar day period.

On March 10, 2008, we implemented a seven (7) for one (1) forward split of all of our outstanding Class A, B and C capital units. The information contained in this report reflects the result of that split.

Table of Contents

Capital Unit Holders

As of December 23, 2010, there were 16,002 Class A capital units, 12,068 Class B capital units and 350 Class C capital units outstanding, owned by a total of approximately 647 members.

Distributions to Members

Under the terms of our Operating Agreement, we are required to make an annual distribution to our members of a minimum of 20% of the net cash we earn from operations, as defined in the Operating Agreement, as long as net cash from operations exceeds $500,000 for that year. However, we are prohibited from making any distributions if it would violate or cause us to default under any of the terms of any of our credit facilities or debt instruments.

During the 2010 fiscal year, we made four quarterly distributions to our members totaling $520 per unit for an aggregate of $14,778,400 in cash. During the 2009 fiscal year, we distributed a total of $175 per unit or $4,973,500 in cash to our members. Future distributions may be subject to restrictions that materially limit our ability to pay such distributions, such as our credit facilities if we have an outstanding balance with our lender. To the extent we are not subject to any restriction that materially limits our ability to pay distributions, however, future distributions in excess of the amount required under our Operating Agreement will be made in the discretion of our Board of Managers.

Securities Authorized for Issuance under Equity Compensation Plans

We currently have no equity compensation plan; however, we may consider such a plan in the future which would be subject to member approval.

Item 6. Selected Financial Data.

Not required.

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

Except for the historical information, the following discussion contains forward-looking statements that are subject to risks and uncertainties. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the risks described in “Risk Factors” and elsewhere in this annual report. Our discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and related notes and with the understanding that our actual future results may be materially different from what we currently expect.

Introduction

The following discussion analyzes our operating results for the two fiscal years ended September 30, 2010 and our financial condition at September 30, 2010 and 2009, with a particular emphasis on the year ended September 30, 2010.

We derive revenue from the sale of fuel grade ethanol and distillers grains. We operate in one industry segment for accounting purposes. We commenced production of ethanol in January 2004. Prior to that date, we were considered to be in the development stage for accounting purposes.

Results of Operations for the Year Ended September 30, 2010 compared to September 30, 2009

Overview. Table 1 below highlights certain of our operating results for the years ended September 30, 2010 and 2009:

Table 1

	Fiscal Year Ended September 30,
	2010		2009
Revenue	$	96,048,749	$	92,268,505
Cost of sales	76,359,242		81,722,233
Gross profit	19,689,507		10,546,272
General & administrative expenses	2,605,853		2,315,556
Income from operations	10,335,389		1,803,674
Other income	849,549		894,756
Interest expense	—		20,158
Net income	11,184,938		2,698,430
Net income per unit(1)	394		95

Table of Contents

(1) — Adjusted to reflect seven-for-one forward split effective March 10, 2008.

Table 2 sets forth information regarding our ethanol production and raw material usage and the average price we received for our ethanol and paid for our raw materials for the years ended September 30, 2010 and 2009:

Table 2

	Fiscal Year Ended September 30,
	2010		2009
Gallons of ethanol sold	48,944,948		48,766,384
Average price per gallon ethanol	$	1.65	$	1.49
DDGS sold (tons)	15,654		14,255
Average price DDGS per ton	$	94.22	$	111.12
WDGS sold (tons)	367,170		393,409
Average price WDGS per ton	$	37.41	$	46.65
Bushels grain used in production	17,812,126		17,965,374
Average price per bushel grain	$	3.45	$	3.74
Natural gas used MMBTU	972,059		976,104
Average price per MMBTU natural gas	$	4.94	$	4.69

As shown in Table 1, our operating results improved significantly from 2009 to 2010. This is primarily attributable to higher average ethanol prices and lower average grain prices in fiscal 2010 compared to 2009, as shown in Table 2. Demand for fuel grade ethanol increased modestly during the calendar year 2010. Production in the industry had expanded at a rapid rate during the previous two years and we saw some of our fellow producers shut-in some production capacity in the first half of fiscal 2009. During the last quarter of fiscal 2009, virtually all of this shut-in capacity came back online due to the strengthening of production margins across the industry. The excess ethanol production over domestic demand that was anticipated during the 2010 fiscal year was offset by an increase in the amount of domestically produced ethanol that was exported, primarily to Europe.

Net Income. Net income increased $8,486,508, or approximately 314.5%, in fiscal 2010 from fiscal 2009. We attribute this increase to higher average prices received for ethanol, and a lower cost of grains used to produce ethanol.

Operating income for the 2010 fiscal year increased by $8,531,714, or approximately 473.0%, from 2009. This increase results likewise from the decrease in the cost of grain and higher prices for ethanol realized during fiscal 2010. Operating income excludes the effect of other income or expense, which primarily includes government grants and subsidies.

Revenue. Revenue for the 2010 fiscal year increased $3,780,244, or approximately 4.1%, from 2009. As a result of continued improvements in our production process, production volume increased during fiscal 2010 by 354,050 gallons of ethanol from fiscal 2009. However, as shown in Table 2, the average price we received for sale of ethanol was $0.16 per gallon higher in fiscal 2010, or 10.7%, contributing primarily to the increase in revenue. Sales volume increased by 178,564 gallons during 2010, or approximately 0.4%. Revenue consisted of approximately 84% in ethanol sales and 16% from the sale of distillers grains, which is a slight decrease in the ratio of distillers grains to ethanol as compared with fiscal 2009. Total revenue derived from the sale of ethanol increased $8,087,706, or approximately 11.1%, from fiscal 2009, while revenue derived from the sale of distillers grains decreased $4,307,461, or approximately 22.1%, from fiscal 2009. Ethanol prices began to increase during the fourth quarter of fiscal 2009 and the first quarter of fiscal 2010, decreasing in the second and third quarters of fiscal 2010, while recovering during the fourth quarter of fiscal 2010. We expect the prices to remain favorable for the near future compared to the prior year. Distillers grain prices will likely follow grain prices in fiscal 2011.

Costs of Goods Sold. Our cost of goods sold for the 2010 fiscal year equaled 79.5% of revenue, resulting in a gross profit margin of 20.5%. This represents an increase in gross profit margin from 11.4% in 2009. We attribute the increase to several factors including:

· A decrease in the price of grain used;

· A decrease in the R & D expenses; and

Table of Contents

· A decrease in natural gas costs.

Grain prices, which represent the significant majority of our cost of goods sold, decreased overall in fiscal 2010. Favorable growing conditions and a decrease in export demand put downward pressure on grain markets. As shown in Table 2, the average price we paid for grain decreased approximately 7.8% in fiscal 2010 as compared to 2009. Although the 2010 corn crop was estimated to be somewhat smaller than the 2009 harvest, we believe there is more than adequate supply of local grain to draw from. In addition, the weakening of the U.S. dollar has stimulated export demand. These factors have caused the price of corn to increase during the first quarter of fiscal 2011.

Our increased grain storage capacity helps us manage our grain costs by enabling us to purchase grain when costs are lower. As grain prices rise, we anticipate we will reduce grain inventory and try to avoid purchasing grain at market prices higher than the price paid for the grain in storage.

We believe we continue to improve the efficiency with which we operate our plant based on a year-over-year basis. As a result, our production costs (exclusive of commodity costs and increased costs for necessary chemicals) continue to decrease.

Energy costs, representing the second largest component of our costs of goods sold, saw a slight increase during our 2010 fiscal year as compared to fiscal 2009; however, the price remained more stable during fiscal 2010 as compared to the previous fiscal year. Our energy costs for fiscal 2010 increased $341,487, or approximately 5.9%, from fiscal 2009. This increase in cost was primarily the result of the increase in natural gas prices in 2010. We expect natural gas prices to remain stable in fiscal 2011.

We continue to believe that hedging is an integral part of our business as a means of risk management. Our strategy is to mitigate the impact of large adverse price changes in costs, such as natural gas and grain, as well as the products we sell. Our operating results include both realized and unrealized gains or losses in these hedging activities. For the 2010 fiscal year, we realized $192,266 in losses relating to grain futures contracts and $431,660 in realized losses from natural gas futures contracts, which amounts are included in costs of goods sold. In addition, we recorded an unrealized gain on grain hedging contracts of $544,526 at September 30, 2010.

General and Administrative Expenses. During fiscal 2010, general and administrative expenses increased $290,297 or approximately 12.5% from fiscal 2009. Significant components of these expenses include salaries, professional fees, property taxes, and insurance. Salaries increased approximately 6.4% during 2010, primarily due to an increase in bonuses paid during the year. Professional fees increased 9.0% from fiscal 2009 to fiscal 2010 primarily due to an increase in legal and filing services related to our required reporting with the SEC. Property taxes decreased approximately 4.2% reflecting a lower assessed value in fiscal 2010 than in fiscal 2009, while general insurance expense decreased 7.0% for fiscal 2010 as compared to fiscal 2009.

Depreciation and Amortization. Amortization remained constant during the 2010 fiscal year from 2009. During that time, depreciation expenses increased approximately 5.0%. This increase is primarily attributable to the additional depreciation related to the new fermenter, grain receiving pit and related conveyance system, and upgrades to our energy center and process systems placed in service during fiscal 2010.

Other Income. Other income for the 2010 fiscal year decreased $45,207, or approximately 5.1%, from the year ended September 30, 2009. A significant portion of that decrease was interest income which decreased by $32,187 or approximately 44.0%, which was partially tempered by a reduction in interest expense that decreased by $20,158 pursuant to a reclassification of bank fees from interest expense to administrative expense. Interest income decreased due to a lower interest rate and average cash balance in interest bearing accounts during fiscal 2010, as compared to fiscal 2009. We also recorded an increase of $56,963, or approximately 6.9%, in income from subsidies received from the state and federal government. The amount we received in grants and subsidies increased as a result of a new program initiated by the USDA Rural Development which is designed to encourage production of renewable energy using feedstock other than corn. We qualified for this program because a large portion of feedstock used in production of our ethanol and distillers grain is milo, which meets the current guidelines. We received $848,999 from the federal program in December of 2009, of which $700,000 was accrued as income in fiscal year 2009, with the balance of $148,999 recorded as income for fiscal 2010. We received additional payments during fiscal 2010 of $224,705 from the federal program. We received a payment of $514,860 in August 2010 from the state subsidy program for which we are eligible.

Trends that may Impact our Future Operating Results

Prices for Ethanol. Demand for and the price of ethanol can vary significantly over time and a decrease in the price of ethanol will adversely affect our profitability. Historically, the price of ethanol tended to fluctuate with the price of petroleum gasoline; however, we believe ethanol prices are trending less with gasoline prices and often are affected by the price of grains used to produce it.

Table of Contents

At the time of filing of this report, ethanol is trading at price levels similar to petroleum gasoline which means that using ethanol for blending with petroleum has become only marginally economical, particularly where blending is discretionary rather than mandatory. We believe this may decrease the demand for ethanol which in turn will continue to put downward pressure on ethanol prices. Another factor that may affect the price of ethanol is the increased supply anticipated as a result of the expansion of present plants, construction of new plants, and the reopening of plants formerly in financial difficulty; however, we believe this trend may be less noticeable in 2011 as excess capacity is leveling off due to decreased demand and/or delays in plant start-ups scheduled in the future. The increase in production capacity will increase the supply of ethanol, which will tend to reduce the price for ethanol if demand does not also increase.

During the fourth quarter of fiscal 2010 and continuing into the first quarter of fiscal 2011, we have experienced a steady increase in the price of ethanol which has had a favorable effect on our margins; however, we expect prices to decrease as we are entering the seasonal period of lower overall fuel demand. The price of corn has also increased somewhat: however, we were able to partially mitigate the effect of this increase by purchasing and storing local grain at harvest.

Supply and price of grain. Prices for grain reflected on CBOT have risen in the first quarter of fiscal 2011, however, local cash values have remained weak, primarily due to the large supply locally. To the extent local supply remains in excess of local demand, we believe local cash values will continue to widen from futures prices. The grain market is dependent upon a variety of factors unrelated to the ethanol market. The price of grain is generally dependent upon regional and international grain supplies, which can be very volatile. In addition, the gradual recovery in the stock market, increasing prices for oil and decreasing value of the U.S. dollar has put upward pressure on grain prices. Grain supplies and the resultant prices are also affected by weather, governmental policy, disease and other conditions. Grain markets were relatively volatile during 2010 as well as 2009; and we believe this trend will continue during fiscal 2011. Our cost of grain will likely be at higher levels in fiscal 2011 as compared to fiscal 2010.

Government supports. As discussed elsewhere in this report, current federal law is favorable to ethanol because it mandates certain oxygenate blending. In addition, as noted above in the section titled “Item 1. Business,” the RFS established by the Energy Policy Act of 2005 mandates that fuel refiners use a certain minimum amount of ethanol and other renewable fuels, which was subsequently increased by the enactment of EISA. While the RFS may not have an immediate impact on the ethanol market since current national ethanol production capacity exceeds the 2010 RFS requirement of 12.95 billion gallons, it is likely that the increased RFS requirement of 36 billion gallons of renewable fuel by 2022, 15 billion gallons of which may come from grain based ethanol, will continue to support the ethanol industry in the long-term. It is also possible that cessation of supports and incentives may adversely affect price and demand. In addition, the recent announcement from the EPA that approves use of gasoline with increased discretionary blending of ethanol from 10% to 15% in vehicles manufactured in 2007 and later expands the marketing opportunities for ethanol. The EPA is currently conducting further studies in support of extending the 15% limit to 2001 and newer vehicles, which may potentially add millions of customers.

Production of ethanol. As noted above, with a few new ethanol plants and plant expansions currently under construction and the reentry into the market of plants previously shut-in during fiscal 2009, the nationwide production capacity for ethanol is expected to increase in the near term. At a minimum, this increased capacity creates some uncertainty for the ethanol industry. If the production of ethanol exceeds either the demand for ethanol or the petroleum industry’s ability to economically blend ethanol with gasoline, then the price of ethanol would be expected to fall, and the decrease in ethanol prices could be significant. In that case, our revenues would decrease accordingly. However, we believe that our lack of significant long-term debt positions us favorably to weather lower ethanol prices compared to some of our competitors.

Liquidity and Capital Resources

Overview. The following table highlights certain information relating to our liquidity and capital resources at September 30, 2010 and 2009:

	September 30
	2010		2009
Working Capital	$	13,044,083	$	13,723,893
Current Assets	20,433,068		17,336,366
Current Liabilities	7,388,985		3,612,473
Long-term Debt	—		—
Members’ Equity	26,086,370		29,919,179

Our working capital at September 30, 2010 decreased by $679,810, or approximately 5.0%, from September 30, 2009. Current assets increased $3,096,702, or approximately 17.8%, while current liabilities increased $3,772,512, or approximately 104.4%. We attribute the increase in current assets to several factors. Accounts receivable, inventory and commodity trading accounts were higher at September 30, 2010 as compared to the same period of 2009. Accounts receivable for ethanol increased approximately 50% at

Table of Contents

September 30, 2010 compared to September 30, 2009, which was the result of a 41% higher price and 6.7% increase in the amount of gallons in receivables. Inventory increased 169.3% at September 30, 2010 compared to the same period of 2009, as a result of an increase in grain prices of approximately 36% and an increase of 213.4% in the quantity on hand. These were partially offset by a reduction in cash on hand, a decrease in prepaid expenses, a decrease in accounts receivable - government subsidies, and an increase in accounts payable at September 30, 2010 as compared to September 30, 2009.

Under the terms of our Operating Agreement, we are required to make an annual distribution of cash to our members of a minimum of 20% of the net cash we earn from operations, as defined in that agreement, as long as net cash from operations exceeds $500,000 for that year. Additional distributions may be made in the sole discretion of our Board of Managers. However, we are prohibited from making any distribution that would violate or cause a default under any of the terms of our credit facilities or debt instruments. Distributions to members increased dramatically during fiscal 2010 as compared to fiscal 2009, reflecting the increase in net income.

Our capital resources consist of: (i) cash from operations; (ii) permanent financing, in the form of capital contributions by our members; (iii) a revolving line of credit; and (iv) industrial development bonds. At September 30, 2010, we believe the mix of our capital resources was appropriate and adequate for the foreseeable future. Other than financing continuing operations, additional capital would be necessary should we decide to further expand our plant or pursue acquisitions of additional property, plant or equipment.

Cash Flow. Net cash used during the 2010 fiscal year was $3,038,963, compared to net cash generated of $5,851,536 in fiscal 2009. The most significant factors causing the decrease in cash flow in 2010 were increases in the distributions paid to members, purchases of plant and equipment, quantity and value of grain inventory, and accounts receivable compared to fiscal 2009.

Cash provided by operations increased by $6,558,435 in fiscal 2010 compared to fiscal 2009. The increase primarily reflects increases in net income, accounts payable, and depreciation, and a reduction in prepaid expenses and accounts receivable from government subsidies. The change in grain hedging contracts, the increase in accounts receivable and the increase in inventory tempered the increase in cash from operations. Our accounts payable balance was significantly higher at September 30, 2010 primarily due to the increased commodities account payable.

The cash provided by our investing activities during fiscal 2010 decreased by $5,652,153 from fiscal 2009. We invested $3,595,266 in property, plant and equipment in fiscal 2010 compared to $1,101,521 in fiscal 2009. We incurred net margin calls of $920,965 from our commodity trading accounts during fiscal 2010, as compared to a withdrawal, net of margin calls, of $2,237,443 during the comparable period of fiscal 2009.

Cash used in financing activities increased by $9,796,781 in fiscal 2010 compared to fiscal 2009. The increase primarily reflects the increase in distributions to members during fiscal 2010. Total distributions paid to members during fiscal 2010 and 2009 were $14,778,400 and $4,973,500, respectively.

Equity Financing. Our members have contributed $19,801,035 in equity financing since inception, primarily from our initial public offering completed in 2003. We do not anticipate that any additional equity financing will be necessary in the foreseeable future.

Debt Financing. Under our arrangement with AgCountry, our principal lender, we borrowed $22,000,000 under a construction loan in 2003. The proceeds of that loan were used by us to complete construction of the plant and to commence operations. In August 2004, we converted the loan to permanent financing in the form of a $16,000,000 term loan and a line of credit in the amount of $5,000,000. At that time, we paid AgCountry $5,000,000 to reduce the loan, all of which was used to create the line of credit. We paid the AgCountry term loan in full in June 2006 and continue to maintain the line of credit. Pursuant to the Fifth Amendment to the Credit Agreement dated July 29, 2003, which was effective May 2, 2007, the amount available on the line of credit was increased to $8,000,000 with variable interest at LIBOR plus 2.0%. There is no balance outstanding on this line of credit at September 30, 2010.

Our existing repayment obligations under the credit agreement with AgCountry are secured by all of our tangible and intangible real and personal property. In addition, the bonds acquired from Gove County have been pledged to AgCountry to secure our borrowing. As part of the credit agreement, we agreed to certain affirmative, negative and financial covenants which potentially affect our operations, including, but not limited to, the following:

· We must provide AgCountry with audited annual and unaudited quarterly financial statements, annual budgetary and business plan information, and a notice of the occurrence of an event of default and other material events;

Table of Contents

· We must permit AgCountry representatives to visit and inspect our properties, conduct audits of the collateral, examine our books and records and review documents related to construction of our plant;

· With certain exceptions, we may not incur additional indebtedness, allow our real or personal properties to be used as collateral for any other obligations or make any other investments of any kind;

· We can distribute up to 75% of our net income to our members. If we maintain a leverage ratio of 0.60:1.00 and working capital greater than $5 million (each as reported in audited year-end financial statements prepared in accordance with generally accepted accounting principles), we can distribute 100% of our net income to our members.

· We must maintain certain financial ratios, beginning at various times, including a fixed charge coverage ratio and current ratio and we must meet a minimum net worth requirement of $25,000,000. We also may not, after completion of construction of the plant, make any capital expenditures in excess of $2,500,000 during any fiscal year without AgCountry’s prior written approval.

At September 30, 2010, we believe we satisfied all of the covenants under the loan agreement; however, upon request by us, AgCountry has occasionally agreed to waive the restrictions on distributions of net income contained in the covenants.

Off-Balance Sheet Arrangements

At September 30, 2010, we had no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Use of Estimates. Preparation of our financial statements necessarily requires estimates and judgments to be made that affect the amounts of assets, liabilities, revenues and expenses reported. Such decisions include the selection of the appropriate accounting principles to be applied and the assumptions on which to base accounting estimates. Our management continually evaluates these estimates based on assumptions it believes to be reasonable under the circumstances.

The difficulty in applying these policies arises from the assumptions, estimates and judgments that must be made currently about matters that are inherently uncertain, such as future economic conditions, operating results and valuations, as well as management intentions. As the uncertainty increases, the level of precision decreases, meaning that actual results can, and probably will be, different from those currently estimated.

Of the significant accounting policies described in the notes to the financial statements, we believe that the following may involve a higher degree of estimates, judgments and complexity:

Revenue Recognition. Revenue from the production of ethanol and related products is recorded when loaded out of our facility. Interest income is recognized as earned. Income from government grant programs is recognized as costs are incurred. Government subsidies are recognized based on fulfillment of program criteria, completion of application and determination of available funding.

Derivatives and Financial Instruments. We account for derivatives in accordance with Accounting Standards Codification (“ASC”) 815-10, “Accounting for Derivative Instruments and Hedging Activities.” ASC 815-10 requires the recognition of derivatives in the balance sheet and the measurement of these instruments at fair value. Changes in the fair value of derivatives are recorded as a component of Cost of Sales unless the normal purchase or sale exception applies or hedge accounting is elected.

We enter into derivative instruments including future contracts and swap agreements and purchased options to fix prices for a portion of future raw material requirements. We have designated, documented and assessed for hedge relationships, which mostly resulted in cash flow hedges that require us to record the derivative assets and liabilities at their fair value on the balance sheet with an offset in other comprehensive income. Amounts are removed from other comprehensive income as the underlying transactions occur and realized gains or losses are recorded. We have included in its cost of sales an aggregate of $623,925 of losses on completed contracts related to its hedging activities for corn and natural gas and have recorded an aggregate of $239,348 of unrealized losses for the year ended September 30, 2010, as a charge to comprehensive income as compared to $1,874,225 losses on contracts and $1,058,867 of unrealized gains for the year ended September 30, 2009. At September 30, 2010, the commodities trading account-futures and options contracts amounted to $231,862, as compared to $94,771 at September 30, 2009, representing the lower of the cost or fair market value of the futures and options contracts recorded on the balance sheet.

Table of Contents

Commitments and Contingencies. Contingencies, by their nature, relate to uncertainties that require management to exercise judgment both in assessing the likelihood that a liability has been incurred, as well as in estimating the amount of the potential expense. In conformity with accounting principles generally accepted in the United States, we accrue an expense when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Long-Lived Assets. Depreciation and amortization of our property, plant and equipment is applied on the straight-line method by charges to operations at rates based upon the expected useful lives of individual or groups of assets placed in service. Economic circumstances or other factors may cause management’s estimates of expected useful lives to differ from the actual useful lives. Differences between estimated lives and actual lives may be significant, but management does not expect events that occur during the normal operation of our plant related to estimated useful lives to have a significant effect on results of operations.

Long-lived assets, including property, plant and equipment and investments, are evaluated for impairment on the basis of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impaired asset is written down to its estimated fair market value based on the best information available. Considerable management judgment is necessary to estimate future cash flows and may differ from actual cash flows. Management does not expect an impairment of assets will exist based on their assessment of the risks and rewards related to the ownership of these assets and the expected cash flows generated from the operation of the plant.

Recently Adopted Accounting Standards

We evaluate the pronouncements of various authoritative accounting organizations, primarily the Financial Accounting Standards Board (“FASB”), the SEC, and the Emerging Issues Task Force (“EITF”), to determine the impact of new pronouncements on US GAAP and the impact on our company. With the exception of those stated below, there have been no recent accounting pronouncements or changes in accounting pronouncements during year ended September 30, 2010 that are of material significance, or have potential material significance, to the company:

Effective July 1, 2009, the FASB issued Accounting Standards Update (“ASU”) No. 825 “Disclosures about Fair Value of Financial Instruments,” to require entities to disclose, among other things, the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. Adoption of ASU No. 825 did not have a material impact on our results of operations or financial position.

In December 2009, the FASB issued ASU No. 2009-17, “Consolidations (Topic 810) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.” ASU No. 2009-17 changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. ASU No. 2009-17 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity is required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. ASU No. 2009-17 is effective for fiscal years beginning after November 15, 2009, and interim periods within those fiscal years. We adopted ASU No. 2009-17 as of January 1, 2010, and its application had no impact on our financial statements.

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition (Topic 605) - Multiple-Deliverable Revenue Arrangements.” ASU No. 2009-13 addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services (deliverables) separately rather than as a combined unit. This guidance establishes a selling price hierarchy for determining the selling price of a deliverable, which is based on: (a) vendor-specific objective evidence; (b) third-party evidence; or (c) estimates. This guidance also eliminates the residual method of allocation and requires that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. In addition, this guidance significantly expands required disclosures related to a vendor’s multiple-deliverable revenue arrangements. ASU No. 2009-13 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010 and early adoption is permitted. A company may elect, but will not be required, to adopt the amendments in ASU No. 2009-13 retrospectively for all prior periods. We are currently evaluating the requirements of ASU No. 2009-13 and have not yet determined its impact on our financial statements.

In December 2009, the FASB issued ASU No. 2010-06 “Fair Market Value Measurements and Disclosures” (Topic 820) “Improving Dislcosures about Fair Value Measurements”. This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in ASC Subtopic 820-10. The FASB’s objective is to improve these

Table of Contents

disclosures and, thus, increase the transparency in financial reporting. The adoption of this ASU did not have a material impact on our financial statements.

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which provides amendments to ASC topic “Fair Value Measurements and Disclosures”. This ASU provides more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) the transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. We are currently assessing the impact that the adoption will have on our disclosures.

In February 2010, the FASB issued ASU 2010-09 (ASU 2010-09), “Subsequent Events (Topic 855).” The amendments remove the requirements for an SEC filer to disclose a date, in both issued and revised financial statements, through which subsequent events have been reviewed. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. GAAP. ASU 2010-09 is effective for interim or annual financial periods ending after June 15, 2010. W do not expect the provisions of ASU 2010-09 to have a material effect on our financial position, results of operations or cash flows.

There were various other updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our financial position, results of operations or cash flows.

Forward-Looking Statements

This report contains or incorporates by reference “forward-looking statements,” as that term is used in federal securities laws, about our financial condition, results of operations and business. These statements include, among others:

· statements concerning the benefits that we expect will result from our business activities and certain transactions that we have completed, such as increased revenues, decreased expenses and avoided expenses and expenditures; and

· statements of our expectations, beliefs, future plans and strategies, anticipated developments and other matters that are not historical facts.

These statements may be made expressly in this document or may be incorporated by reference to other documents that we will file with the SEC. You can find many of these statements by looking for words such as “believes,” “expects,” “anticipates,” “estimates” or similar expressions used in this report or incorporated by reference in this report.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties that may cause our actual results to be materially different from any future results expressed or implied by us in those statements. Because the statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied. We caution you not to put undue reliance on these statements, which speak only as of the date of this report. Further, the information contained in this document or incorporated herein by reference is a statement of our present intention, is based on present facts and assumptions and may change at any time and without notice based on changes in such facts or assumptions.

A few of the uncertainties that could affect the accuracy of forward-looking statements, besides the specific “Risk Factors” identified above, include:

· The state of the United States economy and how it affects the desire for automobile travel;

· The relative price of gasoline and other competing fuels;

· Changes in government regulations for air and water quality or subsidies for production of ethanol and other fossil fuel alternatives;

· Technological advances in the process for producing ethanol; and

· Drought and other environmental conditions.

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

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

Table of Contents

we designate these contracts as hedges for accounting purposes pursuant to the requirements of ASC TOPIC 815, Derivatives and Hedging.

Interest Rate Risk

We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results from holding a revolving promissory note which bears a variable interest rate. At September 30, 2010, there was no outstanding balance on this note. We are subject to interest at the rate of LIBOR plus 2.0% on the outstanding balance.

Commodity Price Risk

We are also exposed to market risk from changes in commodity prices. Exposure to commodity price risk results from our dependence on grain and natural gas in the ethanol production process. We seek to minimize the risks from fluctuations in the prices of grain and natural gas through the use of hedging instruments. In practice, as markets move, we actively manage our risk and adjust hedging strategies as we believe appropriate. Although we believe our hedge positions accomplish an economic hedge against our future purchases, they are not designated as such for hedge accounting purposes, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged. We are marking to market our hedge positions, which means as the current market price of our hedge positions changes, the gains and losses are immediately recognized in our cost of goods sold. For example, it is likely and we would generally expect that a 10% increase in the cash price of grain and natural gas would produce an increase in the fair value of our derivative instruments equal to approximately $23,186 based on our positions at September 30, 2010.

The immediate recognition of hedging gains and losses can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged. As of September 30, 2010, the fair value of our derivative instruments for grain is an asset in the amount of $231,862. We recorded an unrealized loss in the amount of $239,348 for the fiscal year ended September 30, 2010. There are several variables that could affect the extent to which our derivative instruments are impacted by price fluctuations in the cost of grain or natural gas. However, it is likely that commodity cash prices will have the greatest impact on the derivatives instruments with delivery dates nearest the current cash price.

To manage our grain price risk, our hedging strategy is designed to establish a price ceiling and floor for our purchases. We have taken a net long position on our exchange traded futures and options contracts, which allows us to offset increases or decreases in the market price of grain. The upper limit of loss on our futures contracts is the difference between the contract price and the cash market price of corn and milo at the time of the execution of the contract. The upper limit of loss on our exchange traded and over-the-counter option contracts is limited to the amount of the premium we paid for the option.

We estimate that our expected grain usage is approximately 18 million bushels per year for the production of 49 million gallons of ethanol. We have approximately 5% our expected grain usage with price protection in place for fiscal year ending September 30, 2011. If we determine that obtaining price protection would be beneficial as we go further into 2011, we would likely do so using CBOT futures and options and over the counter option contracts. As grain prices move in reaction to market trends and information, our income statement may be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, price protection positions may cause immediate adverse effects, but are expected to produce long-term positive growth for us.

To manage our natural gas price risk, we entered into a natural gas purchase agreement with our natural gas supplier. This purchase agreement fixes the price at which we purchase natural gas. We currently have no forward contracts in place for our natural gas needs for fiscal 2011. We expect the natural gas prices to be somewhat flat during fiscal 2011 with the normal winter months fluctuations.

A sensitivity analysis has been prepared to estimate our exposure to grain and natural gas price risk. The table presents the fair value of our derivative instruments as of September 30, 2010 and September 30, 2009 and the potential loss in fair value resulting from a hypothetical 10% adverse change in such prices. The fair value of the positions is a summation of the fair values calculated by valuing each net position at quoted market prices as of the applicable date. The results of this analysis, which may differ from actual results, are as follows:

Period Ended	Fair Value		Effect of Hypothetical Adverse Change - Market Risk
September 30, 2010	$	231,862	$	23,186
September 30, 2009	94,771		9,477

Table of Contents

We are also exposed to market risk from changes in ethanol prices. These price fluctuations are minimized in part by advanced contract pricing of our ethanol, which is designed to establish a price floor for our ethanol sales. Currently, we have entered into priced contracts for the 95% of our anticipated ethanol production through the first three months of fiscal 2011. We have not currently contracted for any of our anticipated production beyond the first quarter of fiscal 2011. We will continue to advance contract for ethanol sales in fiscal 2011 to attempt to further reduce our risk related to price decreases. While this strategy minimizes the risk associated with downward price fluctuations of ethanol, it may also prevent us from realizing the full benefit of upward price movements. Although using priced contracts makes our revenue more predictable, we cannot predict the extent to which other factors such as inflation, government regulation or changing prices may affect our financial performance.

Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Members and Board of Managers

Western Plains Energy, L.L.C.

We have audited the accompanying balance sheets of Western Plains Energy, L.L.C. as of September 30, 2010 and 2009, and the related statements of income, changes in members’ equity, and cash flows for the years ended September 30, 2010 and 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Plains Energy, L.L.C. as of September 30, 2010 and 2009, and the results of its operations and its cash flows for the years ended September 30, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ StarkSchenkein, LLP

Denver, Colorado
December 17, 2010

Table of Contents

WESTERN PLAINS ENERGY, L.L.C.

BALANCE SHEETS

SEPTEMBER 30, 2010 AND 2009

	2010			2009
ASSETS

CURRENT ASSETS
Cash	$	5,313,931		$	8,352,894
Accounts receivable	6,821,011			4,852,593
Accounts receivable - government subsidies	—			700,000
Inventory	7,808,330			2,899,434
Prepaid expense	257,934			436,674
Commodities trading account- futures and options contracts	231,862			94,771
Total current assets	20,433,068			17,336,366

PROPERTY AND EQUIPMENT
Land	701,872			701,872
Land improvements	1,346,457			1,220,677
Manufacturing equipment	41,524,737			39,029,728
Buildings	3,011,442			3,011,442
Vehicles	589,648			550,480
Grain handling and other equipment	4,994,743			3,742,557
Office equipment, furniture, fixtures	191,437			184,188
Construction-in-progress	36,137			679,828
Spare parts	1,046,710			727,145
	53,443,183			49,847,917
Less: Accumulated depreciation	(41,122,166		)	(34,414,342		)
	12,321,018			15,433,575

OTHER ASSETS
Investment in industrial development revenue bonds	32,000,000			32,000,000
Water rights	340,408			340,408
Loan origination fees, net	129,239			162,947
Financing fees, net	153,788			160,521
Deposits	97,834			97,834
	32,721,269			32,761,710

TOTAL ASSETS	$	65,475,355		$	65,531,651

LIABILITIES AND MEMBERS’ EQUITY

CURRENT LIABILITIES
Accounts payable and accrued expenses	$	7,383,874		$	3,607,417
Accrued interest	5,111			5,056
Total current liabilities	7,388,985			3,612,473

LEASE OBLIGATION	32,000,000			32,000,000

COMMITMENTS AND CONTINGENCIES

MEMBERS’ EQUITY
Class A Capital Units, 16,002 issued and outstanding	10,910,140			10,910,140
Class B Capital Units, 12,068 issued and outstanding	7,940,895			7,940,895
Class C Capital Units, 350 issued and outstanding	250,000			250,000
Membership distributions	(90,362,700		)	(75,584,300		)
Accumulated comprehensive (loss)	(2,170,494		)	(1,931,146		)
Retained earnings	99,518,528			88,333,590
Total members’ equity	26,086,370			29,919,179

TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	65,475,355		$	65,531,651

Please refer to accompanying notes to financial statements.

Table of Contents

WESTERN PLAINS ENERGY, L.L.C.

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE FISCAL YEARS ENDED SEPTEMBER 30, 2010 AND 2009

	2010			2009

REVENUE	$	96,048,749		$	92,268,505
COST OF SALES	76,359,242			81,722,233
GROSS PROFIT	19,689,507			10,546,272

EXPENSES
General and administrative expenses	2,605,853			2,315,556
Depreciation expense	6,707,825			6,386,602
Amortization expense	40,440			40,440
Total expenses	9,354,118			8,742,598

Income from operations	10,335,389			1,803,674

Other income (expense)
Interest expense	—			(20,158		)
Interest income	40,961			73,148
Interest from industrial development revenue bonds	1,120,000			1,120,000
Plant lease expense	(1,120,000		)	(1,120,000		)
Grant and subsidy income	888,564			831,601
Other income (expense)	(79,976		)	10,165

Total other income	849,549			894,756

NET INCOME	11,184,938			2,698,430

Unrealized gains (losses) on grain contracts	(239,348		)	1,058,867

COMPREHENSIVE INCOME	$	10,945,590		$	3,757,297

NET INCOME PER UNIT
BASIC AND DILUTED	$	393.56		$	94.95

DISTRIBUTIONS PER UNIT	$	520.00		$	175.00
WEIGHTED AVERAGE UNITS OUTSTANDING
BASIC AND DILUTED	28,420			28,420

Please refer to accompanying notes to financial statements.

Table of Contents

WESTERN PLAINS ENERGY, L.L.C.

STATEMENT OF CHANGES IN MEMBERS’ EQUITY

FOR THE FISCAL YEARS ENDED SEPTEMBER 30, 2009 and 2010

	Class A			Class B			Class C			Membership			Retained		Accumulated
	Units	Amount		Units	Amount		Units	Amount		Distributions			Earnings		Comprehensive (loss)			Total

Balance September 30, 2008	16,002	$	10,910,140	12,068	$	7,940,895	350	$	250,000	$	(70,610,800	)	$	85,635,160	$	(2,990,013	)	$	31,135,382

Distributions to members										(4,973,500		)						(4,973,500		)

Change in grain hedge contracts															1,058,867			1,058,867

Net income													2,698,430					2,698,430

Balance September 30, 2009	16,002	$	10,910,140	12,068	$	7,940,895	350	$	250,000	$	(75,584,300	)	$	88,333,590	$	(1,931,146	)	$	29,919,179

Distributions to members										(14,778,400		)						(14,778,400		)

Change in grain hedge contracts															(239,348		)	(239,348		)

Net income													11,184,938					11,184,938

Balance September 30, 2010	16,002	$	10,910,140	12,068	$	7,940,895	350	$	250,000	$	(90,362,700	)	$	99,518,528	$	(2,170,494	)	$	26,086,370

Please refer to accompanying notes to financial statements.

Table of Contents

WESTERN PLAINS ENERGY, L.L.C.

STATEMENTS OF CASH FLOWS

FOR THE FISCAL YEARS ENDED SEPTEMBER 30, 2010 AND 2009

	2010			2009

OPERATING ACTIVITIES
Net income	$	11,184,938		$	2,698,430
Depreciation	6,707,825			6,386,602
Amortization	40,440			40,440
Gain (loss) on disposal of equipment	—			—
Change in unrealized losses on grain hedging contracts	544,526			1,058,866
Changes in assets and liabilities
Accounts receivable	(1,968,418		)	1,290,729
Accounts receivable - Government Subsidies	700,000			(328,081		)
Inventory	(4,908,896		)	1,297,662
Prepaid expenses	178,741			(228,703		)
Accounts payable and accrued expenses	3,776,457			(2,519,004		)
Accrued interest	55			291
NET CASH PROVIDED BY OPERATING ACTIVITIES	16,255,668			9,697,233

INVESTING ACTIVITIES
Purchase of property, plant and equipment	(3,595,266		)	(1,101,521		)
Investment in commodity trading accounts	(4,536,748		)	(17,278,556		)
Withdrawals from commodity trading accounts	3,615,783			19,515,999
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(4,516,231		)	1,135,922

FINANCING ACTIVITIES
Distributions to members	(14,778,400		)	(4,973,500		)
Proceeds from notes payable	—			—
Payment of notes payable	—			(8,119		)
Acquisition of membership units	—			—
NET CASH (USED IN) FINANCING ACTIVITIES	(14,778,400		)	(4,981,619		)

NET INCREASE (DECREASE) IN CASH	(3,038,963		)	5,851,536

CASH - BEGINNING OF PERIOD	8,352,894			2,501,358

CASH - END OF PERIOD	$	5,313,931		$	8,352,894

SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for income taxes	$	—		$	—
Cash paid for interest	$	—		$	19,868

Please refer to accompanying notes to financial statements.

Table of Contents

WESTERN PLAINS ENERGY, L.L.C.

NOTES TO FINANCIAL STATEMENTS

SEPTEMBER 30, 2010 AND 2009

NOTE 1 - NATURE OF OPERATIONS

Principal Business Activity

Western Plains Energy, L.L.C. (a Kansas limited liability company with its principal place of business in Gove County, Kansas; the “Company”) owns and operates a 40 million gallon nameplate capacity ethanol plant. The Company was organized on July 10, 2001 and began its principal operations in January 2004.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Revenue from the production of ethanol and related products is recorded when the product is loaded on the common carrier FOB “shipping point,” when title passes to customer. The distillers grain products are subject to a Purchase and Sales Agreement, and revenue is recognized upon delivery, FOB “Shipping point.” Interest income is recognized as earned. Income from government grant programs is recognized as costs are incurred. Government subsidies are recognized based on fulfillment of program criteria, completion of application and determination of available funding.

Derivatives and Financial Instruments

The Company accounts for derivatives in accordance with ASC 815-10, “Accounting for Derivative Instruments and Hedging Activities”. ASC 815-10 requires the recognition of derivatives in the balance sheet and the measurement of these instruments at fair value. Changes in the fair value of derivatives are recorded as a component of Cost of Sales unless the normal purchase or sale exception applies or hedge accounting is elected.

The Company enters into derivative instruments including future contracts, swap agreements and options to fix prices for a portion of future raw material requirements. The Company has designated, documented and assessed for hedge relationships, which mostly resulted in cash flow hedges that require the Company to record the derivative assets and liabilities at their fair value on the balance sheet with an offset in other comprehensive income. Amounts are removed from other comprehensive income as the underlying transactions occur and realized gains or losses are recorded. The Company has included in its cost of sales an aggregate of $623,925 of losses on completed contracts related to its hedging activities and has recorded an aggregate of $239,348 of unrealized losses as a credit to comprehensive income for the year ended September 30, 2010. This compares to losses on contracts of $3,833,914 and unrealized gains of $1,058,867 for the year ended September 30, 2009. At September 30, 2010, the commodities trading account-futures and options contracts amounted to $231,862, compared to $94,771 at September 30, 2009, which represents the lower of the cost or fair market value of the futures and options contracts recorded on the balance sheet.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Property and Equipment

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

Building and manufacturing equipment		5 - 31.5 years
Land improvements		15 years
Vehicles		7 years
Office equipment and furniture		7 years

Depreciation expense for the years ended September 30, 2010 and 2009 amounted to $6,707,825 and $6,386,602, respectively.

Table of Contents

Long-Lived Assets

The Company reviews the value of its non-current assets for impairment whenever events indicate that the carrying amount of the asset may not be recoverable. An impairment loss is recorded if the sum of the estimated future cash flows is less than the carrying amount of the asset. The amount of the loss is determined by comparing the estimated fair market value of the asset to the carrying amount of the asset. Such assessments did not result in any adjustment to the value of non-current assets.

Use of Estimates

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

Concentration of Credit Risk

The Company’s cash balances are maintained in bank depositories and periodically exceed federally insured limits. At September 30, 2010, the Company’s balances exceeded insured limits by $4,030,842.

Fair Value of Financial Instruments

Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of September 30, 2010. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, accounts receivable, accounts payable, and accrued liabilities. Fair values were assumed to approximate carrying values for these financial instruments because they are short term in nature and their carrying amounts approximate fair values.

Income Taxes

The Company is organized as a limited liability company under state law. As a limited liability company that has elected to be taxed as a partnership, the Company’s earnings pass through to the members and are taxed at the member level. Accordingly, no income tax provision has been included in these financial statements.

Earnings Per Capital Unit

For purposes of calculating basic earnings per capital unit, capital units subscribed for and issued by the Company are considered outstanding on the effective date of issuance. The Company has no potentially dilutive securities outstanding.

Segment Information

The Company follows ASC 220-10, “Disclosures about Segments of an Enterprise and Related Information”. Certain information is disclosed, per ASC 220-10, based on the way management organizes financial information for making operating decisions and assessing performance. The Company currently operates in a single segment and will evaluate additional segment disclosure requirements if it expands its operations.

Comprehensive Income

The Company reports comprehensive income in accordance with ASC 280-10, “Reporting Comprehensive Income,” which requires the reporting of all changes in equity during a period, except those resulting from investment by owners and distribution to owners, in a financial statement for the period in which they are recognized. This encompasses unrealized gains and losses from available-for-sale securities held. The Company recorded comprehensive losses of $239,348 and comprehensive income of $1,058,867 for the fiscal years ended September 30, 2010 and September 30, 2009, respectively, which recognized a decrease in the fair value of unfulfilled future purchase contracts for raw materials at September 30, 2010, while recognizing an increase in fair value at September 30, 2009.

Accounts Receivable

The Company’s accounts receivable are due from distributors in the ethanol and livestock feed industries. Credit is extended based on evaluation of a customer’s financial condition and collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the

Table of Contents

Company, and the condition of the general economy and the industry as a whole. The Company writes-off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. There was no allowance for doubtful accounts at September 30, 2010 or 2009.

Inventories

Inventories are stated at the lower of cost or market, determined on a first-in, first-out basis. Inventory reserves are established for obsolescence based on expiration dating of perishable products and excess levels of inventory on hand. Inventories at September 30, 2010 and 2009 consist of the following:

	2010		2009
Raw materials	$	6,031,517	$	1,543,721
Work-in-process	1,411,966		1,007,129
Finished goods	364,847		348,584
Total	$	7,808,330	$	2,899,434

Shipping and Handling

The cost of shipping products to customers is included in cost of goods sold. Amounts billed to a customer in a sale transaction related to shipping and handling is classified as revenue.

Recent Accounting Pronouncements

With the exception of those stated below, there have been no recent accounting pronouncements or changes in accounting pronouncements during year ended September 30, 2010 that are of material significance, or have potential material significance, to the Company.

In December 2009, the FASB issued Accounting Standards Update (“ASU”) No. 2009-17, “Consolidations (Topic 810) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.” ASU No. 2009-17 changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. ASU No. 2009-17 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity is required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. ASU No. 2009-17 is effective for fiscal years beginning after November 15, 2009, and interim periods within those fiscal years. The Company adopted ASU No. 2009-17 as of January 1, 2010, and its application had no impact on the Company’s financial statements.

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition (Topic 605) - Multiple-Deliverable Revenue Arrangements.” ASU No. 2009-13 addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services (deliverables) separately rather than as a combined unit. This guidance establishes a selling price hierarchy for determining the selling price of a deliverable, which is based on: (a) vendor-specific objective evidence; (b) third-party evidence; or (c) estimates. This guidance also eliminates the residual method of allocation and requires that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. In addition, this guidance significantly expands required disclosures related to a vendor’s multiple-deliverable revenue arrangements. ASU No. 2009-13 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010 and early adoption is permitted. A company may elect, but will not be required, to adopt the amendments in ASU No. 2009-13 retrospectively for all prior periods. The Company is currently evaluating the requirements of ASU No. 2009-13 and has not yet determined its impact on the Company’s financial statements.

Table of Contents

disclosures and, thus, increase the transparency in financial reporting. The adoption of this ASU did not have a material impact on the Company’s financial statements.

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which provides amendments to ASC topic “Fair Value Measurements and Disclosures”. This will provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) the transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. The Company is currently assessing the impact that the adoption will have on its disclosures.

In February 2010, the FASB issued ASU 2010-09 (ASU 2010-09), “Subsequent Events (Topic 855).” The amendments remove the requirements for an SEC filer to disclose a date, in both issued and revised financial statements, through which subsequent events have been reviewed. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. GAAP. ASU 2010-09 is effective for interim or annual financial periods ending after June 15, 2010. The Company does not expect the provisions of ASU 2010-09 to have a material effect on the financial position, results of operations or cash flows of the Company.

There were various other updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company’s financial position, results of operations or cash flows.

NOTE 3 — MEMBERS’ EQUITY

On February 29, 2008, the Board of Managers announced that effective March 10, 2008, the Company’s units of membership interest would be split on a seven to one (7:1) basis. Unless otherwise stated, all units and per unit disclosures reflect the effect of the 7:1 split. Subsequent to the split, the Company purchased 140 Class B units from a member. The resulting units outstanding at September 30, 2010 are as follows:

Class A units		16,002
Class B units		12,068
Class C units		350
Total units		28,420

Historically, the Company had four classes of membership capital units: Class A, B, C and D. Capital units of each class were issued in denominations of $5,000 (pre-split).

Class A and Class B capital units were offered for sale in an initial public offering in 2002. A total of 27,769 Class A and B capital units were offered at a price of $714.29 per unit (adjusted to reflect the split) pursuant to a registration statement filed with the Securities and Exchange Commission, with a minimum of $15,735,000 and a maximum of $19,835,000 proceeds from such offering of units.

The Company’s Class A capital units were offered only to producers of agricultural products, with a minimum purchase of two (2) Class A Capital Units per investor (pre-split). The Company also offered to sell Class B capital units with a minimum purchase of seven (7) Class B capital units per investor (pre-split).

The Offering was completed in 2003 with 14,840 Class A and 12,208 Class B units sold for gross proceeds of $19,330,000.

For Class C capital units subscribed in a private placement prior to the public offering, 10% of the offering price was due upon subscription with the remaining amount executed as a promissory note due at the call of the Board of Managers. In 2003, the Company closed the sale of 350 Class C Units, totaling $250,000, from Ethanol Products, LLC.

Class D capital units were offered for sale prior to the public offering at a price of $5,000 per unit to the members of the Board of Managers and certain others. Total equity raised from the sale of Class D units was $415,000 during the year ended December 31, 2001. Upon completion of the public offering, which occurred in March 2003, 581 Class D units automatically converted into 1,162 Class A capital units. The Company must approve all transfers or other dispositions of capital units.

Voting rights are one vote per member for Class A capital units, and one vote per unit for Class B and Class C capital units. Members elect the Board of Managers, and members must approve any merger or consolidation with another business entity, sale of

Table of Contents

substantially all of the Company’s assets or voluntary dissolution. The Board of Managers decides all other matters regarding operation and management of the Company, including amendment of the Operating Agreement.

Income and losses are allocated to members based on their respective percentage of membership interest. Distributions to members must be no less than 20% of net cash from operations, as defined in the Operating Agreement, if net cash from operations exceeds $500,000 on an annual basis, provided that any such distribution does not constitute or cause a default under any of the Company’s loan documents or credit facilities.

Upon dissolution of the Company, and after the payment of all debts and liabilities of the Company, the assets shall be distributed to the unit holders ratably in proportion to the credit balances in their respective capital accounts for all classes of units.

The Company made distributions to its members of $14,778,400 during the fiscal year ended September 30, 2010. In the fiscal year ended September 30, 2009, distributions paid to members totaled $4,973,500.

NOTE 4 - FINANCING ARRANGEMENTS

Construction and permanent financing

During July 2003, the Company entered into a credit agreement (“Credit Agreement”) with Ag Country Farm Credit Services, FLCA (“AgCountry”) that established a $22,000,000 (or 55% of construction costs, whichever is less) multiple-advance, non-revolving construction loan for construction of the ethanol plant. The construction note expired August 1, 2004, with the amount outstanding converted into a permanent term loan to be amortized over a 10 year period. During the construction period, interest-only payments equal to the London Interbank Offered Rate (LIBOR) plus 4% were due monthly. This loan was paid in full June 30, 2006.

A portion of the construction note was also converted into a $5,000,000 credit line (the “Revolving Loan”). The Revolving Loan was paid in full during September 2004. In addition, the Company entered into an agreement with Ag Country in October 2004 that established a $3,500,000 expansion loan to fund a portion of a plant expansion to increase ethanol production to 40,000,000 gallons per year nameplate capacity. This note was paid in full prior to September 30, 2005.

The term loan was subject to certain restrictive covenants, and required payment of origination, participation and other fees totaling $337,107 and an annual administrative fee of $25,000. The $362,107 of financing costs are being amortized over the life of the loan (10 years), commencing with the loan’s conversion into a permanent loan in August 2004. Of that amount, $40,440 was amortized and expensed in each of the years ended September 30, 2010, 2009, 2008, 2007 and 2006. In the fiscal year ended September 30, 2005, $41,005 was amortized and $10,669 was amortized over the nine months ended September 30, 2004. The annual administrative fee is amortized over 12 months.

The Third Amendment to the Credit Agreement was executed on March 7, 2006, which increased allowable dividends to up to 75% of net income with distributions up to 100% of net income, so long as the Company maintains working capital that exceeds $5,000,000 and a defined leverage ratio of 0.60:1. The Amendment also waived certain compliance requirements for dividends paid in prior periods.

The Fourth Amendment to the Credit Agreement was entered into on October 2, 2006, which reduced the variable interest rate applicable to the Revolving Loan to LIBOR plus 2.50%. In addition, the annual administration fee was suspended and the quarterly “unused commitment fee” was reduced from 0.5% to 0.25% of the unused Revolving Loan balance during the quarter. The Capital Expenditure section was deleted and replaced with a requirement for pre-approval of capital expenditures in excess of $2,500,000 for any fiscal year. Written approval is required for capital expenditures which exceed this limit.

The Fifth Amendment to the Credit Agreement was entered into on May 2, 2007, which increased the Revolving Loan limit to $8,000,000 and reduced the variable interest rate from LIBOR plus 2.50% to LIBOR plus 2.00%.

There was no outstanding balance on the Revolving Loan at September 30, 2010.

During the period ended September 30, 2004, the Company entered into two irrevocable standby letters of credit (the “Letters of Credit”) for $120,000 and $500,000, respectively. The Letters of Credit are for the benefit of the Company’s utility provider. The Letters of Credit expire on December 31, 2011.

In December 2005, the Company purchased 80 acres of land for $96,000. The terms of the agreement required the Company to pay $24,000 prior to December 31, 2005, and an additional $24,000 prior to January 31, 2006. All payments were made in a timely manner. The balance of $24,000 was paid in January 2008 plus accrued interest at the rate of 6.0% per annum.

Table of Contents

NOTE 5 - COMMITMENTS, CONTINGENCIES AND AGREEMENTS

The Company has entered into various agreements regarding its formation, operation and management. Significant agreements are as follows:

Employee 401(k) Plan

The Company established a 401(k) retirement plan on November 1, 2004 for its employees. The Company matches employee contributions to the plan up to 5% of each eligible employee’s gross compensation. The amount contributed by the Company is vested 25% per year on behalf of the employee. The Company contributed $71,674 and $75,526 for fiscal years ended September 30, 2010 and 2009, respectively.

Energy Management Services

The Company has entered into an agreement with U.S. Energy Service, Inc. for energy management and engineering services. The initial term of the agreement expired on August 31, 2003, and is renewable for one-year terms unless terminated by either party with 30 days advance notice. The agreement provides for fees of $2,800 per month. The agreement was renewed through August 31, 2010, and again through August 31, 2011.

Sales Service Agreement

The Company has entered into an agreement with United Bio Energy, LLC (“UBE”) (see Notes 7 and 10) for the sale of the bulk feed grade products (distillers grains) produced from the plant. The agreement expired September 30, 2010, and was automatically renewed for a one-year term pursuant to the terms of the agreement. Under the terms of the agreement, UBE purchases all products at a price equal to 98% or 97.5% of the selling price depending on whether it is wet or dry grains, less applicable freight. If the product is sold to members of the Company, UBE will pay an additional 0.5% to the members, less applicable freight. UBE is responsible for billing and account servicing of the product sales and for losses related to non-payment unless such non-payment relates to substandard products.

Marketing Agreement

On November 24, 2008, the Company entered into a new marketing agreement with Ethanol Products, LLC dba POET Ethanol Products for marketing the Company’s ethanol and certain administrative services. The commencement date of the new agreement was February 1, 2009 for a five (5) year term, and will automatically renew for an additional five (5) year period unless terminated by either party ninety (90) days prior to the end of the term. The Marketing and Service Fee paid to the marketer shall be one percent (1%) of the net-back sales price per gallon of the ethanol sold.

Fermenter Contract

The Company contracted with ICM, Inc. to construct a fifth fermenter on December 7, 2009 at a cost of $2,236,131. With this addition, it allowed the fermentation process to be extended from 52 hours to 65 hours per batch which increased the amount of starch converted to sugars. This project was completed and placed in operation May 6, 2010, with all related invoices paid prior to September 30, 2010.

NOTE 6 - RELATED PARTY TRANSACTIONS

The Company has reimbursed members of the Board of Managers for certain expenses incurred by the Company and paid by the members of the Board of Managers including attending Board meetings. Expense reimbursements for the years ended September 30, 2010 and 2009 totaled $62,933 and $48,831, respectively.

NOTE 7 — INCENTIVE PAYMENTS

The United States Department of Agriculture Rural Development instituted the “Advanced Biofuel Payment Program” during fiscal year 2009, which allocated up to $25,000,000 to be paid to producers who qualify for advanced biofuel feedstocks used to produce renewable energy. The Company has applied for this program and has been accepted as a qualified participant pursuant to the use of milo as a feedstock. The Company received payments during fiscal 2010 totaling $1,073,704, of which $700,000 was accrued and recorded as income during fiscal 2009. Subsequent to its 2010 fiscal year end, the Company received an additional payment of $374,079 which will be recorded as income in the first quarter of fiscal 2011. Additionally, the Company also qualifies for production

Table of Contents

incentive payments under a State of Kansas program. The Kansas program is limited to an amount of $1,125,000 per year for each producer in excess of five million gallons per year at the rate of $0.075 per gallon. During the year ended September 30, 2010, the Company recorded revenue of $514,860, which was received in August 2010.

NOTE 8 — SALE / LEASEBACK TRANSACTION

On October 3, 2003, the Company completed an industrial revenue bond financing with Gove County, Kansas that has and will provide property tax savings for 10 years on the plant site. As part of the financing, title to the plant site and improvements have been transferred to Gove County, as security for the repayment of the bonds, and the Company is leasing back the site for an amount that is equal to the amount of interest to be paid on the Gove County bonds. AgCountry consented to this transaction, and the bonds have been pledged to AgCountry as security for any obligations under the AgCountry Credit Agreement. As part of the financing, the Company paid the bond underwriter, W.R. Taylor, $160,000 and agreed to pay an additional $40,000 only if the bonds are converted to a variable rate and remarketed by W.R. Taylor. The maximum principal amount of the bonds is $32,000,000.

The $160,000 of financing fees paid to the bond underwriter and $42,040 of legal and other cost associated with the bond closing are being amortized over the 30-year life of the bonds. A total of $6,732 of amortization expense was recognized during each of the years ended September 30, 2010 and 2009.

The Company, as holder of the industrial revenue bonds, is due interest at 3.5% per annum with interest payable semi-annually on March 1st and September 1st. This interest income is directly offset by the lease payments on the plant. Both the bond and the corresponding lease have terms of 30 years. The lease qualifies as a capital lease. Interest income recognized on the Industrial Revenue Bonds for the periods ended September 30, 2010 and 2009 were $1,120,000 per year. This amount is equal to the lease expense of the plant in each respective period.

NOTE 9 — CONCENTRATION OF CUSTOMERS

The Company sells essentially all of its products to two marketers, which in turn sell to other purchasers. The Company has executed an exclusive marketing agreement with POET Ethanol Products (see Note 6) to market the ethanol produced at its plant. The agreement with POET Ethanol Products commenced effective February 1, 2009 and is automatically renewable for subsequent five-year terms unless terminated by either party prior to expiration. POET Ethanol Products has agreed to purchase all of the ethanol that is produced at the plant. POET Ethanol Products is solely responsible for determining the price and terms at which the ethanol acquired from the plant is sold and to whom it is sold.

The Company also has executed an exclusive agreement with UBE to market all of the distillers grains produced at the plant. The initial term of the agreement with UBE expired September 30, 2006 and has automatically renewed for successive one-year terms. The agreement is automatically renewed each year unless terminated by the Company or UBE following 90 days advance written notice.

NOTE 10 - REGULATION

The construction of the plant required various state and local permits to comply with existing governmental regulations designed to protect the environment and worker safety. While the Company is subject to regulations on emissions by the United States Environmental Protection Agency (“EPA”), current EPA rules do not require the Company to obtain any permits or approvals in connection with the construction of the plant or operation of the Company’s business. However, state and federal rules can and do change and such changes could result in greater regulatory burdens on the Company.

The ethanol production requires the Company to emit a significant amount of carbon dioxide into the air. Current Kansas law regulating emissions does not restrict or prevent the Company from emitting carbon dioxide gas into the air, but this could change in the future.

The Company obtained what is believed to be all the necessary air and water permits to operate the plant, including a permit to discharge wastewater from the plant.

In addition to the foregoing regulations affecting air and water quality, the Company is subject to regulation for fuel storage tanks. If the Company is found to have violated federal, state or local environmental regulations in the future, the Company could incur liability for clean-up costs, damage claims from third parties and civil or criminal penalties that could adversely affect its business.

Table of Contents

NOTE 11 - SUBSEQUENT EVENTS

Based on the Company’s financial condition at September 30, 2010, on October 19, 2010, the Board of Managers declared a distribution to members equal to $100 per unit totaling $2,842,000. This distribution was paid November 19, 2010.

On December 1, 2010, the Company received a payment of $374,079 from the USDA Rural Development Program.

The Company evaluated all events subsequent to the balance sheet date of September 30, 2010, through the date of issuance of these financial statements and has determined that, except as set forth above, there are no further subsequent events that require disclosure.

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

There has been no change in our independent accountants since 2003. StarkSchenkein, LLP has been our independent registered accounting firm since that time.

Item 9A. Controls and Procedures.

(a) Our management supervised and participated in an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2010. Based on that evaluation, our management, including our principal executive officer and principal financial officer, concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed in the reports filed or submitted by the company under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure within the time periods specified in the SEC’s rules and forms.

This report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report, which is included in Item 8 above, was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this annual report.

(b) There were no changes in our internal control over financial reporting during the quarter ended September 30, 2010 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.

The Securities Exchange Act of 1934 defines internal control over financial reporting in Rules 13a-15(f) and 15d-15(f) as a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

· Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and disposition of assets;

· Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and

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

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems that are determined to be effective provide only reasonable assurance with respect to financial statement preparation and presentation. 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 the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting based on criteria for effective internal control over financial reporting described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Table of Contents

Based on its assessment, management concluded that we maintained effective internal control over financial reporting as of September 30, 2010.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The following are the members of our Board of Managers and Executive Officers at September 30, 2010:

Name	Age	Positions With the Company	Manager Since

Jeff Torluemke(1)(4)	51	Board President, Manager	2001

Richard Sterrett(2)	66	Board Vice President, Manager	2001

Ben Dickman(1)(2)	56	Board Secretary, Manager	2001

Brian Baalman(2)	52	Manager	2001

Ron Blaesi(1)(2)(3)	61	Manager	2001

Scott Foote	34	Chief Financial Officer, Manager	2006

Gary Johnson (3) (4)	64	Manager	2001

David Mann (1)(2)(3)	59	Manager	2001

Jeff Roskam (4)	53	Manager	2007

Steven McNinch	42	Chief Executive Officer, General Manager	N/A

Curt Sheldon	61	Chief Accounting Officer	N/A

(1) Member of the Audit Committee.

(2) Member of the Risk Management Committee.

(3) Member of the Nominating Committee.

(4) Member of the Compensation Committee.

Each of our Managers is elected for a three-year term and serves continuously until his successor is elected and qualified or until he resigns or is removed. Our Board consists of staggered terms so that each year the term expires for three Managers at the annual meeting of members. The Chief Executive Officer and Chief Accounting Officer serve at the pleasure of the Board.

The following information summarizes the business experience of each of our Managers and Executive Officers for at least the last five years:

Jeff Torluemke. Mr. Torluemke has been a member of our Board of Managers since our company’s inception. He serves as President of the Board. Mr. Torluemke served as our Chief Executive Officer from 2001 until November 12, 2003 and again from January 2006 to January 2007. Mr. Torluemke received a Bachelor of Science in Agricultural Economics from Colorado State University in 1981. He has been the executive vice president of the State Bank of Hoxie since 1993. From 1985 to 1993, he held various positions, including Chairman of the Peoples State Bank in Colby, Kansas. He has also farmed in the Hoxie, Kansas area since 1976. He has served as president of the Bankers Association of Northwest Kansas, and on the Agricultural Committee of the Kansas Bankers Associations.

Table of Contents

Richard Sterrett. Mr. Sterrett has been a member of our Board since our company’s inception and has also served as our Chief Financial Officer and Vice President of the Board since that time. Mr. Sterrett attended Fort Hays State College. He has been farming in the Quinter, Kansas area since 1961. He owned Sterrett Chemical Co. for 35 years until 2003. Mr. Sterrett is a member of the Smoky Hill-Saline Basin Advisory Committee to the Kansas Water Authority.

Ben Dickman. Mr. Dickman has been a member of our Board since our company’s inception. He serves as Secretary of the Board. He received a Bachelor of Science in Agricultural Economics from Kansas State University in 1975. He has been farming in the Grinnell, Kansas area since 1976 and is a past member of the School Board for the U.S.D. 291 Grinnell School District.

Brian Baalman. Mr. Baalman has been a member of our Board since our company’s inception. He has been farming in Sheridan, Thomas and Gove counties in Kansas since 1974. He also owns a 10,000-head feed yard that he leases to a third party. He is a lifetime resident of Menlo, Kansas. Mr. Baalman is currently the President of the Kansas Corn Growers Association and is a commissioner on the Kansas Corn Commission. He also serves on the National Corn Growers Ethanol Committee. He has previously served as president of the Northwest Kansas Corn Growers Association and as a member of his local church board.

Ron Blaesi. Mr. Blaesi has been a member of our Board since our company’s inception. He received a Bachelor of Science degree in History from Kansas State University in 1971. Mr. Blaesi has been a cash grain farmer since 1971 in the Sharon Springs area of Kansas. He has held various positions on the Kansas Corn Commission, National Corn Growers Association, as well as the U.S. Grain Council. He has also previously served as President of the Wallace County Farm Bureau, the Northwest Kansas Farm Management Association, Northwest Kansas Agricultural Tax Service, Wallace County Historical Society, National Renewable Energy Fund and United Methodist Men. Mr. Blaesi has also served on the Board of Directors of the Wallace County Farmers Union.

Scott Foote. Mr. Foote was elected to our Board in March 2006. He grew up on a farm in Bucyrus, Kansas and moved to Hoxie when his family purchased Hoxie Feedyard in 1997. He currently acts as manager of Hoxie Feedyard and serves as our Chief Financial Officer. He graduated from Kansas State University in 1997 with a bachelor’s degree in Agricultural Economics and in 2004 with a master’s degree in Agribusiness. Mr. Foote is a member of Hoxie Elks Lodge, Hoxie Rotary Club, Kansas Cattlemen’s Association and R-CALF United Stockgrowers of America.

Gary Johnson. Mr. Johnson has been a member of our Board since our company’s inception. He graduated from Cowley County Junior College. He has been co-owner of Mitten Truck Stop, Inc. for the past 39 years, and currently serves on the board of the Kansas Petroleum Marketers Association. He is a past board member of the National Texaco Travel Plaza Association and the National Texaco Wholesale Association. He has also sat on the Logan County Fair Board and was past president of the Oakley Country Club.

David Mann. Mr. Mann has been a member of our Board since our company’s inception. He attended Kansas State University. Mr. Mann has been a farmer and cattle rancher in the Quinter, Kansas area for 32 years. He has served on the school board for the U.S.D. 293 School District, and the board of the Northwest Kansas Educational Service Center in Oakley, Kansas.

Jeff Roskam. Mr. Roskam was elected to our Board in 2007. He currently serves as the chief executive officer of the Kansas Alliance for Biorefining and Bioenergy, a non-profit corporation created to identify barriers and implementing solutions for the growth and expansion of the biomass industry. He also operates Roskam Industries, Inc., a renewable fuels consulting firm and is the majority partner in CAP CO2, LLC, a carbon dioxide market development firm. Mr. Roskam was the president and founder of United Bio Energy Ingredients, LLC (“UBE Ingredients”), a partnership jointly owned by ICM, Inc. and Fagen, Inc. from January 2004 through April 1, 2006. Mr. Roskam also served as vice president of US BioEnergy Corp. after it acquired UBE Ingredients in May 2005. UBE Ingredients markets distillers’ grains throughout the Midwest for numerous ethanol producers, including our company. Immediately prior to starting UBE Ingredients, he spent seven years at ICM, Inc., an ethanol process technology and construction firm, where he was the senior vice president. Prior to that, he was an operations manager for Renewable Oxygenates, Inc. a Wisconsin cheese whey-to-ethanol firm and worked three years as an engineering project manager for Broin and Associates, an ethanol processing engineering firm. Mr. Roskam has previously served on the founding board of directors of Badger State Ethanol, located in Monroe, Wisconsin, and US Energy Partners of Russell, Kansas. He also served on the board of directors of Big River Resources of West Burlington, Iowa and Denco, LLC of Morris, Minnesota. Mr. Roskam grew up on an Iowa farm and worked as a mechanic and industrial electrician before he attended Iowa State University and received a degree in Business Administration.

Steven McNinch. Mr. McNinch was appointed General Manager of our company in February 2006 and was appointed Chief Executive Officer on January 25, 2007. Immediately prior to his appointment as General Manager, Mr. McNinch served as the polyurethane department manager for the Belleville Shoe Manufacturing Company in Belleville, Illinois, where he was responsible for day-to-day operations, capital budgeting and staffing of the department, a position he had occupied since November 2004. Between 2002 and November 2004, he was the manufacturing manager for DBM Technologies of Owensboro, Kentucky, where he was responsible for the day-to-day operations of two manufacturing facilities engaged in the production of plastic automotive components.

Table of Contents

From 1998 to 2001, Mr. McNinch served as the manager of manufacturing for Rubbermaid in Winfield, Kansas, where he was responsible for the day-to-day operation of two manufacturing facilities engaged in the production of household products. Mr. McNinch serves as the chairman of the Kansas Association of Ethanol Producers and also serves as a board member of Growth Energy, an ethanol industry advocacy group. He received a Bachelor of Arts in Chemistry and Physics in 1995 and a Master of Business Administration in 2002 from Southwestern College located in Winfield, Kansas.

Curt Sheldon. Mr. Sheldon was appointed Chief Accounting Officer in May 2008. Immediately prior to his appointment as Chief Accounting Officer, Mr. Sheldon served as the Company’s controller since 2005 and he continues to assist the Company in that capacity. Prior to joining the Company, he was the president and owner of Kalispell Glass and Doors, Inc., a provider of commercial and residential windows and doors, for 9 years. Mr. Sheldon was responsible for all management and accounting functions associated with that business. He received a Bachelor of Science degree in business administration from the University of California at Chico.

Compliance With Section 16(a) of the Exchange Act

Based on a review of Forms 3, 4 and 5, filed under the Securities Exchange Act of 1934, and written representations received by from our officers, members of our Board of Managers, and the holders of 10% or more of our membership units, we do not believe any individual failed to timely file such forms as required by Section 16 of the Exchange Act during the fiscal year ended September 30, 2010, however, we believe that Hoxie Feedyard, Inc., the owner of more than 10% of the outstanding membership units, has failed to file any reports required by Section 16.

Code of Ethics

On January 18, 2005, the Board of Managers adopted a code of ethics for our chief executive officer, principal financial and accounting officers, controller and persons performing similar functions for our company. The code is designed to promote honesty and integrity and to avoid conflicts of interest between personal and professional relationships in conducting our affairs. We filed the Code of Ethics as Exhibit 14 to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 and any interested member may obtain a copy without charge by contacting Debbie Nelson at (785) 672-8810 or dnelson@wpellc.com.

Nominating Committee and Changes to Procedures in Which Members May Recommend Nominees

The Nominating Committee, comprised of Ron Blaesi, Gary Johnson and Dave Mann, is responsible for identifying and evaluating potential candidates for nomination to the Board of Managers and reporting to the Board thereon. Our Board has adopted the following criteria which an individual must meet in order to be nominated to our Board of Managers: (i) the individual must be a natural person over 21 years of age; (ii) the individual should have management experience; (iii) the individual should have knowledge about the issues affecting the Company’s business; (iv) the individual should have exemplary personal integrity and reputation, sound judgment, and strong decision-making ability; (v) independence; and (vi) the individual should have sufficient time to devote his or her energy and attention to the diligent performance of his or her duties, including, but not limited to, review of our company’s documents, SEC filings and other materials and the attendance at Board and committee meetings, as applicable.

There have been no material changes to the procedures by which our members can recommend nominees to the Nominating Committee of the Board of Managers.

Audit Committee

The Audit Committee, comprised of Jeff Torluemke, Ben Dickman, Ron Blaesi and David Mann, oversees the selection and appointment of our independent registered public accounting firm by the Board of Managers, reviews the proposed scope, content and results of the audit performed by the accountants and any reports and recommendations made by them. We believe the members of the Audit Committee meet the definition of “independent” as defined in Rule 5605 of the Nasdaq Stock Market Rules.

Our Board of Managers has determined that Jeff Torluemke qualifies as an audit committee financial expert, in that he has (i) an understanding of generally accepted accounting principles and financial statements; (ii) the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; (iii) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by our financial statements, or experience actively supervising one or more persons engaged in such activities; (iv) an understanding of internal controls over financial reporting; and (v) an understanding of the audit committee functions. Mr. Torluemke acquired these attributes through experience in connection with his responsibilities at the State Bank of Hoxie, where he serves as an officer.

Table of Contents

Item 11. Executive Compensation

Summary Compensation Table

The following table sets forth the total compensation paid to our named executive officers, which in this case is our General Manager and Chief Executive Officer and our Chief Accounting Officer, for the two most recent fiscal years. Our Chief Financial Officer, Scott Foote, is also a member of our Board of Managers and serves as Chief Financial Officer without compensation, thus he is omitted from the table below. We do not issue equity awards or administer a pension or non-qualified deferred compensation plan for our named executive officers, thus this information is omitted from the table below:

Name and Principal Position	Year	Salary		Bonus		Non-Equity Incentive Plan Compensation		All other Compensation			Total
Steven McNinch	2010	$	164,500	—		$	32,311	$	9,841	(2)	$	206,652
General Manager and Chief Executive Officer(1)	2009	$	159,625	$	25,000	$	8,183	$	9,640	(3)	$	202,448

Curt Sheldon	2010	$	87,315	$	28,391	$	—	$	5,635	(5)	$	121,341
Chief Accounting Officer(4)	2009	83,565		8,582		—		4,434		(6)	96,581

(1) Mr. McNinch was appointed our General Manager effective February 21, 2006. On January 25, 2007, Mr. McNinch was appointed our Chief Executive Officer.

(2) Includes $9,841 for the company’s portion of contributions to Mr. McNinch’s 401(k).

(3) Includes $9,640 for the company’s portion of contributions to Mr. McNinch’s 401(k).

(4) Mr. Sheldon was appointed Chief Accounting Officer on May 20, 2008.

(5) Includes $5,635 for the company’s portion of contributions to Mr. Sheldon’s 401(k).

(6) Includes $4,434 for the company’s portion of contributions to Mr. Sheldon’s 401(k).

We maintain a written employment agreement only with our General Manager and Chief Executive Officer. We executed a revised employment agreement effective January 25, 2009 with Mr. McNinch which increased his base salary to $164,500 to reflect his additional responsibilities as Chief Executive Officer of our company. Under the terms of Mr. McNinch’s employment agreement, he is entitled to non-equity incentive compensation payments of 0.33% of net earnings to be paid quarterly if our company meets certain minimum performance requirements, including positive cash flow from operations, a conversion rate of grain to anhydrous alcohol of at least 2.65 to 1 and production costs (less the price of grain) which do not exceed budgeted amounts by more than 5%. The incentive compensation program was implemented with the goal of significantly rewarding Mr. McNinch for outstanding performance. The amount of incentive compensation payable to Mr. McNinch may not exceed 110% of his base salary, or $180,950. During fiscal 2010, Mr. McNinch received $32,311 as non-equity incentive compensation, compared to $8,183 in fiscal 2009 due to our company’s improved financial performance.

Cash bonuses may be recommended by the Compensation Committee, in its discretion, based on individual and company performance. Other than as described above for Mr. McNinch, there is no specific bonus plan or policy in place setting forth timing of awards or establishing specific performance objectives for company executives and key employees. The Compensation Committee is vested with the discretion to determine the amounts and timing of any bonus awards, and past practice has led to the Committee recommending bonuses to be awarded on an annual basis. One of the primary factors the committee considers is the amount of cash paid in distributions to members during the fiscal year when considering bonuses. Mr. McNinch did not receive a discretionary cash bonus in 2010 or 2009, however he was awarded a signing bonus in the amount of $25,000 upon execution of his new employment agreement with our company.

If the employment agreement is terminated without “cause” as defined therein, Mr. McNinch is entitled to severance pay equal to two years’ base salary. The agreement also provides for continuing health and life insurance benefits until expiration of the agreement in the event Mr. McNinch is terminated without cause. The term of the employment agreement expires on January 25, 2012.

Mr. Sheldon’s base salary is determined by the Compensation Committee based on market rates for commensurate experience. Mr. Sheldon also receives cash bonuses solely at the discretion of the Committee. Mr. Sheldon received a cash bonus of $28,391 for fiscal 2010 as his pro-rated share of the pool of cash bonuses awarded to all employees of the company except the Chief Executive Officer as a result of our improved financial performance during the 2010 fiscal year.

Table of Contents

Additional benefits provided to named executive officers and key employees as part of their compensation packages include health, life and disability insurance and participation in our 401(k) plan. We believe these benefits are both reasonable and competitive. To the extent the named executive officers participate in these programs, they do so on the same basis as the other employees of our company.

Manager Compensation

Each member of the Board of Managers received a base fee of $600 per quarter for a total of $2,400 for the 2010 fiscal year. In addition to the base fee, each Manager, except the Board President and Secretary, received $300 for each meeting attended in person. The President and Secretary of the Board of Managers received $450 and $400, respectively, for each meeting attended in person during fiscal 2010. Managers also received $50 or $150 for each committee meeting attended during fiscal 2010, dependent upon the circumstances of the meeting. Committee members are compensated $150 for each committee meeting attended in person unless the meeting precedes or follows a regular board meeting, in which case committee members receive $50. We reimburse the Managers for reasonable expenses incurred by them in carrying out their duties as such. Members of the Board of Managers who are also holders of capital units will receive the same membership benefits that other members receive.

The following table sets forth the total compensation paid to the members of the Board of Managers in fiscal 2010. We do not issue equity awards, non-equity incentive plan compensation or administer a pension or non-qualified deferred compensation plan for its managers, thus this information is omitted from the table below:

Name	Fees earned or paid in cash		All other compensation		Total
Jeff Torluemke	$	7,650	$	—	$	7,650
Richard Sterrett	5,700		—		5,700
Ben Dickman	7,500		—		7,500
Brian Baalman	6,150		—		6,150
Ron Blaesi	6,000		—		6,000
Scott Foote	5,400		—		5,400
Gary Johnson	5,100		—		5,100
David Mann	5,550		—		5,550
Jeff Roskam	4,800		—		4,800

Item 12. Security Ownership of Certain Benefical Owners and Management

The following table sets forth information with respect to the ownership of our capital units by each officer and manager or manager nominee individually, all officers and managers as a group and all owners known to us to beneficially hold more than 5% of any class of the Company’s membership units. On March 10, 2008, we effected a seven-for-one forward split of our capital units and all of the information in this proxy statement has been adjusted to reflect that split.

As of December 23, 2010, we had issued and outstanding 16,002 Class A units; 12,068 Class B units; and 350 Class C units. Unless otherwise stated, the address of each individual is c/o Western Plains Energy, L.L.C., 3022 County Road 18, Oakley, Kansas 67748. All unit ownership listed in the table is direct, unless otherwise indicated.

The following unit holders have sole voting and investment power with respect to the units, unless otherwise indicated:

Class	Name	Number of Units	% of Class
Class A	Jeff Torluemke, Manager,(1)	245	1.53	%
Class A	Richard Sterrett, Manager, Officer(2)	336	2.10	%
Class A	Brian Baalman, Manager(3)	889	5.56	%
Class A	Ron Blaesi, Manager	84	0.52	%
Class A	Ben Dickman, Manager(4)	168	1.05	%
Class A	Gary Johnson, Manager	98	0.61	%
Class A	David Mann, Manager(5)	98	0.61	%
Class A	Jeff Roskam, Manager	0	0	%

Table of Contents

Class	Name	Number of Units	% of Class
Class A	Managers and Officers as a group(1) (2) (3) (4) (5)	1,918	11.98	%

Class B	Jeff Torluemke, Manager	714	5.92	%
Class B	Richard Sterrett, Manager, Officer(2)	56	0.46	%
Class B	Gary Johnson, Manager(6)	126	1.04	%
Class B	Scott Foote, Manager(7)	2,891	23.96	%
Class B	Hoxie Feedyard, Inc., Member(8)	2,891	23.96	%
Class B	Roch Meier, Member(9)	700	5.80	%
Class B	Brian Baalman, Manager	350	2.90	%
Class B	Jeff Roskam, Manager	0	0	%
Class B	Managers and Officers as a group(2) (6) (7)	4,137	34.28	%

Class C	POET-Ethanol Products, LLC(10)	350	100.00	%

(1) Includes 35 Class A units owned by Mr. Torluemke’s spouse, of which he disclaims beneficial ownership.

(2) All units are owned by Sterrett Partnership, LP. Mr. Sterrett is the general partner.

(3) Includes 84 Class A units owned by the Baalman Feedyard Partnership and 84 Class A units owned by the B2C Partnership. The Baalman Feedyard Partnership is a Kansas general partnership. Its two partners are: B2C Partnership, a Kansas general partnership owned and controlled by two Kansas corporations, one solely owned by Mr. Baalman and one solely owned by his spouse; and the Gary and Janice Baalman, L.P.

(4) Includes 28 Class A units owned by BJ Ag Producers, Inc., a Kansas corporation. Mr. Dickman is the president and 50% owner of BJ Ag Producers, Inc. Mr. Dickman’s spouse also owns 50% of BJ Ag Producers, Inc.

(5) Includes 42 Class A units owned by Mr. Mann’s spouse.

(6) Includes 56 Class B units owned by Mitten, Inc. Mr. Johnson owns 51% of Mitten, Inc., and is the president and general manager.

(7) Includes 2,891 Class B units owned by Hoxie Feedyard, Inc. Mr. Foote is the general manager of Hoxie Feedyard, Inc. and in that capacity has been given voting control over these units by voting agreement.

(8) Hoxie Feedyard, Inc.’s address is P.O. Box 65, Hoxie, Kansas, 67740.

(9) The unitholder’s address is HC 1 Box 53, Menlo, Kansas, 67753.

(10) POET-Ethanol Products, LLC’s address is 111 South Ellis, Wichita, Kansas, 67211.

Changes in Control

We know of no arrangements, including the pledge of any units, that would result in a change in control of the Company.

Related Party Transactions

POET-Ethanol Products, LLC. The owner of all of our outstanding Class C capital units, POET-Ethanol Products, LLC, markets all of the ethanol we produce. In exchange, we receive the gross sales price of the ethanol, less the costs of transportation and storage and an administrative fee of 1% of the net-back sales price received for our ethanol. During the fiscal years ended September 30, 2010 and 2009, we paid $633,109 and $719,220, respectively, in administrative fees to POET-Ethanol Products.

Our Board of Managers considers the arrangement with Ethanol Products to be no less favorable than could be obtained from an unaffiliated party.

Each manager or their affiliates own capital units in our company and as members they receive distributions under the same terms and conditions as other members.

Table of Contents

Board Independence

The Board of Managers has affirmatively determined that all of the Managers meet the definition of “independent” as defined in Rule 5605 of the Nasdaq Stock Market Rules except for Messrs. Foote and Sterrett. By virtue of Mr. Foote’s present service as Chief Financial Officer and Mr. Sterrett’s prior service as Chief Financial Officer, Messrs. Foote and Sterrett are not “independent” as defined in the rule.

Item 14. Principal Accounting Fees and Services.

The following table sets forth fees paid to (or accrued to) our principal accounting firm of StarkSchenkein, LLP for the two years ended September 30, 2010:

	2010		2009
Audit Fees	$	42,139	$	32,226
Audit Related Fees	25,299		29,495
All Other Fees	0		0
Total Fees	67,438		$	61,721

It is the policy of the Audit Committee to engage the principal accounting firm selected to conduct the financial audit for our company and to confirm, prior to such engagement, that such principal accounting firm is independent of our company. All services of the independent registered accounting firm reflected above were approved by the Audit Committee.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)	Financial Statements.

	Our financial statements and the report of the independent registered public accounting firm are contained in Item 8.

(b)	Exhibits.

	The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part of this report.

(c)	Financial Statement Schedules.

	None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized in Oakley, Kansas on December 23, 2010.

		WESTERN PLAINS ENERGY, L.L.C.


		By:	/s/ Steven R. McNinch
			Steven R. McNinch, Chief Executive Officer

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

Signature	Title	Date

/s/ Steven R. McNinch	Chief Executive Officer	December 23, 2010
Steven R. McNinch

/s/ Curt V. Sheldon	Chief Accounting Officer	December 23, 2010
Curt V. Sheldon

/s/ Scott Foote	Chief Financial Officer, Manager	December 23, 2010
Scott Foote

/s/ Jeff Torluemke	President, Manager	December 23, 2010
Jeff Torluemke

/s/ Brian Baalman	Manager	December 23, 2010
Brian Baalman

/s/ Ben Dickman	Manager	December 23, 2010
Ben Dickman

/s/ David Mann	Manager	December 23, 2010
David Mann

/s/ Ronald Blaesi	Manager	December 23, 2010
Ronald Blaesi

/s/ Jeff Roskam	Manager	December 23, 2010
Jeff Roskam

/s/ Gary Johnson	Manager	December 23, 2010
Gary Johnson

EXHIBIT INDEX

Exhibit No.	Description	Incorporated by Reference From
3.1(i)	Articles of Organization	Appendix A of our prospectus filed with the Commission pursuant to Rule 424(b)(3) on June 11, 2002 (File No. 333-74982)

3.1(ii)	Third Amended and Restated Operating Agreement	Exhibit 3 to our Form 10-QSB for the quarter ended June 30, 2003

4.1	Form of Class A Capital Unit Certificate	Exhibit 4.1 to our Form SB-2 filed with the Commission on December 12, 2001 (File No. 333-74982)

Table of Contents

4.2	Form of Class B Capital Unit Certificate	Exhibit 4.2 to our Form SB-2 filed with the Commission on December 12, 2001 (File No. 333-74982)

4.3	Form of Class C Capital Unit Certificate	Exhibit 4.3 to our Form SB-2 filed with the Commission on December 12, 2001 (File No. 333-74982)

10.1	Credit Agreement with AgCountry Farm Credit Services, FLCA dated July 29, 2003	Exhibit 10.1 to our Quarterly Report on Form 10-QSB for the quarter ended June 30, 2003 (File No. 333-74982)

10.2	Agreement between the Company and United Bio Energy Ingredients, LLC, dated August 2, 2004	Exhibit 10.8 to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2004 (File No. 0-50714)

10.3	Form of Second Amendment to the Credit Agreement with AgCountry dated July 29, 2004	Exhibit 10.9 to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2004 (File No. 0-50714)

10.4	Promissory Note/Loan Agreement with AgCountry dated November 16, 2004	Exhibit 10.10 to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2004 (File No. 0-50714)

10.5	Third Amendment to Credit Agreement with AgCountry dated March 7, 2006	Exhibit 10.1 to our Report on Form 8-K dated March 27, 2006 (File No. 0-50714)

10.6	Fourth Amendment to Credit Agreement with AgCountry dated October 2, 2006	Exhibit 10.12 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2007 (File No. 0-50714)

10.7	Employment Agreement with Steven McNinch effective January 25, 2007	Exhibit 10.1 to our Report on Form 8-K dated April 17, 2007 (File No. 0-50714)

10.8	Fifth Amendment to Credit Agreement with AgCountry dated May 2, 2007	Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 0-50714)

10.9	Ethanol Marketing Agreement with Ethanol Products, L.L.C. d/b/a POET Ethanol	Exhibit 10.1 to our Report on Form 8-K dated November 24, 2008 (File No. 0-50714)

14.1	Western Plains Energy, L.L.C. Code of Ethics for Principal Executive and Senior Financial Officers	Exhibit 14.1 to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 (File No. 0-50714)
31.1*	Certifications pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934

31.2*	Certifications pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as amended

32*	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith

WESTERN PLAINS ENERGY LLC 10-K