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 October 31, 2011.

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

for the transition period from to .

Commission File Number 000-51825

Heron Lake BioEnergy, LLC

(Exact name of registrant as specified in its charter)

Minnesota		41-2002393
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

91246 390th Avenue, Heron Lake, MN 56137-1375

(Address of principal executive offices)

Registrant’s telephone number, including area code: (507) 793-0077

Securities registered pursuant to Section 12(b) of the Act:		Securities registered pursuant to Section 12(g) of the Act:
Class A Units		None

Name of Exchange on Which Registered: None

Indicate by check mark whether 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 x 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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer.

Large Accelerated Filer o		Accelerated Filer o

Non-Accelerated Filer x		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 126-2 of the Act) Yes o No x

As of April 30, 2011, the aggregate market value of the Company’s Class A Units held by non-affiliates is not able to be calculated. The Company is a limited liability company whose outstanding common equity, consisting of its Class A Units, is subject to significant restrictions on transfer under its Member Control Agreement. No public market for common equity of Heron Lake BioEnergy, LLC is established and it is unlikely in the foreseeable future that a public market for its common equity will develop.

As of January 26, 2012, the Company had outstanding 38,622,107 Class A Units.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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PART I

When we use the terms “Heron Lake BioEnergy,” “we,” “us,” “our,” the “Company”, “HLBE” or similar words in this Annual Report on Form 10-K, unless the context otherwise requires, we are referring to Heron Lake BioEnergy, LLC and its subsidiaries, Lakefield Farmers Elevator, LLC, with grain facilities at Lakefield and Wilder, Minnesota, and HLBE Pipeline Company, LLC. Additionally, when we refer to “units” in this Annual Report on Form 10-K, unless the context otherwise requires, we are referring to the Class A units of Heron Lake BioEnergy, LLC.

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains historical information, as well as forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance, or our expected future operations and actions. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,” “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions. These forward-looking statements are only our predictions based on current information and involve numerous assumptions, risks and uncertainties. Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the reasons described in this report under Part I, Item 1A. “Risk Factors” of this Form 10-K.

We undertake no duty to update these forward-looking statements, even though our situation may change in the future. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report.

ITEM 1. BUSINESS

Overview

We were organized as a Minnesota limited liability company on April 12, 2001 under the name “Generation II, LLC.” In June 2004, we changed our name to Heron Lake BioEnergy, LLC.

We operated a dry mill, coal fired ethanol plant in Heron Lake, Minnesota. After completing a conversion in November 2011, we are now a natural gas fired ethanol plant. Our subsidiary, HLBE Pipeline Company, LLC, owns 73% of Agrinatural Gas, LLC, the pipeline company formed to construct, own, and operate a natural gas pipeline that provides natural gas to the Company’s ethanol production facility through a connection with the natural gas pipeline facilities of Northern Border Pipeline Company in Cottonwood County, Minnesota. Our subsidiary, Lakefield Farmers Elevator, LLC, has grain facilities at Lakefield and Wilder, Minnesota. At nameplate, our ethanol plant has the capacity to process approximately 18.0 million bushels of corn each year, producing approximately 50 million gallons per year of fuel-grade ethanol and approximately 160,000 tons of distillers’ grains with soluble (“DGS”). On September 21, 2007, we began operations at ethanol plant. Fiscal year 2007 was the first fiscal year that includes any revenue generated from our operations. In both our fiscal years 2011 and 2010 which ended October 31, 2011 and 2010, we sold approximately 53.4 million gallons of ethanol, respectively.

The following table sets forth a summary of significant milestones in our company’s history until we began operations at our plant.

Date		Milestone
February 2002		We obtained an option on land that is now part of the 216 acre site of our ethanol plant.

October 2003		We entered into an industrial water supply development and distribution agreement with the City of Heron Lake, Jackson County, and Minnesota Soybean Processors.

Early 2004		We selected Fagen, Inc. to be the design-build firm to build our ethanol plant near Heron Lake, Minnesota, using process technology provided by ICM, Inc.

September 2005		We entered into a Standard Form of Agreement between Owner and Designer — Lump Sum with Fagen, Inc.

December 2005		We purchased certain assets relating to elevator and grain storage facilities in Lakefield, Minnesota and Wilder, Minnesota with a combined storage capacity of approximately 2.8 million bushels.

May 2006		We entered into an industrial water supply treatment agreement with the City of Heron Lake and Jackson County.

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Date		Milestone
August 2006		We entered into an electric service agreement with Interstate Power and Light Company (a wholly-owned subsidiary of Alliant Energy Corporation).

December 2006		We entered into a contract with Federated Rural Electric Association for the construction of the distribution system and electrical substation for the plant.

June 2007		We entered into a master coal supply agreement with Northern Coal Transportation Company (NCTC) to provide Powder River Basin (PRB) coal for the plant.

June 2007		We entered into a coal transloading agreement with Southern Minnesota Beet Sugar Cooperative (SMBSC).

September 2007		We began operations at our dry mill, coal fired ethanol plant.

Production

Since the beginning of operations at our ethanol plant, our primary business is the production and sale of ethanol and co-products, including dried distillers’ grains. We currently do not have or anticipate we will have any other lines of business or other significant sources of revenue other than the sale of ethanol and ethanol co-products.

Our Ethanol Plant

Our ethanol plant was designed and built by Fagen Inc. under a September 2005 design-build agreement who used certain proprietary property and information of ICM, Inc. in the design and construction of our ethanol plant.

Our ethanol plant uses a dry milling process to produce fuel-grade ethanol and distillers’ grains. The dry milling process involves grinding the entire corn kernel into flour and the starch is converted to ethanol through fermentation that also produces carbon dioxide and distillers’ grains.

The ethanol plant consists principally of a natural gas combustion area; storage and processing areas for corn; a fermentation area comprised mainly of fermentation tanks; a distillation finished product storage area; and a drying unit for processing the dried distillers’ grains. Additionally, the ethanol plant contains receiving facilities that have the ability to receive corn by rail and truck, store it for use in the plant and prepare the corn to be used in the plant. We have storage tanks on site to store the ethanol we produce. The plant also contains a storage building and silos to hold distillers’ grains until it is shipped to market.

The Union Pacific Railroad is the railroad adjacent to our ethanol plant. The ethanol plant has the facilities necessary to receive corn by truck and rail, coal by truck, and to load ethanol and distillers grains onto trucks and rail cars.

Our ethanol plant requires significant and uninterrupted amounts of electricity, natural gas and water. We have entered into agreements for our supply of electricity, natural gas and water.

We are required to comply with various requirements of state and federal law regulating the operations at our plant, including regulations relating to air emissions. On July 2, 2010, we entered into a mutual release and settlement agreement with Fagen, Inc. and ICM, Inc. relating to the arbitration commenced by us in September 2009 in which we asserted claims against Fagen based on the design-build agreement for our ethanol plant and the plant’s air emissions. Please review the section entitled “Compliance with Environmental Laws and Other Regulatory Matters” for a description of how compliance with regulatory requirements, including requirements relating to air emissions, has impacted our business.

Our Principal Products

The principal products that we produce are fuel grade ethanol and distillers’ grains. Raw carbon dioxide is also a product of the ethanol production process, but we do not capture or market any carbon dioxide gas.

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Ethanol

Ethanol is a type of alcohol produced in the U.S. principally from corn. Ethanol is primarily used in the U.S. gasoline fuel market as:

· an octane enhancer in fuels;

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

· a gasoline substitute generally known as E85, a fuel blend composed of 85% ethanol; and

· as a renewable fuel to displace consumption of imported oil.

Ethanol used as an octane enhancer or fuel additive is blended with unleaded gasoline and other fuel products. The principal purchasers of ethanol are generally wholesale gasoline distributors or blenders.

Distillers’ Grains

The principal co-product of the ethanol production process is distillers’ grains, a high protein and high-energy animal feed ingredient.

Dry mill ethanol processing creates three primary forms of distillers’ grains: wet distillers’ grains, modified wet distillers’ grains, and dried distillers’ grains with solubles. Wet distillers’ grains are processed corn mash that contains a substantial amount of moisture. It has a shelf life of approximately three days and is primarily sold to feeders of beef animals within the immediate vicinity of the ethanol plant. Modified wet distillers’ grains are similar to wet distillers’ grains except that it has been partially dried and contains less moisture. Modified wet distillers’ grains has a shelf life of a maximum of fourteen days, contains less water to transport, is more easily adaptable to some feeding systems, and is sold to both local and regional markets, primarily for both beef and dairy animals. Dried distillers’ grains with solubles are corn mash that has been dried to approximately 10% moisture. It has an almost indefinite shelf life and may be sold and shipped to any market and to almost all types of livestock. Most of the distillers’ grains that we sell are in the form of dried distillers’ grains.

Procurement and Marketing Agreements

Corn Procurement

The primary raw material used in the production of ethanol at our plant is corn. We need to procure approximately 18 million bushels of corn per year for our dry mill ethanol process. We generally do not have long-term, fixed price contracts for the purchase of corn and our members are not obligated to deliver corn to us. Typically, we purchase our corn directly from grain elevators, farmers, and local dealers within approximately 80 miles of Heron Lake, Minnesota.

We generally purchase corn through cash fixed-price contracts and may utilize hedging positions in the corn futures market for a portion of our corn requirements to manage the risk of excessive corn price fluctuations. Our fixed-price forward contracts specify the amount of corn, the price and the time period over which the corn is to be delivered. These forward contracts are at fixed prices or prices based on the Chicago Board of Trade (CBOT) prices. Our corn requirements can be forward contracted on either a fixed-price basis or futures only contracts. The parameters of these contracts are based on the local supply and demand situation and the seasonality of the price. We also purchase a portion of our corn on a spot basis.

The price and availability of corn is subject to significant fluctuation depending upon a number of factors that affect commodity prices generally. These include, among others, crop conditions, crop production, weather, government programs, and export demands.

Natural Gas Procurement

Effective November 2011, the primary source of energy in our manufacturing process is natural gas. We have a facilities agreement with Northern Border Pipeline Company which allows us access to an existing interstate natural gas pipeline located approximately 16 miles north from our plant. We entered into a transportation agreement with Agrinatural Gas, LLC (“Agrinatural Gas”). Agrinatural Gas, owned by our subsidiary, HLBE Pipeline Company, LLC, and Rural Energy Solutions, was formed to own and operate the pipeline. Our Company owns 73% of the pipeline and its associated delivery of natural gas to the plant.

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We also entered into a base agreement for sale and purchase of natural gas with Constellation NewEnergy — Gas Division, LLC (“Constellation”). We will buy all of our natural gas from Constellation and this agreement runs for a three year period from November 1, 2011 to October 31, 2014.

Ethanol and Distillers’ Grains Marketing

Effective September 1, 2011, the Company entered into certain marketing, corn supply and corn storage agreements with Gavilon, LLC (“Gavilon”) to market the Company’s ethanol and distillers’ grains products and to supply the Company’s ethanol production facility with corn. Gavilon is now the exclusive corn supplier and ethanol and distillers’ grains marketer for the Company’s production facility beginning September 1, 2011 and for an initial term of two years. The Company believes that working with Gavilon to manage the Company’s marketing and procurement needs will provide a comprehensive solution to help the Company achieve its risk management objectives in a competitive market and will enable the Company to reduce its working capital requirements and more effectively manage its processing margins in both spot and forward markets.

The Company pays Gavilon a supply fee consisting of a per bushel fee based on corn processed at the facility and a cost of funds component determined on the amount of corn financed by Gavilon for supply to the Company’s ethanol production facility based on the length of time between when Gavilon pays for the corn stored in or en route to or from the Company’s elevator facilities or production facility, and when the Company is invoiced for that corn at the time it is processed at the Company’s production facility. The supply fee was negotiated based on prevailing market-rate conditions for comparable corn supply services. Both Gavilon and the Company have the ability to originate the corn requirements for the production facility. On the effective date of the corn supply Agreement, Gavilon purchased all corn inventory currently owned by the Company and located at its production facility or elevator facilities, at current market prices, to facilitate the transition to Gavilon supplying 100% of the Company’s corn requirements at the production facility and the repayment of the Company’s line of credit with AgStar Financial Services, PCA (“AgStar”).

Under the ethanol and distillers’ grains marketing agreement, Gavilon will purchase, market and resell 100% of the ethanol and distillers grains products produced at the Company’s ethanol production facility and the Company will pay Gavilon a marketing fee based on a percentage of the applicable sale price of the ethanol and distillers grains products. The marketing fees were negotiated based on prevailing market-rate conditions for comparable ethanol and distillers grains marketing services. On the effective date of the marketing agreement, Gavilon purchased all ethanol and distillers grains inventory currently owned by the Company and located at the Company’s production facilities, at current market prices.

The Company entered into a master netting agreement under which payments by the Company to Gavilon for corn under the corn supply agreement will be netted against payments by Gavilon to the Company for ethanol and distillers’ grains products produced and sold to Gavilon under the marketing agreement. Under the terms of the master netting agreement, the Company is giving Gavilon a first priority security interest in, and a right of set off against, the Company’s non-fixed assets including any rights it has to corn under the corn supply agreement, ethanol and distillers’ grains under the marketing agreement, the work-in-process at the Company’s ethanol production facility, and the other transactions under the Gavilon agreements. The master netting agreement is integral to the transition to the Gavilon agreements, and the termination and payoff of the Company’s seasonal revolving line of credit with AgStar.

As part of the transition to the Gavilon agreements, the Company entered into a termination agreement with CHS Inc. and C&N to terminate the marketing agreements the Company had with each, with termination dates of August 31, 2011 for each. The Company assumed certain rail car leases with the termination of the ethanol marketing agreement and will pay a termination fee of $325,000 over the remaining term of the original contract, which is scheduled to end September 30, 2012.

Pricing of Corn and Ethanol

The sale of ethanol represented approximately 80% of our revenue for the year ended October 31, 2011. The cost of corn represented approximately 76% of our cost of sales for the year ended October 31, 2011. We expect that ethanol sales will represent our primary revenue source and corn will represent our primary component of cost of goods sold. Therefore, changes in the price at which we can sell the ethanol we produce and the price at which we buy corn for our ethanol plant present significant operational risks inherent in our business.

Generally, the price at which ethanol can be sold does not track with the price at which corn can be bought. Historically, ethanol prices have tended to correlate with wholesale gasoline prices, with demand for and the price of ethanol increasing as supplies of petroleum decreased or appeared to be threatened, crude oil prices increased and wholesale gasoline prices increased. However, the prices of both ethanol and corn do not always follow historical trends. Trends in ethanol prices and corn prices are subject to a number of factors and are difficult to predict.

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Demand for Ethanol

In recent years, the demand for ethanol has increased, particularly in the upper Midwest, in part because of two major programs established by the Clean Air Act Amendments of 1990: the Oxygenated Gasoline Program and the Reformulated Gasoline Program. Under these programs, an additive (oxygenate) is required to be blended with gasoline used in areas with excessive carbon monoxide or ozone pollution to help mitigate these conditions. According to the EPA, reformulated gasoline is currently used in 17 states and the District of Columbia pursuant to the requirements of federal law. Additionally, according to the EPA, there are fifteen states that have their own clean fuel program. Approximately 30% of the gasoline sold in the United States is reformulated. Because of the potential health and environmental issues associated with methyl tertiary butyl ether (MTBE) and the actions of the EPA, ethanol is now used as the primary oxygenate in those areas requiring an oxygenate additive.

In addition to demand for ethanol as an oxygenate, ethanol demand has increased because of the adoption of programs setting national renewable fuels standards (RFS). The first RFS program (RFS1) was introduced through the Energy Policy Act of 2005. RFS1 required 7.5 billion gallons of renewable fuel to be blended into gasoline by 2012. With the passage of the Energy Independence and Security Act of 2007, Congress made several important revisions to the RFS that required the EPA to promulgate new regulations to implement these changes. In February 2010, the EPA establish the revised annual renewable fuel standard (RFS2) and to make the necessary program modifications as set forth in the Energy Independence and Security Act of 2007. Further, for the first time, the EPA set volume standards for specific categories of renewable fuels including cellulosic, biomass-based diesel, and total advanced renewable fuels. In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace. Our ethanol does not qualify for the new volume categories of renewable fuels and therefore, the total renewable fuel requirement for each year will be most relevant to the demand for, and required use of, ethanol such as ours. Under RFS2, the total renewable fuel requirement will increase from 12.95 billion gallons in 2010 to 36 billion gallons by 2022. Of the 12.95 billion gallons of total renewable fuel required for 2010, 100 million gallons must be from cellulosic biofuels, 650 million gallons biomass-based diesel, and 950 million gallons must be from advanced biofuels, with the remaining 11.25 billion gallons consisting of other renewable fuels. Of the 36 billion gallons of total renewable fuel required for 2022, 16 billion gallons must be from cellulosic biofuels, the requirement for biomass-based diesel will be determined by the EPA but will not be less than 1.0 billion gallons, and 21 billion gallons must be from advanced biofuels, with the remaining gallons consisting of other renewable fuels. The RFS for 2011 is approximately 14 billion gallons, of which corn based ethanol can be used to satisfy approximately 12.6 billion gallons. Current ethanol production capacity exceeds the 2011 RFS requirement which can be satisfied by corn based ethanol. We believe the RFS program creates greater market for renewable fuels, such as ethanol, as a substitute for petroleum-based fuels.

In addition to the RFS program, one important incentive for the ethanol industry and its customers is the Volumetric Ethanol Excise Tax Credit, commonly referred to as the “blender’s credit.” The tax credit is provided to gasoline distributors as an incentive to blend their gasoline with ethanol. For each gallon of gasoline blended with ethanol, the distributors receive a tax credit. For 2008, the tax credit was 51¢ per gallon of pure ethanol or 5.1¢ per gallon of gasoline blended with 10% ethanol. The per gallon credit was reduced to 45¢ per gallon of pure ethanol in 2009. The tax credit of 45¢ per gallon of pure ethanol was authorized through, and expired on, December 31, 2011.

Markets for Ethanol

There are local, regional, national and international markets for ethanol. Typically, a regional market is one that is outside of the local market, yet within the neighboring states. Some regional markets include large cities that are subject to anti-smog measures in either carbon monoxide or ozone non-attainment areas, or that have implemented oxygenated gasoline programs, such as Chicago, St. Louis, Denver and Minneapolis. We consider our primary regional market to be large cities within a 450-mile radius of our ethanol plant. In the national ethanol market, the highest demand by volume is primarily in the southern United States and the east and west coast regions.

The markets in which our ethanol is sold will depend primarily upon the efforts of Gavilon, which buys and markets our ethanol. However, we believe that local markets will be limited and must typically be evaluated on a case-by-case basis. Although local markets will be the easiest to service, they may be oversold because of the number of ethanol producers near our plant, which may depress the price of ethanol in those markets.

We transport our ethanol primarily by rail. In addition to rail, we service certain regional markets by truck from time to time. We believe that regional pricing tends to follow national pricing less the freight difference.

We believe that the E10 “blend wall” is one of the most critical governmental policies currently facing the ethanol industry. The “blend wall” issue arises because of several conflicting requirements. First, the renewable fuels standards dictate a continuing increase in the amount of ethanol blended into the national gasoline supply. Second, the EPA mandates a limit of 10% ethanol inclusion in non-flex fuel

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vehicles, and the E85 vehicle marketplace is struggling to grow due to lacking infrastructure. Total gasoline usage by the U.S. is expected to decrease over the next 5 years as fuel mileage standards are changed. RFS2 dictates an increasing amount of blending of total renewable fuels: 13.95 billion gallons in 2011, 15.2 billion gallons in 2012, and increasing to 36 billion gallons by 2022. To reach the standard as dictated by RFS2 in 2011, assuming 135 billion gallons of total gasoline usage nationally, each gallon of gasoline sold would have to be blended with greater than 10% ethanol. The EPA limit of 10% ethanol inclusion in non-flex fuel vehicles and the RFS increasing blend rate are at odds, which is sometimes referred to as the “blend wall.” While this issue has been considered by the EPA, there have been no regulatory changes that would reconcile the conflicting requirements. This issue is a major risk to the ethanol industry. During 2011, the United States Environmental Protection Agency allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2001 and later. Management believes that many gasoline retailers will refuse to provide E15 due to the fact that not all standard vehicles will be allowed to use E15 and due to the labeling requirements the EPA may impose. The EPA is considering instituting labeling requirements associated with E15 which may unfairly discourage consumers from purchasing E15. As a result, the approval of E15 may not significantly increase demand for ethanol.

Markets for Distillers’ Grains

We sell distillers’ grains as animal feed for beef and dairy cattle, poultry and hogs. However, the modified wet distillers’ grains typically have a shelf life of a maximum of fourteen days. This provides for a much smaller market and makes the timing of its sale critical. Further, because of its moisture content, the modified wet distillers’ grains are heavier and more difficult to handle. The customer must be close enough to justify the additional handling and shipping costs. As a result, modified wet distillers’ grains are principally sold only to local feedlots and livestock operations.

Various factors affect the price of distillers’ grain, including, among others, the price of corn, soybean meal and other alternative feed products, the performance or value of distillers’ grains in a particular feed market, and the supply and demand within the market. Like other commodities, the price of distillers’ grains can fluctuate significantly.

Competition

Producers of Ethanol

We sell our ethanol in a highly competitive market. We are in direct competition with numerous other ethanol producers, both regionally and nationally, many of which have more experience and greater resources than we have. Some of these producers are, among other things, capable of producing a significantly greater amount of ethanol or have multiple ethanol plants that may help them achieve certain benefits that we could not achieve with one ethanol plant. Further, new products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages over us and harm our business. A majority of the ethanol plants in the U.S. and the greatest number of gallons of ethanol production are located in the corn-producing states, such as Iowa, Nebraska, Illinois, Minnesota, South Dakota, Indiana, Ohio, Kansas, and Wisconsin.

According to the Renewable Fuels Association (RFA), as of January 2011, approximately 204 biorefineries have nameplate capacity of 14.1 billion gallons of ethanol per year

Below is the U.S. ethanol production by state in millions of gallons for the ten states with the most total ethanol production as of January 2011:

State	Nameplate	Operating	Under Construction/ Expansion	Total
Iowa	3,595.0	3,595.0	0	3,595.0
Nebraska	1,864.0	1,839.0	113	1,977.0
Illinois	1,480.0	1,480.0	5	1,485.0
Minnesota	1,136.6	1,118.6	0	1,136.6
Indiana	998.0	906.0	113	1,111.0
South Dakota	1,016.0	1,016.0	33	1,049.0
Ohio	538.0	424.0	0	538.0
Kansas	491.5	436.5	20	511.5
Wisconsin	498.0	498.0	3	501.0

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State	Nameplate	Operating	Under Construction/ Expansion	Total
Texas	250.0	250.0	115	365.0
Total	11,867.1	11,563.1	402	12,269.1

Source: Renewable Fuels Association, January 2011

Because Minnesota is one of the top producers of ethanol in the U.S., we face increased competition because of the location of our ethanol plant in Minnesota. Therefore, we compete with other Minnesota ethanol producers both for markets in Minnesota and markets in other states.

In addition to intense competition with local, regional and national producers of ethanol, we expect increased competition from imported ethanol and foreign producers of ethanol. Ethanol imported to the U.S. was subject to a 2.5 percent ad valorem tax and an additional 54 cents a gallon surcharge, both of which expired on December 31, 2011. As a result, we will face increased competition from imported ethanol and foreign producers of ethanol.

Producers of Other Fuel Additives and Alternative Fuels

In addition to competing with ethanol producers, we also compete with producers of other gasoline oxygenates. Many gasoline oxygenates are produced by other companies, including oil companies, that have far greater resources than we have. Historically, as a gasoline oxygenate, ethanol primarily competed with two gasoline oxygenates, both of which are ether-based: MTBE (methyl tertiary butyl ether) and ETBE (ethyl tertiary butyl ether). Many states have enacted legislation prohibiting the sale of gasoline containing certain levels of MTBE or are phasing out the use of MTBE because of health and environmental concerns. As a result, national use of MTBE has decreased significantly in recent years. Use of ethanol now exceeds that of MTBE and ETBE as a gasoline oxygenate.

While ethanol has displaced these two gasoline oxygenates, the development of ethers intended for use as oxygenates is continuing and we will compete with producers of any future ethers used as oxygenates.

A number of automotive, industrial and power generation manufacturers are developing alternative fuels and power systems, both for vehicles and other applications. Fuel cells have emerged as a potential alternative power system 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.

Additionally, there are more than a dozen alternative and advanced fuels currently in development, production or use, including the following alternative fuels that, like ethanol, have been or are currently commercially available for vehicles:

· biodiesel

· electricity

· hydrogen

· methanol

· natural gas

· propane

Several emerging fuels are currently under development. Many of these fuels are also considered alternative fuels and may have other benefits such as reduced emissions or decreasing dependence upon oil. Examples of emerging fuels include:

· Biobutanol: Like ethanol, biobutanol is an alcohol that can be produced through the processing of domestically grown crops, such as corn and sugar beets, and other biomass, such as fast-growing grasses and agricultural waste products.

· Biogas: Biogas is produced from the anaerobic digestion of organic matter such as animal manure, sewage, and municipal solid waste. After it is processed to required standards of purity, biogas becomes a renewable substitute for natural gas and can be used to fuel natural gas vehicles.

· Fischer-Tropsch Diesel: Diesel made by converting gaseous hydrocarbons, such as natural gas and gasified coal or biomass, into liquid fuel, including transportation fuel

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· Hydrogenation-Derived Renewable Diesel (HDRD): The product of fats or vegetable oils—alone or blended with petroleum—that has been refined in an oil refinery

· P-Series: A blend of natural gas liquids (pentanes plus), ethanol, and the biomass-derived co-solvent methyltetrahydrofuran (MeTHF) formulated to be used in flexible fuel vehicles

· Ultra-Low Sulfur Diesel: This is diesel fuel with 15 parts per million or lower sulfur content. This ultra-low sulfur content enables the use of advanced emission control technologies on vehicles using ULSD fuels produced from non-petroleum and renewable sources that are considered alternative fuels.

Additionally, there are developed and developing technologies for converting natural gas, coal and biomass to liquid fuel, including transportation fuels such as gasoline, diesel, and methanol.

We expect that competition will increase between ethanol producers, such as HLBE, and producers of these or other newly developed alternative fuels or power systems, especially to the extent they are used in similar applications such as vehicles.

Producers of Distillers’ Grains

The amount of distillers’ grains produced annually in North America is expected to increase significantly as the number of ethanol plants increase. We compete with other producers of distillers’ grains products both locally and nationally, with more intense competition for sales of distillers’ grains among ethanol producers in close proximity to our ethanol plant. There are seven ethanol plants within an approximate 50 mile radius of our plant with a combined ethanol capacity of 436 million gallons that will produce approximately 1.4 million tons of distillers’ grains. These competitors may be more likely to sell to the same markets that we target for our distillers’ grains.

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

Competition for Corn

We will compete with ethanol producers in close proximity for the supplies of corn we will require to operate our plant. Ethanol production consumes a significant portion of Minnesota’s corn crop, approximately 29% in 2009 and 34% in 2010. The existence and development of other ethanol plants, particularly those in close proximity to our plant, will increase the demand for corn that may result in higher costs for supplies of corn. We estimate that the seven ethanol plants within an approximate 50 mile radius of our plant will use approximately 160 million bushels of corn and that we will compete with these other ethanol plants for corn for our ethanol plant.

We compete with other users of corn, including ethanol producers regionally and nationally, producers of food and food ingredients for human consumption (such as high fructose corn syrup, starches, and sweeteners), producers of animal feed and industrial users. According to estimates by the Minnesota Department of Agriculture for 2010, 34% of Minnesota corn production was used in ethanol production, 44% was exported, 15% was used for feed, 4% was put to a residual use, and 3% was used in other processing.

Competition for Personnel

We will also compete with ethanol producers in close proximity for the personnel we will require to operate our plant. The existence and development of other ethanol plants will increase competition for qualified managers, engineers, operators and other personnel. We also compete for personnel with businesses other than ethanol producers and with businesses located outside the community of Heron Lake, Minnesota.

Hedging

We may hedge anticipated corn purchases and ethanol and distillers’ grain sales through a variety of mechanisms.

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We procure corn through spot cash, fixed-price forward, basis only, futures only, and delayed pricing contracts. Additionally, we may use hedging positions in the corn futures and options market to manage the risk of excessive corn price fluctuations for a portion of our corn requirements.

For our spot purchases, we post daily corn bids so that corn producers can sell to us on a spot basis. Our fixed-price forward contracts specify the amount of corn, the price and the time period over which the corn is to be delivered. These forward contracts are at fixed prices indexed to Chicago Board of Trade, or CBOT, prices. Our corn requirements can be contracted in advance under fixed-price forward contracts or options. The parameters of these contracts are based on the local supply and demand situation and the seasonality of the price. For delayed pricing contracts, producers will deliver corn to our elevators, but the pricing for that corn and the related payment will occur at a later date.

To hedge a portion of our exposure to corn price risk, we may buy and sell futures and options positions on the CBOT. In addition, our facilities have significant corn storage capacity. We generally maintain inventories of corn at our ethanol plant, but can draw from our elevators at Lakefield and Wilder to protect against supply disruption. At the ethanol plant, we have the ability to store approximately 10 days of corn supply and our elevators have capacity for approximately an additional 50 days of supply.

Effective September 1, 2011, Gavilon is the exclusive marketer for all of the ethanol produced at our facility. Gavilon is obligated to use reasonable efforts to obtain the best price for our ethanol. To mitigate ethanol price risk and to obtain the best margins on ethanol that is marketed and sold by our marketer, we may utilize ethanol swaps, over-the-counter (“OTC”) ethanol swaps, or OTC ethanol options that are typically settled in cash, rather than gallons of the ethanol we produce.

Our marketing and risk management committee assists the board and our risk management personnel to, among other things, establish appropriate policies and strategies for hedging and enterprise risk.

Compliance with Environmental Laws and Other Regulatory Matters

Our business subjects us to various federal, state and local environmental laws and regulations, including those relating to discharges into the air, water and ground; the generation, storage, handling, use, transportation and disposal of hazardous materials; and the health and safety of our employees.

These laws and regulations require us to obtain and comply with numerous permits to construct and operate our ethanol plant, including water, air and other environmental permits. The costs associated with obtaining these permits and meeting the conditions of these permits have increased our costs of construction and production.

In particular, we have incurred additional costs relating to an air-emission permit from the Minnesota Pollution Control Agency (“MPCA”). We applied for a synthetic minor air-emissions source permit in July 2004 that was granted by the MPCA in May 2005. In June 2005, a coalition of two environmental groups and one energy group challenged the granting of this air emissions permit by an appeal to the Minnesota Court of Appeals. In July 2006, the Minnesota Court of Appeals affirmed the MPCA’s issuance of the permit. In conjunction with the permit and the permit dispute and to prevent further appeals by the coalition, we entered into a compliance agreement with the MPCA on January 23, 2007.

Under the compliance agreement, we agreed to submit an amendment to our air permit to qualify our facility as a “major emissions source.” The compliance agreement also allowed us to continue with the construction of our facility. Under the compliance agreement, we agreed to operate our facility such that each type of emission generated by our ethanol plant was within an established amount and we agreed to comply in all other respects with the air emissions permit previously issued by the MPCA. Accordingly, we submitted an amendment to our existing air-emissions permit in December 2008, and, following air pollution control device testing, we submitted a second amendment to our air permit in September 2009, seeking amendments to permit conditions and adjustments to other components of plant operations and production.

On December 16, 2010, the MPCA issued a permit to us that supersedes our previously issued air permit and the compliance agreement. The new permit establishes the applicable limits for each type of emission generated by our ethanol plant. The permit also requires us to take additional actions relating to our plant and our operations within certain time frames.

We have also incurred additional expense to resolve a notice of violation issued by the MPCA in March 2008 that alleged violations certain rules, statutes, and permit conditions, including emission violations and reporting violations. On December 16, 2010, we entered into a stipulation agreement with the MPCA relating to this March 2008 notice of violation. Under the stipulation agreement, we agreed to pay a civil

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penalty of $66,000, of which $54,000 was paid within thirty days and up to $12,000 may be satisfied through our delivery of the building capture efficiency study referred to above.

We have incurred costs associated with obtaining the air permits and costs associated with the compliance agreement of approximately $452,000 in fiscal year 2009, $315,000 in fiscal year 2010, and $163,000 in fiscal year 2011.

Compliance with environmental laws and permit conditions in the future could require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment, as well as significant management time and expense. A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damage, criminal sanctions, permit revocations and/or plant shutdown, any of which could have a material adverse effect on our operations. Although violations and environmental incompliance still remain after the conversion from coal to natural gas combustion, the exposure to the company has been greatly reduced.

We have also experienced significant additional expense in fiscal year 2009 and part of fiscal year 2010 associated with equipment failures and/or warranty and other claims against Fagen, Inc. that were the subject of an arbitration action we brought against Fagen, Inc. relating to the design-build agreement and air emissions at our plant. While we settled this arbitration action against Fagen, Inc. on July 2, 2010, we incurred costs and expenses associated with our claims of approximately $743,000 in fiscal year 2010 and approximately $2,700,000 in fiscal year 2009.

Employees

As of October 31, 2011, we had 44 full-time employees, of which 36 were in operations and 8 were in executive, general management and administration. We also have four part-time employees of which two were in operations and two in executive, general management and administration. We do not maintain an internal sales organization, but instead rely upon third-parties to market and sell the ethanol and distillers’ grains that we produce.

Corporate Information

Our principal executive offices are located at 91246 390th Avenue, Heron Lake, Minnesota 56137 and our telephone number is 507-793-0077. We maintain an Internet website at www.heronlakebioenergy.com. We make available free of charge on or through our Internet website, www.heronlakebioenergy.com, all of our reports and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). We will provide electronic or paper copies of these documents free of charge upon request.

Additionally, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

ITEM 1A. RISK FACTORS

If any of the following risks actually occur, our results of operations, cash flows and the value of our units could be negatively impacted.

Risks Related to Our Financial Condition

While we have relied upon on our master loan agreement to fund our past operations and past losses, we must generate a sufficient level of net income and obtain additional working capital to fund our ongoing operations.

We had net income of approximately $540,000 for our fiscal year ended October 31, 2011 and $1.7 million for our fiscal year ended October 31, 2010, which included one-time settlement income of approximately $2.6 million. We experienced a net loss of approximately $11.3 million for the fiscal year ended October 31, 2009. Our income or loss has primarily been driven by our low or negative margins. For example, our cost of goods sold (including lower of cost or market adjustments) as a percentage of revenues was 95.8% and 93.9% for the fiscal years ended October 31, 2011 and October 31, 2010, respectively. Whether we achieve a sufficient level of net income to fund our operations will depend on a number of factors, including:

· our revenue in any given period, which depends both on the volume of our products produced and the price we receive for these products;

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· our expense levels, particularly our operating expenses relating to corn; and

· the efficiency of our plant, particularly managing costs and expenses associated with repairs and air emissions compliance and remediation plans and avoiding plant shut downs and slow downs.

We have historically financed our operations primarily through borrowing under our master loan agreement with AgStar, and, to a lesser extent, cash from operating activities. As of October 31, 2011, we had cash and cash equivalents (other than restricted cash) of approximately $7.1 million. As of October 31, 2011, our indebtedness under the master loan agreement with AgStar was approximately $46.6 million.

The amount currently available under our master loan agreement is insufficient to fund our ongoing operations. To fund our ongoing cash needs and to service our indebtedness, we must increase the income and cash generated from our operations. We cannot assure you that we will improve our liquidity to the extent required to enable us to service or reduce our indebtedness or to fund our other capital needs, if at all.

Certain provisions of our master loan agreement with AgStar present special risks to our business.

As of October 31, 2011, our debt with AgStar consists of approximately $20.0 million in fixed rate obligations and $26.6 million in variable rate obligations. The variable rate on a portion of our debt may make us vulnerable to increases in prevailing interest rates. If the interest rate on our variable rate debt were to increase, our aggregate annualized interest and principal payments would also increase and could increase significantly.

The principal and interest payments on our $40.0 million term loan are calculated using an amortization period of ten years even though the note will mature on September 1, 2016, five years from the date of its issuance. As a result, at maturity of the term loan, there would be approximately $29.0 million in principal remaining under the term loan. In order to finance this large payment of principal that would be due at maturity, we may attempt to extend the term of the loan under the master loan agreement, refinance the indebtedness under the master loan agreement, in full or in part, or obtain a new loan to repay the term loan. We cannot assure you that we will be successful in obtaining an extension of or refinancing our indebtedness. We also cannot assure you that we will be able to obtain a new loan in an amount that is sufficient for our needs, in a timely manner or on terms and conditions acceptable to us or our members.

If we are unable to service our debt, AgStar may accelerate all of our indebtedness and may seize the assets that secure our indebtedness, causing us to lose control of our business. We may also be forced to sell our assets, restructure our indebtedness, submit to foreclosure proceedings, cease operations or seek bankruptcy or reorganization protection.

Risks Relating to Our Operations

Because we are primarily dependent upon one product, our business is not diversified, and we may not be able to adapt to changing market conditions or endure any decline in the ethanol industry.

Our success depends on our ability to efficiently produce and sell ethanol, and, to a lesser extent, distillers’ grains. We do not have any other lines of business or other significant sources of revenue to rely upon if we are unable to produce and sell ethanol and distillers’ grains, or if the market for those products decline. Our lack of diversification means that we may not be able to adapt to changing market conditions, changes in regulation, increased competition or any significant decline in the ethanol industry.

Our profitability depends upon purchasing corn at lower prices and selling ethanol at higher prices and because the difference between ethanol and corn prices can vary significantly, our financial results may also fluctuate significantly.

The substantial majority of our revenues are derived from the sale of ethanol. Our gross profit relating to the sale of ethanol is principally dependent on the difference between the price we receive for the ethanol we produce and the price we pay for the corn we used to produce our ethanol. Because we do have contracts establishing the price we receive for the ethanol we produce or for the corn we purchase, the price for both ethanol and corn will be determined in significant part by prevailing market conditions affecting these commodities.

The price we receive for our ethanol is dependent upon a number of factors. Increasing domestic ethanol capacity may boost demand for corn, resulting in increased corn prices and corresponding decrease in the selling price of ethanol as production increases. Further, the price of corn is influenced by weather conditions (including droughts or over abundant rainfall) and other factors affecting crop yields, farmers’ planting decisions and general economic, market and regulatory factors, including government policies and subsidies with respect to agriculture

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and international trade, and global and local supply and demand. Declines in the corn harvest, caused by farmers’ planting decisions or otherwise, could cause corn prices to increase and negatively impact our gross margins.

We have experienced low or negative margins in the past, reflecting a higher expenses for the corn we purchase and lower revenues from ethanol we produce. For example, our cost of goods sold (including lower of cost or market adjustments) as a percentage of revenues was 95.8% and 93.9% for the fiscal years ended October 31, 2011 and October 31, 2010, respectively. Reduction in ethanol prices without corresponding decreases in corn costs or increases in corn prices without corresponding increases in ethanol prices has adversely affected our financial performance in the past and may adversely affect our financial performance in the future.

If the supply of ethanol exceeds the demand for ethanol, the price we receive for our ethanol and distillers’ grains may decrease.

According to the RFA, domestic ethanol production capacity has increased steadily each year from 1999 to 2011. However, demand for ethanol may not increase as quickly as expected or to a level that exceeds supply, or at all.

Excess ethanol production capacity may result from decreases in the demand for ethanol or increased domestic production or imported supply. There are many factors affecting demand for ethanol, including regulatory developments and reduced gasoline consumption as a result of increased prices for gasoline or crude oil. Higher gasoline prices could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage, or higher prices could spur technological advances, such as the commercialization of engines utilizing hydrogen fuel-cells, which could supplant gasoline-powered engines. There are a number of governmental initiatives designed to reduce gasoline consumption, including tax credits for hybrid vehicles and consumer education programs.

If ethanol prices decline for any reason, including excess production capacity in the ethanol industry or decreased demand for ethanol, our business, results of operations and financial condition may be materially and adversely affected.

In addition, because ethanol production produces distillers’ grains as a co-product, increased ethanol production will also lead to increased production of distillers’ grains. An increase in the supply of distillers’ grains, without corresponding increases in demand, could lead to lower prices or an inability to sell our distillers’ grains production. A decline in the price of distillers’ grains or the distillers’ grains market generally could have a material adverse effect on our business, results of operations and financial condition.

The price of distillers’ grains is affected by the price of other commodity products, such as soybeans, and decreases in the price of these commodities could decrease the price of distillers’ grains.

Distillers’ grains compete with other protein-based animal feed products. The price of distillers’ grains may decrease when the price of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the commodities from which they are derived. Downward pressure on commodity prices, such as soybeans, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers’ grains. The price of distillers’ grains is not tied to production costs. However, decreases in the price of distillers’ grains would result in less revenue from the sale of distillers’ grains and could result in lower profit margins.

We face intense competition that may result in reductions in the price we receive for our ethanol, increases in the prices we pay for our corn, or lower gross profits.

Competition in the ethanol industry is intense. We face formidable competition in every aspect of our business from both larger and smaller producers of ethanol and distillers’ grains. Some larger producers of ethanol, such as Archer Daniels Midland Company, Cargill, Inc., Valero Energy Corporation, have substantially greater financial, operational, procurement, marketing, distribution and technical resources than we have. Additionally, smaller competitors, such as farmer-owned cooperatives and independent companies owned by farmers and investors, have business advantages, such as the ability to more favorably procure corn by operating smaller plants that may not affect the local price of corn as much as a larger-scale plant like ours or requiring their farmer-owners to sell them corn as a requirement of ownership.

We also face increasing competition from international ethanol suppliers. Most international ethanol producers have cost structures that can be substantially lower than ours and therefore can sell their ethanol for substantially less than we can. While ethanol imported to the

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U.S. was subject to an ad valorem tax and a per gallon surcharge that helped mitigate the effects of international competition for U.S. ethanol producers, the tax and per gallon surcharge expired on December 31, 2011. Because the tax and surcharge on imported ethanol was not extended beyond December 31, 2011, we will face increased competition from imported ethanol and foreign producers of ethanol. In addition, ethanol imports from certain countries are exempted from these tariffs under the Caribbean Basin Initiative to spur economic development in Central America and the Caribbean. Imports of ethanol from Central American and Caribbean countries represents a significant portion of the gallons imported into the U.S. each year and a source of intense competition for us due to the lower production costs these ethanol producers enjoy.

Competing ethanol producers may introduce competitive pricing pressures that may adversely affect our sales levels and margins or our ability to procure corn at favorable prices. As a result, we cannot assure you that we will be able to compete successfully with existing or new competitors.

We engage in hedging transactions which involve risks that can harm our business.

In an attempt to offset some of the effects of pricing and margin volatility, we may hedge anticipated corn purchases and ethanol and distillers’ grain sales through a variety of mechanisms. Because of our hedging strategies, we are exposed to a variety of market risks, including the effects of changes in commodities prices of ethanol and corn.

Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. Our losses or gains from hedging activities may vary widely.

There can be no assurance that our hedging strategies will be effective and we may experience hedging losses in the future. We also vary the amount of hedging or other price mitigation strategies we undertake, and we may choose not to engage in hedging transactions at all. As a result, whether or not we engage in hedging transactions, our business, results of operations and financial condition may be materially adversely affected by increases in the price of corn or decreases in the price of ethanol.

Operational difficulties at our plant could negatively impact our sales volumes and could cause us to incur substantial losses.

We have experienced operational difficulties at our plant that have resulted in scheduled and unscheduled downtime or reductions in the number of gallons of ethanol we produce. Some of the difficulties we have experienced relate to production problems, repairs required to our plant equipment and equipment maintenance, the installation of new equipment and related testing, and our efforts to improve and test our air emissions. Although operational difficulties will still remain after the conversion from coal to natural gas combustion, the amount of incidents should be reduced. Our revenues are driven in large part by the number of gallons of ethanol we produce and the number of tons of distillers’ grains we produce. If our ethanol plant does not efficiently produce our products in high volumes, our business, results of operations, and financial condition may be materially adversely affected.

Our operations are also subject to operational hazards inherent in our industry and to manufacturing in general, such as equipment failures, fires, explosions, abnormal pressures, blowouts, pipeline ruptures, transportation accidents and natural disasters. Some of these operational hazards may cause personal injury or loss of life, severe damage to or destruction of property and equipment or environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. The occurrence of any of these operational hazards may materially adversely affect our business, results of operations and financial condition. Further, our insurance may not be adequate to fully cover the potential operational hazards described above or we may not be able to renew this insurance on commercially reasonable terms or at all.

Our operations and financial performance could be adversely affected by infrastructure disruptions and lack of adequate transportation and storage infrastructure in certain areas.

We ship our ethanol to our customers primarily by the railroad adjacent to our site. We also have the potential to receive inbound corn via the railroad, although we currently receive corn by truck from our facilities in Lakefield, Minnesota and Wilder, Minnesota, each of which is less than 15 miles away from our plant. Our customers require appropriate transportation and storage capacity to take delivery of the products we produce. We also receive our natural gas through a pipeline that is approximately 16 miles in length. Without the appropriate flow of natural gas through the pipeline our plant may not be able to run at desired production levels or at all. Therefore, our business is dependent on the continuing availability of rail, highway and related infrastructure. Any disruptions in this infrastructure network, whether caused by labor difficulties, earthquakes, storms, other natural disasters, human error or malfeasance or other reasons, could have a material adverse effect

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on our business. We rely upon third-parties to maintain the rail lines from our plant to the national rail network, and any failure on their part to maintain the lines could impede our delivery of products, impose additional costs on us and could have a material adverse effect on our business, results of operations and financial condition.

In addition, lack of this infrastructure prevents the use of ethanol in certain areas where there might otherwise be demand and results in excess ethanol supply in areas with more established ethanol infrastructure, depressing ethanol prices in those areas. In order for the ethanol industry to grow and expand into additional markets and for our ethanol to be sold in these new markets, there must be substantial development of infrastructure including:

· additional rail capacity;

· additional storage facilities for ethanol;

· increases in truck fleets capable of transporting ethanol within localized markets;

· expansion of refining and blending facilities to handle ethanol; and

· growth in service stations equipped to handle ethanol fuels.

The substantial investments that will be required for these infrastructure changes and expansions may not be made on a timely basis, if at all, and decisions regarding these infrastructure improvements are outside of our control. Significant delay or failure to improve the infrastructure that facilitates the distribution could curtail more widespread ethanol demand or reduce prices for our products in certain areas, which would have a material adverse effect on our business, results of operations or financial condition.

Competition for qualified personnel in the ethanol industry is intense and we may not be able to hire and retain qualified personnel to operate our ethanol plant.

Our success depends in part on our ability to attract and retain competent personnel. For our ethanol plant, we must hire qualified managers, operations personnel, accounting staff and others, which can be challenging in a rural community. Competition for employees in the ethanol industry is intense, and we may not be able to attract and retain qualified personnel. If we are unable to hire productive and competent personnel and retain our existing personnel, our business may be adversely affected and we may not be able to efficiently operate our ethanol business and comply with our other obligations.

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

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

Ethanol production methods are constantly advancing. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass such as agricultural waste, forest residue and municipal solid waste. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas that are unable to grow corn. Another trend in ethanol production research is to produce ethanol through a chemical or thermal process, rather than a fermentation process, thereby significantly increasing the ethanol yield per pound of feedstock. Although current technology does not allow these production methods to be financially competitive, new technologies may develop that would allow these methods to become viable means of ethanol production in the future. If we are unable to adopt or incorporate these advances into our operations, our cost of producing ethanol could be significantly higher than those of our competitors, which could make our ethanol plant obsolete. Modifying our plant to use the new inputs and technologies would likely require material investment.

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

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

Our sales will decline, and our business will be materially harmed if our third party marketers do not effectively market or sell the ethanol and distillers grains we produce or if there is a significant reduction or delay in orders from our marketers.

We have entered into an agreement with a third party to market our supply of ethanol and distillers’ grains. Our marketer is an independent business that we do not control. We cannot be certain that our marketer will market or sell our ethanol and distillers’ grains effectively. Our agreements with this marketer do not contain requirements that a certain percentage of sales are of our products, nor do the agreements restrict the marketer’s ability to choose alternative sources for ethanol or distillers’ grains.

Our success in achieving revenue from the sale of ethanol and distillers’ grains will depend upon the continued viability and financial stability of our marketer. Our marketer may choose to devote its efforts to other ethanol producers or reduce or fail to devote the necessary resources to provide effective sales and marketing support of our products. We believe that our financial success will continue to depend in large part upon the success of our marketer in operating its businesses. If our marketer does not effectively market and sell our ethanol and distillers’ grains, our revenues may decrease and our business will be harmed.

Risks Related to Government Programs and Regulation

We have experienced significant costs in obtaining and complying with permits and environmental laws, particularly our air emissions permit, and may continue to experience significant costs in the future.

The costs associated with obtaining and complying with permits and complying with environmental laws have increased our costs of construction, production and continued operation. In particular, we have incurred significant expense relating to our air-emission permit in four categories: (1) obtaining our air emissions permit from the Minnesota Pollution Control Agency (“MPCA”); (2) compliance with our air emissions permit and the terms of our compliance agreement with the MPCA; (3) our dispute under the design-build agreement with Fagen, Inc. relating to equipment failures, warranty claims and other claims regarding air emissions at our plant that was the subject of an arbitration action that was settled on July 2, 2010; and (4) a March 2008 notice of violation from the MPCA that was resolved in December 2010 though a stipulation agreement.

While our air emissions permit issue was resolved with the December 16, 2010 issuance of a new air permit by the MPCA, our arbitration action against Fagen, Inc. has been settled, and we have addressed the notice of violation through a stipulation agreement, we anticipate future expense associated with compliance with our air permit and related environmental laws. The permit requires us to take additional actions relating to our plant and our operations within certain time frames.

Continued compliance with our air emissions permit issue will involve management time and expense and may involve ongoing operational expense or further modifications to the design or equipment in our plant. Although violations and environmental incompliance still remain after the conversion from coal to natural gas combustion, the exposure to the company has been greatly reduced.

There can be no assurance that we will be able to comply with any of the conditions of any of our permits, or with environmental laws applicable to us. A violation of environmental laws, regulations or permit conditions can result in substantial fines, natural resource damage, criminal sanctions, permit revocations or plant shutdown, any of which could have a material adverse effect on our operations.

Our failure to comply with existing or future regulatory requirements could have a material adverse effect on our business, financial condition and results of operations.

We are subject to various federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the air, water and ground. Certain aspects of our operations require environmental permits and controls to prevent and reduce air and water pollution, and these permits are subject to modification, renewal and revocation by issuing authorities including the Minnesota Pollution Control Agency. We could incur substantial costs, including cleanup costs, fines and civil or criminal sanctions and third-party claims for property damage and personal injury as a result of violations of or liabilities under environmental laws or non-compliance with environmental permits. We could also incur substantial costs and experience increased operating expenses as a result of operational changes to

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comply with environmental laws, regulations and permits. As discussed above, we have incurred substantial costs relating to our air emissions permit and expect additional costs relating to this permit in the future.

Further, environmental laws and regulations are subject to substantial change. We cannot predict what material impact, if any, these changes in laws or regulations might have on our business. Future changes in regulations or enforcement policies could impose more stringent requirements on us, compliance with which could require additional capital expenditures, increase our operating costs or otherwise adversely affect our business. These changes may also relax requirements that could prove beneficial to our competitors and thus adversely affect our business. In addition, regulations of the Environmental Protection Agency and the Minnesota Pollution Control Agency depend heavily on administrative interpretations. We cannot assure you that future interpretations made by regulatory authorities, with possible retroactive effect, will not adversely affect our business, financial condition and results of operations.

Failure to comply with existing or future regulatory requirements could have a material adverse effect on our business, financial condition and results of operations.

Because federal and state regulation heavily influence the supply of and demand for ethanol, changes in government regulation that adversely affect demand or supply will have a material adverse effect on our business.

Various federal and state laws, regulations and programs impact the supply of and demand for ethanol. Some government regulation, for example those that provide economic incentives to ethanol producers, stimulate supply of ethanol by encouraging production and the increased capacity of ethanol plants. Others, such as a federal excise tax incentive program that provides gasoline distributors who blended ethanol with gasoline to receive a federal excise tax rate reduction for each blended gallon they sell, stimulate demand for ethanol by making it price competitive with other oxygenates. Further, tariffs generally apply to the import of ethanol from certain other countries, where the cost of production can be significantly less than in the U.S. These tariffs are designed to increase the cost of imported ethanol to a level more comparable to the cost of domestic ethanol by offsetting the benefit of the federal excise tax program. Tariffs have the effect of maintaining demand for domestic ethanol.

Additionally, the Environmental Protection Agency has established a revised annual renewable fuel standard (RFS2) that sets minimum national volume standards for use of renewable fuels. The RFS2 also sets volume standards for specific categories of renewable fuels: cellulosic, biomass-based diesel and total advanced renewable fuels. While our ethanol does not qualify one of the new volume categories of renewable fuels, we believe that the overall renewable fuels requirement of RFS2 creates an incentive for the use of ethanol. Other federal and state programs that require or provide incentives for the use of ethanol create demand for ethanol. Government regulation and government programs that create demand for ethanol may also indirectly create supply for ethanol as additional producers expand or new companies enter the ethanol industry to capitalize on demand. In the case of the RFS2, while it creates a demand for ethanol, the existence of specific categories of renewable fuels also creates a demand for these types of renewable fuels and will likely provide an incentive for companies to further develop these products to capitalize on that demand. In these circumstances, the RFS2 may also reduce demand for ethanol in favor of the renewable fuels for which specific categories exist.

Federal and state laws, regulations and programs are constantly changing. We cannot predict what material impact, if any, these changes might have on our business. Future changes in regulations and programs could impose more stringent operational requirements or could reduce or eliminate the benefits we receive, directly and indirectly, under current regulations and programs. Future changes in regulations and programs may increase or add benefits to ethanol producers other than us or eliminate or reduce tariffs or other barriers to entry into the U.S. ethanol market, any of which could prove beneficial to our competitors, both domestic and international. Future changes in regulation may also hurt our business by providing economic incentives to producers of other renewable fuels or oxygenates or encouraging use of fuels or oxygenates that compete with ethanol. In addition, both national and state regulation is influenced by public opinion and changes in public opinion. For example, certain states oppose the use of ethanol because, as net importers of ethanol from other states, the use of ethanol could increase gasoline prices in that state and because that state does not receive significant economic benefits from the ethanol industry, which are primarily experienced by corn and ethanol producing states. Further, some argue that the use of ethanol will have a negative impact on gasoline prices to consumers, result in rising food prices, add to air pollution, harm car and truck engines, and actually use more fossil energy, such as oil and natural gas, than the amount of ethanol that is produced. We cannot predict the impact that opinions of consumers, legislators, industry participants, or competitors may have on the regulations and programs currently benefiting ethanol producers.

The EPA imposed E10 “blend wall” if not overcome will have an adverse effect on demand for ethanol.

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amount of ethanol blended into the national gasoline supply. Second, the Environmental Protection Agency (EPA) mandates a limit of 10% ethanol inclusion in non-flex fuel vehicles, and the E85 vehicle marketplace is struggling to grow due to lacking infrastructure. The EPA policy of 10% and the RFS increasing blend rate are at odds, which is sometimes referred to as the “blend wall.” While the issue is being considered by the EPA, there have been no regulatory changes that would reconcile the conflicting requirements. In 2011, the United States Environmental Protection Agency allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2001 and later. Management believes that many gasoline retailers will refuse to provide E15 due to the fact that not all standard vehicles will be allowed to use E15 and due to the labeling requirements the EPA may impose. The EPA is considering instituting labeling requirements associated with E15 which may unfairly discourage consumers from purchasing E15. As a result, the approval of E15 may not significantly increase demand for ethanol.

Approval of a Low Carbon Fuel Standard (“LCFS”) by the California Air Resources Board (“CARB”) may have a negative impact on our ability to market our ethanol in California.

The CARB implemented a LCFS, which set standards for the carbon intensity of fuels used in the State of California starting in 2011. While the rules are still subject to rulemaking process in California, certain provisions of the proposed LCFS rules have the potential to ban ethanol produced at our plant from being sold in California. While we believe there may be some negative impact to our sales from the approval of the LCFS in California, we believe we will still be able to market all the ethanol produced by our plant to markets outside of California. However, if additional states where our ethanol is marketed, or the federal government, adopt similar provisions it could have a severe negative impact on our ability to sell all of the ethanol produced at our plant.

Risks Related to the Units

Project Viking owns a large percentage of our units, which may allow it to control or heavily influence matters requiring member approval, and Project Viking has been granted additional board rights under our member control agreement.

As of October 31, 2011, Project Viking, L.L.C. beneficially owned 43.0% of our outstanding units. Project Viking is owned by Roland J. (Ron) Fagen and Diane Fagen, the principal shareholders of Fagen, Inc., the design-build firm for our ethanol plant. Project Viking, together with our executive officers and governors, together control approximately 46.0% of our outstanding units as of October 31, 2011. As a result, these unit holders, acting individually or together, could significantly influence our management and affairs and all matters requiring member approval, including the election of governors and approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying or preventing a change in control of our company and might affect the price of our units.

Additionally, our member control agreement gives members who hold significant amounts of equity in us the right to designate governors to serve on our board of governors. For every 9% of our units held, the member has the right to appoint one person to our board. Project Viking, L.L.C. has the right to appoint four persons to our board pursuant to this provision and has appointed four persons as of October 31, 2011. Although the designated governors do not represent a majority of our board, their presence on the board may allow Project Viking, L.L.C. to have greater influence over the decisions of our board and our business than other members.

Further, the interests of Project Viking, L.L.C. may not coincide with our interests or the interests of our other members. For example, Fagen, Inc. has invested and may continue to invest in a number of other ethanol producers, some of whom may compete with us. As a result of these and other potential conflicting interests, these existing members may make decisions with respect to us with which we or our members may disagree.

There is no public market for our units and no public market is expected to develop.

There is no established public trading market for our units, and we do not expect one to develop in the foreseeable future. To maintain our partnership tax status, we do not intend to list the units on any stock exchange or automatic quotation system such as OTC Bulletin Board. As a result, units held by our members may not be easily resold and members may be required to hold their units indefinitely. Even if members are able to resell our units, the price may be less than the members’ investment in the units or may otherwise be unattractive to the member.

There are significant restrictions on the transfer of our units.

To protect our status as a partnership for tax purposes and to assure that no public trading market in our units develops, our units are subject to significant restrictions on transfer and transfers are subject to approval by our board of governors. All transfers of units must comply with the transfer provisions of our member control agreement and the unit transfer policy adopted by our board of governors. Our board of governors will not approve transfers which could cause us to lose our tax status or violate federal or state securities laws. On November 5,

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2008, our board of governors adopted a revised unit transfer policy. While the revised policy permits transfers of our units under certain circumstances, including certain transfers of units for value, there continue to be significant restrictions on transfer of our units. Among other things, the revised unit transfer policy places limits on the number of units that may be transferred during any fiscal year and requires the transferor and transferee to complete a unit transfer agreement and application form and submit these to us along with the required documents and an application fee.

On July 2, 2010, in conjunction with our recapitalization efforts and in light of the transactions and agreements the Company entered into with Project Viking, L.L.C., the board of governors determined to suspend approvals of any transfers of units, provided that related-party transfers without consideration would still be considered. This suspension was approved by the board pursuant to its authority under our member control agreement. On July 9, 2010, we notified our members of the suspension of approvals by a letter. We also removed all postings on the unit bulletin board.

On November 30, 2011, in light of the recapitalization transactions we entered into during fiscal year 2011 and the conversion of our ethanol plant to natural gas thermal source, the board approved the lifting of its suspension of approvals of transfers of units, with consideration of such transfers to commence at its next regularly scheduled board meeting. The board will now consider approvals of any transfers of units in accordance with our member control agreement and our unit transfer policy, and postings on the unit bulletin board may resume.

As a result of the provisions of our member control agreement, members may not be able to transfer their units and may be required to assume the risks of the investment for an indefinite period of time.

A transferee may be admitted as a member only upon approval by the board of governors and upon satisfaction of certain other requirements, including the transferee meeting the minimum unit ownership requirements to become a member (which for our present units requires holding a minimum of 2,500 units). Any transferee that is not admitted as a member will be deemed an unadmitted assignee. An unadmitted assignee will be a non-member unit holder and will have the same financial rights as other unit holders, such as the right to receive distributions that we declare or that are available upon our dissolution or liquidation. As a non-member unit holder, an unadmitted assignee will not have the voting or other governance rights of members and will not be entitled to any information or accountings regarding our business or to inspect our books and records.

There is no assurance that we will be able to make distributions to our unit holders, which means that holders could receive little or no return on their investment.

Distributions of our net cash flow may be made at the sole discretion of our board of governors, subject to the provisions of the Minnesota Limited Liability Company Act, our member control agreement and restrictions imposed by AgStar under our master loan agreement. Our master loan agreements with AgStar currently materially limit our ability to make distributions to our members and are likely to limit materially the future payment of distributions. If our financial performance and loan covenants permit, we expect to make future cash distributions at times and in amounts that will permit our members to make income tax payments. If our financial performance and loan covenants further permit, we intend to make distributions in excess of those amounts. However, our board may elect to retain cash for operating purposes, debt retirement, plant improvements or expansion. We may also never be in a position to pay distributions because of our financial performance or the terms of our master loan agreement. Consequently, members may receive little or no return on their investment in the units.

We may authorize and issue units of new classes which could be superior to or adversely affect holders of our outstanding units.

Our board of governors, upon the approval of a majority in interest of our members, has the power to authorize and issue units of classes which have voting powers, designations, preferences, limitations and special rights, including preferred distribution rights, conversion rights, redemption rights and liquidation rights, different from or superior to those of our present units. New units may be issued at a price and on terms determined by our board of governors. The terms of the units and the terms of issuance of the units could have an adverse impact on your voting rights and could dilute your financial interest in us.

Our use of a staggered board of governors and allocation of governor appointment rights may reduce the ability of members to affect the composition of the board.

We are managed by a board of governors, currently consisting of five elected governors and four appointed governors. The seats on the board that are not subject to a right of appointment will be elected by the members without appointment rights. An appointed governor serves indefinitely at the pleasure of the member appointing him or her (so long as such member and its affiliates continue to hold a sufficient

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number of units to maintain the applicable appointment right) until a successor is appointed, or until the earlier death, resignation or removal of the appointed governor.

Under our member control agreement, non-appointed governors are divided into three classes, with the term of one class expiring each year. As the term of each class expires, the successors to the governors in that class will be elected for a term of three years. As a result, members elect only approximately one-third of the non-appointed governors each year.

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

Our units represent both financial and governance rights, and loss of status as a member would result in the loss of the holder’s voting and other rights and would allow us to redeem such holder’s units.

Holders of units are entitled to certain financial rights, such as the right to any distributions, and to governance rights, such as the right to vote as a member. If a unit holder does not continue to qualify as a member or such holder’s member status is terminated, the holder would lose certain rights, such as voting rights, and we could redeem such holder’s units. The minimum number of units presently required for membership is 2,500 units. In addition, holders of units may be terminated as a member if the holder dies or ceases to exist, violates our member control agreement or takes actions contrary to our interests, and for other reasons. Although our member control agreement does not define what actions might be contrary to our interests, and our board of governors has not adopted a policy on the subject, such actions might include providing confidential information about us to a competitor, taking a board or management position with a competitor or taking action which results in significant financial harm to us in the marketplace. If a holder of units is terminated as a member, our board of governors will have no obligation to redeem such holder’s units.

Voting rights of members are not necessarily equal and are subject to certain limitations.

Members of our company are holders of units who have been admitted as members upon their investment in our units and who are admitted as members by our board of governors. The minimum number of units required to retain membership is 2,500 units. Any holder of units who is not a member will not have voting rights. Transferees of units must be approved by our board of governors to become members. Members who are holders of our present units are entitled to one vote for each unit held. The provisions of our member control agreement relating to voting rights applicable to any class of units will apply equally to all units of that class.

However, our member control agreement gives members who hold significant amounts of equity in us the right to designate governors to serve on our board of governors. For every 9% of our units held, the member has the right to appoint one person to our board. Project Viking, L.L.C. has the right to appoint four persons to our board pursuant to this provision and has currently appointed four persons. If units of any other class are issued in the future, holders of units of that other class will have the voting rights that are established for that class by our board of governors with the approval of our members. Consequently, the voting rights of members may not be necessarily proportional to the number of units held.

Further, cumulative voting for governors is not allowed, which makes it substantially less likely that a minority of members could elect a member to the board of governors. Members do not have dissenter’s rights. This means that they will not have the right to dissent and seek payment for their units in the event we merge, consolidate, exchange or otherwise dispose of all or substantially all of our property. Holders of units who are not members have no voting rights. These provisions may limit the ability of members to change the governance and policies of our company.

All members will be bound by actions taken by members holding a majority of our units, and because of the restrictions on transfer and lack of dissenters’ rights, members could be forced to hold a substantially changed investment.

We cannot engage in certain transactions, such as a merger, consolidation, dissolution or sale of all or substantially all of our assets, without the approval of our members. However, if holders of a majority of our units approve a transaction, then all members will also be bound to that transaction regardless of whether that member agrees with or voted in favor of the transaction. Under our member control agreement, members will not have any dissenters’ rights to seek appraisal or payment of the fair value of their units. Consequently, because there is no public market for the units, members may be forced to hold a substantially changed investment.

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Risks Related to Tax Issues in a Limited Liability Company

EACH UNIT HOLDER SHOULD CONSULT THE INVESTOR’S OWN TAX ADVISOR WITH RESPECT TO THE FEDERAL AND STATE TAX CONSEQUENCES OF AN INVESTMENT IN HERON LAKE BIOENERGY, LLC AND ITS IMPACT ON THE INVESTOR’S TAX REPORTING OBLIGATIONS AND LIABILITY.

If we are not taxed as a partnership, we will pay taxes on all of our net income and you will be taxed on any earnings we distribute, and this will reduce the amount of cash available for distributions to holders of our units.

We consider Heron Lake BioEnergy, LLC to be a partnership for federal income tax purposes. This means that we will not pay any federal income tax, and our members will pay tax on their share of our net income. If we are unable to maintain our partnership tax treatment or qualify for partnership taxation for whatever reason, then we may be taxed as a corporation. We cannot assure you that we will be able to maintain our partnership tax classification. For example, there might be changes in the law or our company that would cause us to be reclassified as a corporation. As a corporation, we would be taxed on our taxable income at rates of up to 35% for federal income tax purposes. Further, distributions would be treated as ordinary dividend income to our unit holders to the extent of our earnings and profits. These distributions would not be deductible by us, thus resulting in double taxation of our earnings and profits. This would also reduce the amount of cash we may have available for distributions.

Your tax liability from your allocated share of our taxable income may exceed any cash distributions you receive, which means that you may have to satisfy this tax liability with your personal funds.

As a partnership for federal income tax purposes, all of our profits and losses “pass-through” to our unit holders. You must pay tax on your allocated share of our taxable income every year. You may incur tax liabilities from allocations of taxable income for a particular year or in the aggregate that exceed any cash distributions you receive in that year or in the aggregate. This may occur because of various factors, including but not limited to, accounting methodology, the specific tax rates you face, and payment obligations and other debt covenants that restrict our ability to pay cash distributions. If this occurs, you may have to pay income tax on your allocated share of our taxable income with your own personal funds.

You may not be able to fully deduct your share of our losses or your interest expense.

It is likely that your interest in us will be treated as a “passive activity” for federal income tax purposes. In the case of unit holders who are individuals or personal services corporations, this means that a unit holder’s share of any loss incurred by us will be deductible only against the holder’s income or gains from other passive activities, e.g., S corporations and partnerships that conduct a business in which the holder is not a material participant. Some closely held C corporations have more favorable passive loss limitations. Passive activity losses that are disallowed in any taxable year are suspended and may be carried forward and used as an offset against passive activity income in future years. Upon disposition of a taxpayer’s entire interest in a passive activity to an unrelated person in a taxable transaction, suspended losses with respect to that activity may then be deducted.

Interest paid on any borrowings incurred to purchase units may not be deductible in whole or in part because the interest must be aggregated with other items of income and loss that the unit holder has independently experienced from passive activities and subjected to limitations on passive activity losses.

Deductibility of capital losses that we incur and pass through to you or that you incur upon disposition of units may be limited. Capital losses are deductible only to the extent of capital gains plus, in the case of non-corporate taxpayers, the excess may be used to offset up to $3,000 of ordinary income. If a non-corporate taxpayer cannot fully utilize a capital loss because of this limitation, the unused loss may be carried forward and used in future years subject to the same limitations in the future years.

You may be subject to federal alternative minimum tax

Individual taxpayers are subject to an “alternative minimum tax” if that tax exceeds the individual’s regular income tax. For alternative minimum tax purposes, an individual’s adjusted gross income is increased by items of tax preference. We may generate such preference items. Accordingly, preference items from our operations together with other preference items you may have may cause or increase an alternative minimum tax to a unit holder. You are encouraged and expected to consult with your individual tax advisor to analyze and determine the effect on your individual tax situation of the alternative minimum taxable income you may be allocated, particularly in the early years of our operations.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

There is no established public trading market for the units and we do not expect one to develop in the foreseeable future. To maintain our partnership tax status, we do not intend to list the units on any stock exchange or over-the-counter securities market such as the OTC Bulletin Board.

Effective July 2, 2010, our board of governors determined to suspend approvals of any transfers of units, provided that related-party transfers without consideration would still be considered. This suspension was approved by the board pursuant to its authority under our member control agreement. On July 9, 2010, we notified our members of the suspension of approvals by a letter. We also removed all postings on the unit bulletin board.

Holders of Record

As of January 26, 2012, there were 38,622,107 Class A units outstanding and held of record by 1,156 persons. There are no other classes of units outstanding. As of October 31, 2011 and January 26, 2012, there were no outstanding options or warrants to purchase, or securities convertible into, our units.

Distributions

To date, we have only made tax distributions to our members. Our master loan agreement with AgStar Financial Services, PCA currently materially limits our ability to make distributions, other than tax distributions, to our members and is likely to limit materially the future payment of distributions. If our financial performance and loan covenants permit, we expect to make future cash distributions at times and in amounts that will permit our members to make income tax payments. If our financial performance and loan covenants further permit, we intend to make distributions in excess of those amounts. Cash distributions are not assured, however, and we may never be in a position to make distributions. Under Minnesota law, we cannot make a distribution to a member if, after the distribution, we would not be able to pay our debts as they become due or our liabilities, excluding liabilities to our members on account of their capital contributions, would exceed our assets.

For a further description of the limitations on our ability to make distributions to our members, please see “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 9 of the notes to our audited consolidated financial statements.

Securities Authorized for Issuance under Equity Compensation Plans

There are no “compensation plans” (including individual compensation arrangements) under which any of our equity securities are authorized for issuance.

ITEM 6. SELECTED FINANCIAL DATA

Selected Consolidated Financial Data

The following table presents selected consolidated financial and operating data as of the dates and for the periods indicated. The selected financial data for the balance sheet as of October 31, 2011 and 2010 and the statement of operations for the years ended October 31, 2011, 2010 and 2009 has been derived from the audited consolidated financial statements included elsewhere in this Annual Report on

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Form 10-K. The selected financial for the balance sheet as of October 31, 2009, 2008 and 2007 and the statement of operations for the years ended October 31, 2008 and 2007 were derived from audit financial statements filed previously.

This selected consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” within Item 7 and the consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following consolidated financial data.

	Fiscal Year Ended
	October 31,			October 31,			October 31,			October 31,			October 31,
	2011			2010			2009			2008			2007

Statement of Operations Data:
Revenues	$	164,120,375		$	110,624,758		$	88,304,596		$	131,070,642		$	23,560,498
Cost of goods sold	157,163,624			103,690,208			90,857,247			114,411,541			24,313,695
Gross profit (loss)	6,956,751			6,934,550			(2,552,651		)	16,659,101			(753,197		)
Operating expenses	(3,613,465		)	(3,857,492		)	(4,515,476		)	(3,351,252		)	(3,527,199		)
Settlement income	—			2,600,000			—			—			—
Operating income (loss)	3,343,286			5,677,058			(7,068,127		)	13,307,849			(4,280,396		)
Other income (expense)	(2,800,269		)	(3,993,537		)	(4,261,307		)	(4,689,810		)	(1,167,890		)
Net income (loss) before noncontrolling interest	543,017			1,683,521			(11,329,434		)	8,618,039			(5,448,286		)
Noncontrolling income (loss)	(27,838		)	—			—			—			—

Net income (loss)	$	570,855		$	1,683,521		$	(11,329,434	)	$	8,618,039		$	(5,448,286	)

Weighted average units outstanding	33,391,636			28,141,942			27,104,625			27,104,625			26,361,406

Net income (loss) per unit — Basic and diluted	$	0.02		$	0.06		$	(0.42	)	$	0.32		$	(0.21	)

	As of
	October 31,		October 31,		October 31,		October 31,		October 31,
	2011		2010		2009		2008		2007

Balance Sheet Data:
Assets:
Current assets	$	14,237,942	$	18,254,313	$	12,926,672	$	27,223,185	$	24,382,053
Property and equipment	88,592,945		89,803,647		98,560,605		103,882,039		108,852,921
Other assets	1,303,037		1,482,617		1,602,000		2,295,586		724,984
Total assets	$	104,133,924	$	109,540,577	$	113,089,277	$	133,400,810	$	133,959,958

Current liabilities	$	7,807,727	$	60,034,589	$	69,059,727	$	23,552,096	$	29,712,918
Long-term debt	46,844,912		4,068,716		4,775,804		59,265,534		62,281,899
Members’ equity	49,481,285		45,437,272		39,253,746		50,583,180		41,965,141

Total liabilities and members’ equity	$	104,133,924	$	109,540,577	$	113,089,277	$	133,400,810	$	133,959,958

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

The following discussion should be read in conjunction with our financial statements and related notes contained elsewhere in this Annual Report on Form 10-K. This discussion may contain forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results and the timing of selected events could differ materially from those anticipated in these forward-looking statements as a result of selected factors, including those set forth under “Risk Factors” in Part I, Item 1A of this Form 10-K. All forward-looking statements included herein are based on information available to us as of the date hereof, and we undertake no obligation to update any such forward-looking statements.

We prepared the following discussion and analysis to help readers better understand our financial condition, changes in our financial condition, and results of operations for the fiscal year ended October 31, 2011.

Overview

Heron Lake BioEnergy, LLC is a Minnesota limited liability company that owns and operates a dry mill corn-based, natural gas fired ethanol plant near Heron Lake, Minnesota. The plant has a stated capacity to produce 50 million gallons of denatured fuel grade ethanol and 160,000 tons of dried distillers’ grains (DDGS) per year. Production of ethanol and distillers’ grains at the plant began in September 2007. We began recording revenue from plant production in October 2007, the last month of our fiscal year. Our revenues are derived from the sale and distribution of our ethanol throughout the continental United States and in the sale and distribution of our distillers’ grains (DGS) locally, and throughout the continental United States. Our subsidiary, Lakefield Farmers Elevator, LLC, has grain facilities at Lakefield and Wilder, Minnesota. Our subsidiary, HLBE Pipeline Company, LLC, owns 73% of Agrinatural Gas, LLC, the pipeline company formed to construct, own, and operate a natural gas pipeline that provides natural gas to the Company’s ethanol production facility through a connection with the natural gas pipeline facilities of Northern Border Pipeline Company in Cottonwood County, Minnesota.

Our operating results are largely driven by the prices at which we sell ethanol and distillers grains and the costs related to their production, particularly the cost of corn. Historically, the price of ethanol tended to fluctuate in the same direction as the price of unleaded gasoline and other petroleum products. However, during fiscal 2008 and continuing into fiscal 2011, it appears ethanol prices tended to move up and down proportionately, with changes in corn prices. The price of ethanol can also be influenced by factors such as general economic conditions, concerns over blending capacities, and government policies and programs. The price of distillers grains is generally influenced by supply and demand, the price of substitute livestock feed, such as corn and soybean meal, and other animal feed proteins. Our largest component of and cost of production is corn. The cost of corn is affected primarily by factors over which we lack any control such as crop production, carryout, exports, government policies and programs, and weather. The growth of the ethanol industry has increased the demand for corn. We believe that continuing increase in global demand will result in corn prices above historic averages. As an example of our potential sensitivity to price changes, if the price of ethanol rises or falls $.10 per gallon, our revenues may increase or decrease accordingly by approximately $5.0 million, assuming no other changes in our business. Additionally, if the price of corn rises or falls $0.25 per bushel, our cost of goods sold may increase or decrease by $5.0 million, again assuming no other changes in our business. During our fiscal 2011, the market price of ethanol and corn were extremely volatile. The price of corn hit a high of $7.99 per bushel in June 2011 and a low of $5.07 in November 2010, while the price of ethanol fluctuated from a high of $3.07 in July 2011 and a low of $2.04 in November 2010.

Trends and Uncertainties Impacting Our Operations

Our current and future results of operation are affected and will continue to be affected by factors such as (a) volatile and uncertain pricing of ethanol and corn; (b) availability of corn that is, in turn, affected by trends such as corn acreage, weather conditions, and yields on existing and new acreage diverted from other crops; and (c) the supply and demand for ethanol, which is affected by acceptance of ethanol as a substitute for fuel, public perception of the ethanol industry, government incentives and regulation, and competition from new and existing

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construction, among other things. Other factors that may affect our future results of operation include those factors discussed in “Item 1. Business” and “Item 1A. Risk Factors.”

Critical Accounting Estimates

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Impairment testing for assets requires various estimates and assumptions, including an allocation of cash flows to those assets and, if required, an estimate of the fair value of those assets. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. These valuations require the use of management’s assumptions, which do not reflect unanticipated events and circumstances that may occur. In our analysis, we consider future corn costs and ethanol prices, break-even points for our plant and our risk management strategies in place through our derivative instruments and forward contracts. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of impairment of our long-lived assets to be a critical accounting estimate.

We reviewed our long-lived assets for impairment at October 31, 2011. As a result of this review and our related analysis, we believe our long-lived assets were not impaired as of October 31, 2011.

We enter forward contracts for corn purchases to supply the plant. These contracts represent firm purchase commitments which along with inventory on hand must be evaluated for potential market value losses. We have estimated a loss on these firm purchase commitments to corn contracts in place and for corn on hand during 2011 where the price of corn exceeded the market price and upon being used in the manufacturing process and eventual sale of products we anticipate losses. Our estimates include various assumptions including the future prices of ethanol, distillers’ grains and corn. For the years ended 2011, 2010 and 2009 we recognized a lower of cost or market losses of approximately $1,592,000, $904,000 and $5,409,000, respectively.

Fiscal Year Ended October 31, 2011 Compared to Fiscal Year Ended October 31, 2010

The following table shows the results of our operations and the percentage of revenues, cost of goods sold, operating expenses and other items to total revenues in our statements of operations for the fiscal year ended October 31, 2011 and 2010:

	2011					2010
Income Statement Data	Amount			%		Amount			%
Revenues	$	164,120,375		100.0		$	110,624,758		100.0

Cost of Goods Sold	157,163,624			95.8		103,690,208			93.7

Gross Margin	6,956,751			4.2		6,934,550			6.3

Selling, General, and Administrative Expenses	3,613,465			2.2		3,857,492			3.5

Settlement Income	—			0.0		2,600,000			2.4

Operating Income (Loss)	3,343,286			2.0		5,677,058			5.1

Other Expense	(2,800,269		)	(1.7	)	(3,993,537		)	(3.6	)

Net Income before noncontrolling interest	543,017			0.4		1,683,521			1.5

Noncontrolling Income (Loss)	(27,838		)	0.0		—			0.0

Net Income (Loss)	$	570,855		0.3		$	1,683,521		1.5

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Revenues

Ethanol revenues during the period ended October 31, 2011 were approximately $130.6 million, comprising 80% of our revenues compared to $90.9 million during the period ended October 31, 2010, representing 82% of our revenues.

For the year ended October 31, 2011, we sold approximately 53.4 million gallons of ethanol at an average price of $2.45 per gallon. For the year ended October 31, 2010, we sold approximately 53.4 million gallons of ethanol at an average price of $1.70 per gallon. The price of ethanol during our fiscal year was affected by the demand for ethanol as a motor fuel which is affected by, among other factors, regulatory developments, gasoline consumption, and the price of crude oil. The price was also affected by federal RFS blending mandates.

We may hedge anticipated ethanol sales through a variety of mechanisms. Our marketers, whether C&N or Gavilon, are obligated to use reasonable efforts to obtain the best price for our ethanol. To mitigate ethanol price risk and to obtain the best margins on ethanol that is marketed and sold by a marketer, we may utilize ethanol swaps, over-the-counter (“OTC”) ethanol swaps, or OTC ethanol options that are typically settled in cash, rather than gallons of the ethanol we produce. Losses or gains on ethanol derivative instruments recorded in a particular period are reflected in revenue for that period. For the years ended October, 31, 2011 and 2010, we recorded losses of approximately $20,000 and $200,000, respectively, related to ethanol derivative instruments. There are timing differences in the recognition of losses or gains on derivatives as compared to the corresponding sale of ethanol.

We expect to see fluctuations in ethanol prices over the next fiscal year. While the demand for ethanol is expected to continue since gasoline blenders will need increasing amounts of ethanol to meet the Renewable Fuels Standard’s blending requirements, the supply is also expected to increase as additional production facilities are completed or increase production. In addition, low prices for petroleum and gasoline will exert downward pressure on ethanol prices. If ethanol prices decline, our earnings will also decline, particularly if corn prices remain substantially higher than historic averages, as they were in our fiscal year 2011. Future prices for fuel ethanol will be affected by a variety of factors beyond our control including, the demand for ethanol as a motor fuel, federal incentives for ethanol production, the amount and timing of additional domestic ethanol production and ethanol imports and petroleum and gasoline prices.

Total sales of DGS during fiscal years 2011 and 2010 equaled approximately $24.8 million and $13.0 million, respectively, comprising 15% and 12% of our revenues for fiscal years 2011 and 2010, respectively. In fiscal years 2011 and 2010, we sold approximately 136,000 tons and 119,000 tons, respectively, of dried distillers’ grain. The average price we received for distillers’ grain was approximately $176 per ton in fiscal year 2011 and approximately $99 per ton in fiscal year 2010.

Prices for distillers’ grains are affected by a number of factors beyond our control such as the supply of and demand for distillers’ grains as an animal feed and prices for competing feeds. We believe that current market prices for distillers’ grains are approaching levels that can be sustained long-term as long as the prices of competing animal feeds remain steady or increase, livestock feeders continue to create demand for alternative feed sources such as distillers’ grains and the supply of distillers’ grains remains relatively stable. On the other hand, if competing commodity price values retreat and distillers’ supplies increase due to growth in the ethanol industry, distillers’ grains prices may decline.

Cost of Goods Sold

Our costs of sales include, among other things, the cost of corn used in ethanol and DGS production (which is the largest component of costs of sales), coal, processing ingredients, electricity, and wages, salaries and benefits of production personnel. We use approximately 1.5 million bushels of corn per month at the plant. We contract with local farmers and elevators for our corn supply. We are able to store corn that we purchase in our elevators in Lakefield and Wilder, Minnesota, as well as in on-site storage at the plant.

Our costs of sales (including lower of cost or market adjustments) as a percentage of revenues were 95.8% and 93.9% for the twelve months ended October 31, 2011 and, 2010, respectively. The per bushel cost of corn purchased increased approximately 78% in the twelve months ended October 31, 2011 as compared to the fiscal year ended October 31, 2010. Cost of goods sold includes lower of cost or market adjustments of approximately $1.6 million for the fiscal year ended October 31, 2011, which related to forward purchase contracts and inventory where the fixed price was more than the estimated realizable value. The lower of cost or market adjustment for the twelve months ended October 31, 2010 was approximately $0.9 million. We had losses related to corn derivative instruments of approximately $0.4 and $1.0 million for the twelve months ended October 31, 2011 and 2010, respectively, which increased cost of sales. In summary, lower of cost or market adjustments increased approximately $0.7 million for the fiscal year ended October 31, 2011 as compared to the fiscal year ended October 31, 2010. During the same periods, losses on derivatives decreased approximately $0.6 million. The 78% increase in the per bushel cost of corn outweighed the 44% increase in the per gallon sales price of ethanol which caused the increase in the cost of goods sold as a percent of revenues for the twelve months ended October 31, 2011. Our gross margin for the twelve months ended October 31, 2011 decreased to 4.2% from 6.1% for the twelve months ended

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October 31, 2010. Our gross margin decreased in fiscal year 2011 as compared to fiscal year 2010 due in part to the additional plant downtime for the conversion to natural gas.

The cost of corn fluctuates based on supply and demand, which, in turn, is affected by a number of factors that are beyond our control. We expect our gross margin to fluctuate in the future based on the relative prices of corn and fuel ethanol. We use futures and options contracts to minimize our exposure to movements in corn prices, but there is no assurance that these hedging strategies will be effective. Through October 31, 2011, none of our derivative contracts were designated as hedges and, as a result, changes to the market value of these contracts were recognized as an increase or decrease to our costs of goods sold. As a result, gains or losses on derivative instruments do not necessarily coincide with the related corn purchases. This may cause fluctuations in cost of goods sold. While we do not use hedge accounting to match gains or losses on derivative instruments, we believe the derivative instruments provide an economic hedge.

Operating Expense

Operating expenses include wages, salaries and benefits of administrative employees at the plant, insurance, professional fees and similar costs and generally do not vary with the level of production at the plant. These expenses were $3.6 million for the twelve months ended October 31, 2011 down 6.3% from $3.9 million for the twelve months ended October 31, 2010. These expenses generally do not vary with the level of production at the plant and were relatively constant from period to period. Increased revenue for the fiscal year ended October 31, 2011 positively affected operating expenses as a percentage of revenue as total revenues increased approximately 48%.

Settlement Income

From the settlement on July 2, 2010 of our arbitration proceeding involving Fagen, Inc., we recorded $2.6 million of settlement income from cash and noncash proceeds during the third quarter of fiscal year 2010. There was no settlement income in fiscal year 2011.

Operating Income

Our income from operations for fiscal year 2011 totaled $3.3 million compared to fiscal year 2010 operating income of approximately $5.5 million. We experienced a decrease in operating income in fiscal year 2011 compared to 2010 due primarily to the impact of $2.6 million in settlement income.

Other Income and (Expense)

Fiscal Year Ended October 31, 2010 Compared to Fiscal Year Ended October 31, 2009

	2010					2009
Income Statement Data	Amount			%		Amount			%
Revenues	$	110,624,758		100.0		$	88,304,596		100.0

Cost of Goods Sold	103,690,208			93.7		90,857,247			102.9

Gross Margin	6,934,550			6.3		(2,552,651		)	(2.9	)

Selling, General, and Administrative Expenses	3,857,492			3.5		4,515,476			5.1

Settlement Income	2,600,000			2.4		—			0.0

Operating Income (Loss)	5,677,058			5.1		(7,068,127		)	(8.0	)

Other Expense	(3,993,537		)	(3.6	)	(4,261,307		)	(4.8	)

Net Income (Loss)	$	1,683,521		1.5		$	(11,329,434	)	(12.8	)

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Revenues

Ethanol revenues during the period ended October 31, 2010 were approximately $90.9 million, comprising 82% of our revenues compared to $70.4 million during the period ended October 31, 2009, representing 80% of our revenues.

For the year ended October 31, 2010, we sold approximately 53.4 million gallons of ethanol at an average price of $1.70 per gallon. For the year ended October 31, 2009, we sold approximately 46.4 million gallons of ethanol at an average price of $1.52 per gallon. We believe that the number of gallons of ethanol sold was affected by the plant’s productivity that was impacted by scheduled and unscheduled downtime during the fiscal year 2009, including testing and process changes relating to our air emissions. Further, the price of ethanol during our fiscal year was affected by the demand for ethanol as a motor fuel which is affected by, among other factors, regulatory developments, gasoline consumption, and the price of crude oil. The price was also affected by federal RFS blending mandates.

We may hedge anticipated ethanol sales through a variety of mechanisms. Our marketers, whether RPMG or C&N, are obligated to use reasonable efforts to obtain the best price for our ethanol. To mitigate ethanol price risk and to obtain the best margins on ethanol that is marketed and sold by a marketer, we may utilize ethanol swaps, over-the-counter (“OTC”) ethanol swaps, or OTC ethanol options that are typically settled in cash, rather than gallons of the ethanol we produce. Losses or gains on ethanol derivative instruments recorded in a particular period are reflected in revenue for that period. For the years ended October, 31, 2010 and 2009, we recorded a loss of $0.2 million and a gain $0.4 million, respectively, related to ethanol derivative instruments. There are timing differences in the recognition of losses or gains on derivatives as compared to the corresponding sale of ethanol. As such, the losses or gains recognized could be associated with related sales in fiscal years 2008, 2009 or 2010.

We expect to see fluctuations in ethanol prices over the next fiscal year. While the demand for ethanol is expected to continue since gasoline blenders will need increasing amounts of ethanol to meet the Renewable Fuels Standard’s blending requirements, the supply is also expected to increase as additional production facilities are completed or return to production. In addition, low prices for petroleum and gasoline will exert downward pressure on ethanol prices. If ethanol prices decline, our earnings will also decline, particularly if corn prices remain substantially higher than historic averages, as they were in our fiscal year 2010. Future prices for fuel ethanol will be affected by a variety of factors beyond our control including, the demand for ethanol as a motor fuel, federal incentives for ethanol production, the amount and timing of additional domestic ethanol production and ethanol imports and petroleum and gasoline prices.

Total sales of DGS during fiscal years 2010 and 2009 equaled approximately $13.0 million and $12.8 million, respectively, comprising 12% and 14% of our revenues for fiscal years 2010 and 2009, respectively. In fiscal years 2010 and 2009, we sold approximately 119,000 tons of dried distillers’ grain. The average price we received for distillers’ grain was approximately $99 per ton in fiscal year 2010 and approximately $107 per ton in fiscal year 2009.

Cost of Goods Sold

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1.5 million bushels of corn per month at the plant. We contract with local farmers and elevators for our corn supply. We are able to store corn that we purchase in our elevators in Lakefield and Wilder, Minnesota, as well as in on-site storage at the plant.

Our costs of sales (including lower of cost or market adjustments) as a percentage of revenues were 93.9% and 102.9% for the twelve months ended October 31, 2010 and, 2009, respectively. The per bushel cost of corn purchased (net of losses realized in fiscal year 2009 for bushels delivered in fiscal 2010) decreased approximately 1% in the twelve months ended October 31, 2010 as compared to the twelve months ended October 31, 2009. Cost of goods sold includes lower of cost or market adjustments of $0.9 million for the fiscal year ended October 31, 2010, which related to forward purchase contracts and inventory where the fixed price was more than the estimated realizable value. The lower of cost or market adjustment for the twelve months ended October 31, 2009 was $5.4 million. We had a loss related to corn derivative instruments of approximately $1.0 million for the twelve months ended October 31, 2010, which increased cost of sales. We had a gain related to corn derivative instruments of approximately $1.2 million for the twelve months ended October 31, 2009 that reduced cost of sales. In summary, lower of cost or market adjustments decreased $4.5 million for the fiscal year ended October 31, 2010 as compared to the fiscal year ended October 31, 2009. During the same periods, gains on derivatives decreased $2.2 million. These decreased net costs combined with the 12% increase in the per gallon sales price of ethanol caused the decrease in the cost of goods sold as a percent of revenues for the twelve months ended October 31, 2010. Our gross margin (loss) for the twelve months ended October 31, 2010 increased to 6.1% from (2.9%) for the twelve months ended October 31, 2009. We had a positive gross margin in fiscal year 2010 as compared to negative gross margin in fiscal year 2009 due to the increase in ethanol prices; decreased costs of goods sold, relative to revenues; and due to a decrease in losses on forward contracts. In addition, higher production levels in fiscal year 2010 contributed to the positive gross margin experienced in fiscal year 2010.

The cost of corn fluctuates based on supply and demand, which, in turn, is affected by a number of factors that are beyond our control. We expect our gross margin to fluctuate in the future based on the relative prices of corn and fuel ethanol. We use futures and options contracts to minimize our exposure to movements in corn prices, but there is no assurance that these hedging strategies will be effective. Through October 31, 2010, none of our derivative contracts were designated as hedges and, as a result, changes to the market value of these contracts were recognized as an increase or decrease to our costs of goods sold. As a result, gains or losses on derivative instruments do not necessarily coincide with the related corn purchases. This may cause fluctuations in cost of goods sold. While we do not use hedge accounting to match gains or losses on derivative instruments, we believe the derivative instruments provide an economic hedge.

Costs of sales also include expenses directly attributable to the repair and maintenance of the plant. Cost of sales as a percentage of revenue was higher in fiscal year 2009 as compared to fiscal year 2010 due to increased costs attributable to the repair and maintenance of the plant. During the third quarter of fiscal year 2009, we incurred costs of approximately $300,000 as part of a five day planned semi-annual shutdown and maintenance procedure. Upon shutdown, portions of the refractory section of the boiler collapsed. While there were no injuries sustained, significant additional costs were incurred to secure the refractory, ensure the safety of the workers completing repairs and to complete the repairs. This added eleven days to the shutdown for a total of sixteen days shutdown during May 2009.

Cost of sales for fiscal year 2010 also reflects the positive impact of an amended railcar leasing agreement we entered into in July 2009. The terms of the amendment reduce the rail cars under lease by 50 cars and increase the monthly rental amount per remaining rail car until July 1, 2014. This has resulted in a monthly cash savings of $425 per rail car or $21,250 per month.

Operating Expense

Operating expenses include wages, salaries and benefits of administrative employees at the plant, insurance, professional fees and similar costs and generally do not vary with the level of production at the plant. These expenses were $3.9 million for the twelve months ended October 31, 2010 down 13.3% from $4.5 million for the twelve months ended October 31, 2009. These expenses generally do not vary with the level of production at the plant and were relatively constant from period to period other than costs of approximately $800,000 incurred for

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environmental emissions testing done and unusual boiler repairs during fiscal 2009. Increased revenue for the fiscal year ended October 31, 2010 positively affected operating expenses as a percentage of revenue as total revenues increased approximately 25%.

Settlement Income

Operating Income

Our income from operations for fiscal year 2010 totaled $5.5 million compared to a loss from operations for fiscal year 2009 of approximately $7.1 million. We experienced operating income in fiscal year 2010 rather than an operating loss primarily due to positive gross margin in fiscal year 2010 of $6.7 million as compared to a negative gross margin of $2.5 million in fiscal year 2009 and the impact of $2.6 million in settlement income in fiscal year 2010.

Other Income and (Expense)

Other expense consisted primarily of interest expense. Interest expense consists primarily of interest payments on our credit facilities described below. Interest expense for fiscal year 2010, which was up slightly as compared to the twelve months ended October 31, 2009, is dependent on the balances outstanding, interest rate fluctuations and default interest accruals. As of October 31, 2010, debt balances were down 10% as compared to balances at October 31, 2009. The average 1 month LIBOR rate, applicable to our line of credit with AgStar, was 0.27% for the twelve months ended October 31, 2010 compared to 0.52% for the twelve months ended October 31, 2009. Balances on our line of credit decreased from $5,000,000 at October 31, 2009 to $3,500,000 outstanding at October 31, 2010. However, balances on our line of credit had a minimum interest rate of 6% during the twelve months ended October 31, 2010 and there was no minimum interest rate during the twelve months ended October 31, 2009. Additionally, we accrued 2% in default interest on all of our indebtedness to AgStar beginning February 1, 2010 through July 2, 2010, which added additional expense for the twelve months ended October 31, 2010. We also accrued the same 2% default interest on all of our indebtedness to AgStar from May 1, 2009 through May 29, 2009. While interest expense remained rather flat from year to year, fiscal year 2009 included the write-off of loan costs of approximately $445,000 in other expense. Because we have not obtained a waiver from AgStar for actual or expected violations of our master loan agreement, our long-term debt with AgStar was classified as a current liability. As such, we wrote-off the remaining loan costs rather than amortizing them over the original contractual term of the loans.

Liquidity and Capital Resources

As of October 31, 2011, we had cash and cash equivalents (other than restricted cash) of approximately $7.1 million, current assets of approximately $14.2 million and total assets of approximately $103.5 million.

Our principal sources of liquidity consist of cash provided by operations, cash and cash equivalents on hand, and available borrowings under our master loan agreement with AgStar. Under the master loan agreement, we have two forms of debt: a term note and a revolving term note. The total indebtedness to AgStar at October 31, 2011 was $46.6 million, consisting of $39.7 million under the term note and $6.9 million under the revolving term note. Our revolving term note allows borrowing up to $8.0 million subject to letters of credit outstanding. Among other provisions, our master loan agreement contains covenants requiring us to maintain various financial ratios and tangible net worth. It also limits our annual capital expenditures and membership distributions. All of our assets and real property are subject to security interests and mortgages in favor of AgStar as security for the obligations of the master loan agreement. Please see “Credit Arrangements — Credit Arrangement with AgStar” for a description of our indebtedness and agreements relating to our indebtedness with AgStar. We have also raised $3.5 million in equity in fiscal 2011 and another $0.7 million in November 2011.

Effective September 1, 2011, the Company entered into a corn supply agreement with Gavilon. Gavilon purchased all corn inventory currently owned by the Company and located at its production facility or elevator facilities, at current market prices, to facilitate the transition to Gavilon supplying 100% of the Company’s corn requirements at the production facility and the repayment of the Company’s line of credit with AgStar.

There is no assurance that our cash, cash generated from operations and, if necessary, available borrowing under our agreement with AgStar, will be sufficient to fund our anticipated capital needs and operating expenses, particularly if the sale of ethanol and DGS does not produce revenues in

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the amounts currently anticipated or if our operating costs, including specifically the cost of corn, natural gas and other inputs, are greater than anticipated. Due to current volatility in the ethanol and corn markets, our future profit margins might be tight or not exist at all.

Year Ended October 31, 2011 Compared to Year Ended October 31, 2010

Our principal uses of cash are to pay operating expenses of the plant and to make debt service payments. During the twelve months ended October 31, 2011, we used cash to make principal payments of approximately $4.2 million against the term note and to pay down $3.5 million on our line of credit.

The following table summarizes our sources and uses of cash and equivalents from our condensed consolidated statements of cash flows for the periods presented (in thousands):

	Year Ended October 31
	2011			2010			2009
Net cash provided by (used in) operating activities	$	14,258		$	(202	)	$	(8,334	)
Net cash used in investing activities	(4,493		)	(519		)	(232		)
Net cash provided by (used in) financing activities	(4,148		)	(940		)	395
Net increase (decrease) in cash and equivalents	$	5,617		$	(1,661	)	$	(8,171	)

During the twelve months ended October 31, 2011, we received $14.3 million in cash for operating activities. This consists primarily of generating net income of $0.5 million plus non-cash expenses including depreciation and amortization of $5.5 million and reductions in inventory and accounts receivable.

During the twelve months ended October 31, 2011, we used approximately $4.5 million for investing activities primarily to pay for capital expenditures which included costs for the conversion to natural gas.

During the twelve months ended October 31, 2011, we used approximately $4.1 million from financing activities consisting primarily of payments on our term note of approximately $4.2 million and $3.5 million on the line of credit. We also raised $3.5 million from member contributions.

Year Ended October 31, 2010 Compared to Year Ended October 31, 2009

During the twelve months ended October 31, 2010, we used $0.2 million in cash for operating activities. This use consists primarily of generating net income of $1.7 million plus non-cash expenses including depreciation and amortization of $5.6 million and cash used to purchase inventory of $6.0 million.

During the twelve months ended October 31, 2010, we used approximately $519,000 for investing activities to pay for capital expenditures and to purchase restricted certificates of deposit.

During the twelve months ended October 31, 2010, we used approximately $940,000 from financing activities consisting primarily of payments on our term note of approximately $5.1 million and $1.5 million on the line of credit. We also generated $4.5 million from member contributions.

Contractual Obligations

The following table provides information regarding the consolidated contractual obligations of the Company as of October 31, 2011:

	Total		Less than One Year		One to Three Years		Three to Five Years		Greater Than Five Years
Long-term debt obligations (1)	$	62,618,917	$	7,042,955	$	12,609,601	$	40,907,292	$	2,059,069
Operating lease obligations	6,785,586		1,647,589		2,778,997		1,666,000		693,000
Purchase obligations (2)	17,142,830		5,350,310		11,792,520		—		—
Total contractual obligations	$	86,547,333	$	14,040,854	$	27,181,118	$	42,573,292	$	2,752,069

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(1) Long-term debt obligations include estimated interest and interest on unused debt.

(2) Purchase obligations primarily include forward contracts for natural gas.

Off Balance-Sheet Arrangements

We have no off balance-sheet arrangements.

Credit Arrangements

Credit Arrangements with AgStar

We have entered into an amended and restated master loan agreement with AgStar Financial Services, PCA (“AgStar”) under which we have two forms of debt as of September 1, 2011: a five-year term loan initially amounting of $40,000,000 and a five-year term revolving loan commitment in the amount of $8,008,689.

AgStar has been granted a security interest in substantially all of the assets of Heron Lake BioEnergy and its subsidiary, Lakefield Farmers Elevator, LLC. We also assigned to AgStar our interest in our agreements for the sale of ethanol and distillers grains, and for the purchases of natural gas, corn and electricity, as well as our design-build agreement with Fagen, Inc. AgStar also received a mortgage relating to our real property and that of Lakefield Farmers Elevator.

During the term of the loans, we are subject to certain financial loan covenants consisting of minimum working capital, minimum debt coverage, and minimum tangible net worth. We are only allowed to make annual capital expenditures up to $500,000 annually without prior approval. The loan agreements also impose restrictions on our ability to make cash distributions to our members.

Upon an occurrence of an event of default or an event that will lead to our default, AgStar may upon notice terminate its commitment to loan funds and declare the entire unpaid principal balance of the loans, plus accrued interest, immediately due and payable. An event of default includes, but is not limited to, our failure to make payments when due, insolvency, any material adverse change in our financial condition or our breach of any of the covenants, representations or warranties we have given in connection with the transaction.

Please see the discussion above in “Liquidity and Capital Resources” regarding our failure to comply with covenants of the master loan agreement and the impact of these covenant violations on our liquidity and capital resources.

Term Note

The Fifth Amended and Restated Master Loan Agreement and related loan documents with AgStar replaced and superseded the Company’s existing loan agreements, related loan documents and the amended forbearance agreements effective September 1, 2011. Under the Fifth Amended and Restated Master Loan Agreement the Company has a five-year term loan in the amount of $40,000,000, comprised of two tranches of $20,000,000 each, with the first tranche bearing interest at a variable rate equal to the greater of a LIBOR rate plus 3.50% or 5.0%, and the second tranche bearing interest at 5.75%. The Company must make equal monthly payments of principal and interest on the term loan based on a ten-year amortization, provided the entire principal balance and accrued and unpaid interest on the term loan is due and payable in full on the maturity date of September 1, 2016.

Revolving Term Note

Under the Fifth Amended and Restated Master Loan Agreement the Company also obtained a five-year term revolving loan commitment in the amount of $8,008,689, under which AgStar agreed to make periodic advances to the Company up to this original amount until September 1, 2016. Amounts borrowed by the Company under the term revolving loan and repaid or prepaid may be re-borrowed at any time prior to maturity date of the term revolving loan, provided that outstanding advances may not exceed the amount of the term revolving loan commitment. Amounts outstanding on the term revolving loan bear interest at a variable rate equal to the greater of a LIBOR rate plus 3.50% or 5.0%, payable monthly. The Company also pays an unused commitment fee on the unused portion of the term revolving loan commitment at the rate of 0.35% per annum, payable in arrears in quarterly installments during the term of the term revolving loan. Under the

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terms of the new agreement, the term revolving loan commitment is scheduled to decline by $500,000 annually, beginning on September 1, 2012 and each anniversary date thereafter. The maturity date of the term revolving loan is September 1, 2016.

Amounts available under the revolving term note are reduced by outstanding standby letters of credit. The Company does have a $600,000 outstanding standby letter of credit at October 31, 2011.

Line of Credit

In September 2011, the Company negotiated a new debt agreement with AgStar that superseded past agreements, including the forbearance agreements. This new debt agreement extends the maturity date of the loans, increases the potential available balance on the revolving portion of the long-term debt, and allows the Company to reclassify the debt to long-term. As part of this new agreement, the Company repaid in full the line of credit with AgStar in September 2011. The repayment of the line of credit was done as part of the change in ethanol and distillers marketers to Gavilon, LLC (“Gavilon”) in September 2011. Gavilon will also assume responsibility for certain risk management activities for the Company and will carry certain raw material and finished goods inventory rather than the Company. With the transition to Gavilon, the Company sold certain inventory to Gavilon in order to pay off the line of credit in September 2011.

At October 31, 2010, outstanding borrowings on the line of credit were $3.5 million. Amounts available under the line of credit were reduced by outstanding standby letters of credit. However, we had no outstanding standby letters of credit at October 31, 2010.

Other Credit Arrangements

In addition to our primary credit arrangement with AgStar, we have other material credit arrangements and debt obligations.

In October 2003, we entered into an industrial water supply development and distribution agreement with the City of Heron Lake, Jackson County, and Minnesota Soybean Processors. In consideration of this agreement, we and Minnesota Soybean Processors are allocated equally the debt service on $735,000 in water revenue bonds that were issued by the City to support this project that mature in February 2019. The parties have agreed that prior to the scheduled expiration of the agreement, they will negotiate in good faith to replace the agreement with a further agreement regarding the wells and related facilities. In May 2006, we entered into an industrial water supply treatment agreement with the City of Heron Lake and Jackson County. Under this agreement, we pay monthly installments over 24 months starting January 1, 2007 equal to one years’ debt service on approximately $3.6 million in water revenue bonds, which will be returned to us if any funds remain after final payment in full on the bonds and assuming we comply with all payment obligations under the agreement. As of October 31, 2011, there was a total of $3.1 million in outstanding water revenue bonds and we classify our obligations under these bonds as assessments payable. The interest rates on the bonds range from 0.50% to 8.73%.

In November 2007, we entered into a shared savings contract with Interstate Power and Light Company (“IPL”), our electrical service provider. Under the agreement, IPL is required to pay $1,850,000 to fund project costs for the purchase and installation of electrical equipment. In exchange, we are required to share a portion of the energy savings with IPL that may be derived from the decreased energy consumption from the new equipment. We are required to pay IPL approximately $30,000 for the first thirteen billing cycles, $140,000 at the end of the thirteenth billing cycle, and thereafter, approximately $30,000 for the remainder of the billing cycles. These amounts represent IPL’s portion of the shared savings. We also granted IPL a security interest in the electrical equipment to be installed on our site. The shared savings contract expires December 31, 2012.

In connection with the shared savings contract, IPL deposited $1,710,000 of the $1,850,000 in an escrow account on our behalf and we received the remaining $140,000 as cash proceeds. The escrow account expires at the same time as the shared savings contract or a termination by IPL of the escrow arrangement, at which time any remaining funds will be distributed to IPL. We earn interest at a rate of 4.2% on the funds escrowed and we pay a rate of interest of 1.5% on the funds deposited into escrow. Each month, a distribution from the escrow account is made to IPL to pay its portion of the shared savings under the shared savings contract.

To fund the purchase of the distribution system and substation for the plant, we entered into a loan agreement with Federated Rural Electric Association pursuant to which we borrowed $600,000 by a secured promissory note. Under the note we are required to make monthly payments to Federated Rural Electric Association of $6,250 consisting of principal and an annual fee of 1% beginning on October 10, 2009. In exchange for this loan, Federated Rural Electric Association was granted a security interest in the distribution system and substation for the plant. The balance of this loan at October 31, 2011 was $443,750.

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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 ethanol. We do not enter into these derivative financial instruments for trading or speculative purposes, nor do we designate these contracts as hedges for accounting purposes pursuant to the requirements of FASB ASC 815, Derivatives and Hedging.

Interest Rate Risk

We may be exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding a variable term note and a revolving term note. The specifics of these notes are discussed in greater detail in “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Commodity Price Risk

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

As corn prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments. Depending on market movements, crop prospects and weather, these price protection positions may cause immediate adverse effects, but are expected to produce long-term positive growth for us.

A sensitivity analysis has been prepared to estimate our exposure to ethanol and corn price risk. Market risk related to these factors is estimated as the potential change in income resulting from a hypothetical 10% adverse change in the fair value of our corn and average ethanol price as of October 31, 2011, net of the forward and future contracts used to hedge our market risk for corn usage requirements. The volumes are based on our expected use and sale of these commodities for a one year period from October 31, 2011. As of October 31, 2011, none of our corn usage or our ethanol sales over the next 12 months were subject to fixed price or index contracts where a price has been established with an exchange. Other procurement and sales options including basis or index contracts without a price established on the exchange, for both corn and ethanol, are not included in this analysis. The results of this analysis, which may differ from actual results, are as follows:

	Estimated Volume Requirements for the next 12 months (net of forward and futures contracts)	Unit of Measure	Hypothetical Adverse Change in Price as of 10/31/2011		Approximate Adverse Change to Income

Ethanol	53,400,000	Gallons	10	%	$	13,010,000
Corn	18,500,000	Bushels	10	%	$	12,025,000

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements are included in this Annual Report on Form 10-K beginning at the “F” page noted:

	Page Reference

Report of Independent Registered Public Accounting Firm	F-1

Consolidated Balance Sheets as of October 31, 2011 and 2010	F-2

Consolidated Statements of Operations for the fiscal years ended October 31, 2011, 2010 and 2009	F-4

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Consolidated Statements of Changes in Members’ Equity for the fiscal years ended October 31, 2011, 2010 and 2009	F-5

Consolidated Statements of Cash Flows for the fiscal years ended October 31, 2011, 2010 and 2009	F-6

Notes to Consolidated Financial Statements	F-8

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

We maintain a system of “disclosure controls and procedures,” as defined by Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended.

Our Chief Executive Officer, Robert J. Ferguson, and our Chief Financial Officer, Lucas G. Schneider, have evaluated our disclosure controls and procedures as of October 31, 2011. Based upon their review, they have concluded that these controls and procedures are effective.

(b) Management’s Report on Internal Control over Financial Reporting

The Board of Directors and Members of Heron Lake BioEnergy, LLC:

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a15-(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is 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. A company’s internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

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

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

Under the supervision of our Chief Executive Officer and our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

A material weakness (within the meaning of PCAOB Auditing Standard No. 5) is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

In conducting the aforementioned evaluation, management concluded that the Company’s internal control over financial reporting was effective as of October 31, 2011.

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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.

Dated: January 30, 2012

	HERON LAKE BIOENERGY, LLC


	By:	/s/ Robert J. Ferguson
	Robert J. Ferguson, Chief Executive Officer
	(principal executive officer)

Each person whose signature appears below hereby constitutes and appoints Robert J. Ferguson and Lucas G. Schneider, and each of them, as his true and lawful attorney-in-fact and agent, with full power of substitution, to sign on his behalf, individually and in each capacity stated below, all amendments to this Form 10-K and to file the same, with all exhibits thereto and any other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully and to all intents and purposes as each might or could do in person, hereby ratifying and confirming each act that said attorneys-in-fact and agents may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on behalf of the registrant by the following persons in the capacities indicated on January 30, 2012.

/s/ Robert J. Ferguson		Chief Executive Officer and President
Robert J. Ferguson		(principal executive officer), Governor

/s/ Lucas G. Schneider		Chief Financial Officer (principal
Lucas G. Schneider		financial and accounting officer)

/s/ David J. Woestehoff		Governor
David J. Woestehoff

/s/ Doug Schmitz		Governor
Doug Schmitz

/s/ Michael S. Kunerth		Governor
Michael S. Kunerth

/s/ Kenton Johnson		Governor
Kenton Johnson

/s/ Nick Bowdish		Governor
Nick Bowdish

/s/ Steven H. Core		Governor
Steven H. Core

/s/ Milton J. McKeown		Governor
Milton J. McKeown

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HERON LAKE BIOENERGY, LLC

INDEX TO EXHIBITS TO FORM 10-K FOR FISCAL YEAR ENDED OCTOBER 31, 2011

Exhibit Number	Exhibit Title	Incorporated by Reference To:

3.1	First Amended and Restated Articles of Organization of Heron Lake BioEnergy, LLC	Exhibit 3.1 of the Company’s Registration Statement on Form 10 (File No. 000-51825) filed on August 22, 2008 (the “2008 Registration Statement”).
3.2	Member Control Agreement of Heron Lake BioEnergy, LLC, as amended through March 29, 2008	Exhibit 3.2 of the Company’s 2008 Registration Statement.
4.1	Form of Class A Unit Certificate	Exhibit 4.1 of the Company’s 2008 Registration Statement.
4.2	Unit Transfer Policy adopted November 5, 2008	Exhibit 4.1 of the Company’s Current Report on Form 8-K dated November 5, 2008.
10.1	Fourth Amended and Restated Loan Agreement dated October 1, 2007 by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.1 of the Company’s 2008 Registration Statement.
10.2	Third Supplement dated October 1, 2007 to Fourth Amended and Restated Loan Agreement by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.2 of the Company’s 2008 Registration Statement.
10.3	Fourth Supplement dated October 1, 2007 to Fourth Amended and Restated Loan Agreement by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.3 of the Company’s 2008 Registration Statement.
10.4	Term Note dated October 1, 2007 in principal amount of $59,583,000 by Heron Lake BioEnergy, LLC to AgStar Financial Services, PCA as lender	Exhibit 10.4 of the Company’s 2008 Registration Statement.
10.5	Term Revolving Note dated October 1, 2007 in principal amount of $5,000,000 by Heron Lake BioEnergy, LLC to AgStar Financial Services, PCA as lender	Exhibit 10.5 of the Company’s 2008 Registration Statement.
10.6	Personal Guaranty dated October 1, 2007 by Roland Fagen, guarantor, in favor of AgStar Financial Services, PCA	Exhibit 10.6 of the Company’s 2008 Registration Statement.
10.7	Fourth Amended and Restated Guaranty dated October 1, 2007 by Lakefield Farmers Elevator, LLC in favor of AgStar Financial Services, PCA	Exhibit 10.7 of the Company’s 2008 Registration Statement.
10.8	Fifth Supplement dated November 19, 2007 to Fourth Amended and Restated Loan Agreement by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.8 of the Company’s 2008 Registration Statement.
10.9	Revolving Line of Credit Note dated November 19, 2007 in principal amount of $7,500,000 by Heron Lake BioEnergy, LLC to AgStar Financial Services, PCA as lender	Exhibit 10.9 of the Company’s 2008 Registration Statement.
10.10	Industrial Water Supply Development and Distribution Agreement dated October 27, 2003 among Heron Lake BioEnergy, LLC (f/k/a Generation II Ethanol, LLC), City of Heron Lake, Jackson County, and Minnesota Soybean Processors	Exhibit 10.10 of the Company’s 2008 Registration Statement.
10.11	Industrial Water Supply Treatment Agreement dated May 23, 2006 among Heron Lake BioEnergy, LLC, City of Heron Lake and County of Jackson	Exhibit 10.11 of the Company’s 2008 Registration Statement.
10.12	Standard Form of Agreement between Owner and Designer — Lump Sum dated September 28, 2005 by and between Fagen, Inc. and Heron Lake BioEnergy, LLC†	Exhibit 10.12 of Amendment No. 4 to the Company’s 2008 Registration Statement.
10.13	Distiller’s Grain Marketing Agreement dated October 5, 2005 by and between Heron Lake BioEnergy, LLC and Commodity Specialist Company as assigned to CHS Inc. as of August 17, 2007	Exhibit 10.13 of the Company’s 2008 Registration Statement.

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Exhibit Number	Exhibit Title	Incorporated by Reference To:
10.14	Ethanol Fuel Marketing Agreement dated August 7, 2006 by and between RPGM, Inc. and Heron Lake BioEnergy, LLC	Exhibit 10.14 of the Company’s 2008 Registration Statement.
10.15	Letter Agreement re: Environmental Compliance Support dated March 12, 2007 by and between Fagen Engineering, LLC Heron Lake BioEnergy, LLC	Exhibit 10. 15 of the Company’s 2008 Registration Statement.
10.16	Coal Loading, Transport, and Delivery Agreement effective as of April 1, 2007 by and between Tersteeg Transport Inc. and Heron Lake BioEnergy, LLC	Exhibit 10.16 of the Company’s 2008 Registration Statement.
10.17	Coal Transloading Agreement dated June 1, 2007 by and between Southern Minnesota Beet Sugar Cooperative and Heron Lake BioEnergy, LLC†	Exhibit 10.17 of the Company’s 2008 Registration Statement.
10.18	Master Coal Purchase and Sale Agreement dated June 1, 2007 by and between Northern Coal Transport Company and Heron Lake BioEnergy, LLC, including confirmation letter dated July 13, 2007†	Exhibit 10.18 of the Company’s 2008 Registration Statement.
10.19	Loan Agreement dated December 28, 2007 by and between Federated Rural Electric Association and Heron Lake BioEnergy, LLC	Exhibit 10.19 of the Company’s 2008 Registration Statement.
10.20	Secured Promissory Note issued December 28, 2007 by Heron Lake BioEnergy, LLC as borrower to Federated Rural Electric Association as lender in principal amount of $600,000	Exhibit 10.20 of the Company’s 2008 Registration Statement.
10.21	Security Agreement dated December 28, 2007 by Heron Lake BioEnergy, LLC in favor of Federated Rural Electric Association	Exhibit 10.21 of the Company’s 2008 Registration Statement.
10.22	Electric Service Agreement dated October 17, 2007 by and between Interstate Power and Light Company and Heron Lake BioEnergy, LLC	Exhibit 10.22 of the Company’s 2008 Registration Statement.
10.23	Shared Savings Contract dated November 16, 2007 by and between Interstate Power and Light Company and Heron Lake BioEnergy, LLC	Exhibit 10.23 of the Company’s 2008 Registration Statement.
10.24	Escrow Agreement dated November 16, 2007 by and between Heron Lake BioEnergy, LLC , Farmers State Bank of Hartland for the benefit of Interstate Power and Light Company	Exhibit 10.24 of the Company’s 2008 Registration Statement.
10.25	Employment Agreement dated February 1, 2008 by and between Heron Lake BioEnergy, LLC and Robert J. Ferguson *	Exhibit 10.25 of the Company’s 2008 Registration Statement.
10.26	Compliance Agreement effective January 23, 2007 by and between Heron Lake BioEnergy, LLC and the Minnesota Pollution Control Agency	Exhibit 10.28 to Amendment No. 1 to the Company’s 2008 Registration Statement.
10.27	Letter Agreement dated November 25, 2008 by and between Heron Lake BioEnergy, LLC, CFO Systems, LLC and Brett L. Frevert relating to the services of Brett L. Frevert *	Exhibit 10.1 to Current Report on Form 8-K dated November 26, 2008.
10.28	Ethanol Purchase and Marketing Agreement dated September 2, 2009 by and between Heron Lake BioEnergy, LLC and C&N Ethanol Marketing Corporation	Exhibit 10.1 to Current Report on Form 8-K dated September 2, 2009.
10.29	Amendment No. 4 to Fifth Supplement dated December 8, 2009 by and between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Exhibit 10.32 to Annual Report on Form 10-K for the year ended October 31, 2009.
10.30	Amendment No. 5 to Fifth Supplement to the Master Loan Agreement dated March 25, 2010 by and between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Exhibit 10.1 to Current Report on Form 8-K dated March 25, 2010
10.31	Amendment No. 6 to Fifth Supplement to the Master Loan Agreement dated May 27, 2010 by and between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Exhibit 10.2 to Current Report on Form 8-K dated March 25, 2010
10.32	Amended and Restated Fifth Supplement dated as of July 2, 2010 to the Master Loan Agreement by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.1 to Current Report on Form 8-K dated July 2, 2010

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Exhibit Number	Exhibit Title	Incorporated by Reference To:
10.33	Second Amended and Restated Revolving Line of Credit Note dated July 2, 2010 in the maximum principal amount of $6,750,000 by Heron Lake BioEnergy, LLC as borrower to AgStar Financial Services, PCA as lender	Exhibit 10.2 to Current Report on Form 8-K dated July 2, 2010
10.34	Forbearance Agreement dated July 2, 2010 by and between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Exhibit 10.3 to Current Report on Form 8-K dated July 2, 2010
10.35	Mutual Release and Settlement Agreement dated July 2, 2010 among Heron Lake BioEnergy, LLC, Fagen, Inc. and ICM, Inc. †	Exhibit 10.1 to Current Report on Form 8-K dated July 2, 2010
10.36	Subscription Agreement dated July 2, 2010 by Heron Lake BioEnergy, LLC and Project Viking, L.L.C.	Exhibit 10.1 to Current Report on Form 8-K dated July 2, 2010
10.37	First Amendment to Fifth Supplement to the Master Loan Agreement dated as of December 30, 2010 by and between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC	Exhibit 10.1 to Current Report on Form 8-K dated December 30, 2010
10.38	Third Amended and Restated Revolving Line of Credit Note dated December 30, 2010 in the maximum principal amount of $6,750,000 by Heron Lake BioEnergy, LLC as borrower to AgStar Financial Services, PCA as lender	Exhibit 10.2 to Current Report on Form 8-K dated December 30, 2010
10.39	First Amendment to Forbearance Agreement dated December 30, 2010 by and between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Exhibit 10.3 to Current Report on Form 8-K dated December 30, 2010
10.40	Fifth Amended and Restated Master Loan Agreement dated to be effective as of September 1, 2011 between AgStar Financial Services, PCA and Heron Lake BioEnergy, LLC†	Attached hereto.
10.41	Amended and Restated Term Note dated September 1, 2011 in principal amount of $40,000,000 by Heron Lake BioEnergy, LLC to AgStar Financial Services, PCA as lender	Attached hereto.
10.42	Amended and Restated Term Revolving Note dated September 1, 2011 in principal amount of $8,008,689 by Heron Lake BioEnergy, LLC to AgStar Financial Services, PCA as lender	Attached hereto.
10.43	Fourth Amended and Restated Mortgage, Security Agreement and Assignment of Rents and Leases dated September 1, 2011 between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Attached hereto.
10.44	Fifth Amended and Restated Guaranty dated September 1, 2011 by Lakefield Farmers Elevator, LLC in favor of AgStar Financial Services, PCA	Attached hereto.
10.45	Amended and Restated Guaranty dated September 1, 2011 by HLBE Pipeline Company, LLC in favor of AgStar Financial Services, PCA	Attached hereto.
10.46	Collateral Assignment dated September 1, 2011 between Heron Lake BioEnergy, LLC and AgStar Financial Services, PCA	Attached hereto.
10.47	Collateral Assignment dated September 1, 2011 between Lakefield Farmers Elevator, LLC and AgStar Financial Services, PCA	Attached hereto.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

	October 31, 2011			October 31, 2010

ASSETS
Current Assets
Cash and equivalents	$	7,140,573		$	1,523,318
Restricted cash	367,012			572,224
Restricted certificates of deposit	650,000			400,000
Accounts receivable	1,378,220			5,017,229
Inventory	3,764,616			10,637,023
Prepaid expenses	937,521			104,519
Total current assets	14,237,942			18,254,313

Property and Equipment
Land and improvements	12,265,434			12,208,498
Plant buildings and equipment	94,509,719			94,480,582
Vehicles and other equipment	635,054			620,788
Office buildings and equipment	615,298			605,431
Construction in progress	4,132,965			—
	112,158,470			107,915,299
Less accumulated depreciation	(23,565,525		)	(18,111,652		)
	88,592,945			89,803,647

Other Assets
Restricted cash	59,574			395,982
Other intangible assets, net	415,276			451,643
Debt service deposits and other assets	828,187			634,992
Total other assets	1,303,037			1,482,617

Total Assets	$	104,133,924		$	109,540,577

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

	October 31, 2011			October 31, 2010

LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Checks written in excess of bank balance	$	—		$	913,492
Line of credit	—			3,500,000
Current maturities of long-term debt	4,572,613			50,830,571
Accounts payable:
Trade accounts payable	2,704,707			2,852,083
Trade accounts payable - related party	109,101			955,137
Accrued expenses	421,306			881,215
Lower of cost or market accrued expense	—			707
Derivative instruments	—			101,388
Total current liabilities	7,807,727			60,034,593

Long-Term Debt, net of current maturities	46,844,912			4,068,716

Commitments and Contingencies

Members’ Equity
Controlling interest in equity:
37,208,074 and 30,208,074 Class A units outstanding at October 31, 2011 and October 31, 2010, respectively	49,508,123			45,437,268
Noncontrolling interest	(26,838		)	—
Total members’ equity	49,481,285			45,437,268

Total Liabilities and Members’ Equity	$	104,133,924		$	109,540,577

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

	Year Ended October 31, 2011			Year Ended October 31, 2010			Year Ended October 31, 2009

Revenues	$	164,120,375		$	110,624,758		$	88,304,596

Cost of Goods Sold
Cost of goods sold	155,571,814			102,786,513			85,448,407
Lower of cost or market adjustment	1,591,810			903,695			5,408,840
Total Cost of Goods Sold	157,163,624			103,690,208			90,857,247

Gross Profit (Loss)	6,956,751			6,934,550			(2,552,651		)

Operating Expenses	(3,613,465		)	(3,857,492		)	(4,515,476		)

Settlement Income	—			2,600,000			—

Operating Income (Loss)	3,343,286			5,677,058			(7,068,127		)

Other Income (Expense)
Interest income	37,078			43,179			78,320
Interest expense	(2,900,470		)	(4,048,634		)	(4,014,448		)
Write off of loan costs	—			—			(444,985		)
Other income	63,123			11,918			119,806
Total other expense, net	(2,800,269		)	(3,993,537		)	(4,261,307		)

Net Income (Loss)	543,017			1,683,521			(11,329,434		)

Net Loss Attributable to Noncontrolling Interest	(27,838		)	—			—

Net Income (Loss) Attributable to Heron Lake BioEnergy, LLC	$	570,855		$	1,683,521		$	(11,329,434	)

Weighted Average Units Outstanding - Basic and Diluted	33,391,636			28,141,942			27,104,625

Net Income (Loss) Per Unit - Basic and Diluted	$	0.02		$	0.06		$	(0.42	)

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

Balance - October 31, 2008	$	50,583,180

Net loss	(11,329,434		)

Balance - October 31, 2009	39,253,746

Capital Issuance — 3,103,449 Class A units, $1.45 per unit, July 2010	4,500,001

Net income	1,683,521

Balance - October 31, 2010	45,437,268

Capital Issuance — 7,000,000 Class A units, $0.50 per unit, May 2011	3,500,000

Capital Issuance for noncontrolling interest	1,000

Net loss attributable to noncontrolling interest	(27,838		)

Net income attributable to Heron Lake BioEnergy, LLC	570,855

Balance - October 31, 2011	$	49,481,285

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

	Year Ended October 31, 2011			Year Ended October 31, 2010			Year Ended October 31, 2009

Cash Flow From Operating Activities
Net income (loss)	$	543,017		$	1,683,521		$	(11,329,434	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	5,490,240			5,578,053			5,645,311
Amortization of loan costs included with interest expense	—			—			22,143
Write off of loan costs	—			—			444,985
Lower of cost or market adjustment	1,591,810			903,695			5,408,840
Unrealized losses on derivative instruments	—			193,590			—
Gain on disposal of assets	—			—			(38,301		)
Non-cash settlement income	—			(500,000		)	—
Change in operating assets and liabilities:
Restricted cash	205,212			(231,580		)	1,021,767
Accounts receivable	3,639,009			(577,528		)	(1,071,625		)
Inventory	6,857,746			(5,981,727		)	4,529,174
Derivative instruments	(107,271		)	(92,202		)	750,172
Prepaid expenses and other	(936,192		)	(59,135		)	406,505
Accounts payable	(993,412		)	621,970			(3,247,499		)
Accrued expenses	(454,026		)	314,735			53,771
Lower of cost or market accrued expense	(1,577,856		)	(2,055,662		)	(10,929,853		)
Net cash provided by (used in) operating activities	14,258,277			(202,270		)	(8,334,044		)

Cash Flows from Investing Activities
Proceeds from sale of assets	—			—			177,516
Payments for restricted certificates of deposit	(250,000		)	(400,000		)
Capital expenditures	(4,243,171		)	(119,047		)	(349,521		)
Payment for other intangibles	—			—			(59,835		)
Net cash used in investing activities	(4,493,171		)	(519,047		)	(231,840		)

Cash Flows from Financing Activities
Checks written in excess of bank balance	(913,492		)	913,492			—
Proceeds from (payments on) line of credit, net	(3,500,000		)	(1,500,000		)	5,000,000
Payments on long-term debt	(4,219,512		)	(5,100,700		)	(4,992,343		)
Proceeds from note payable	737,750
Debt service deposits	—			—			(26,850		)
Release of restricted cash	336,408			322,808			414,076
Issuance of member units	3,500,000			4,500,001			—
Cost of raising capital	(90,005		)	(75,040		)	—
Noncontrolling interest investment	1,000			—			—
Net cash provided by (used in) financing activities	(4,147,851		)	(939,439		)	394,883

Net Increase (Decrease) in cash and equivalents	5,617,255			(1,660,756		)	(8,171,001		)

Cash and Equivalents - Beginning of period	1,523,318			3,184,074			11,355,075

Cash and Equivalents - End of period	$	7,140,573		$	1,523,318		$	3,184,074

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

The Company owns and operates a 50 million gallon ethanol plant near Heron Lake, Minnesota with ethanol distribution throughout the continental United States. In addition, the Company produces and sells distillers grains with solubles as co-products of ethanol production. The Company was formed on April 12, 2001 to have an indefinite life. The Company converted the plant from being coal fuel to natural gas fuel in November 2011.

Principles of Consolidation

The financial statements include the accounts of Heron Lake BioEnergy, LLC and its wholly owned subsidiaries, Lakefield Farmers Elevator, LLC and HLBE Pipeline Company, LLC, collectively, the “Company.” HLBE Pipeline Company, LLC owns 73% of Agrinatural Gas, LLC (Agrinatural); the remaining 27% is included in the consolidated financial statements as a noncontrolling interest. All significant intercompany balances and transactions are eliminated in consolidation.

Fiscal Reporting Period

The Company’s fiscal year end for reporting financial operations is October 31.

Accounting Estimates

Management uses estimates and assumptions in preparing these financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. The Company uses estimates and assumptions in accounting for significant matters including, among others, the carrying value and useful lives of property and equipment, analysis of impairment on long-lived assets, contingencies and valuation of forward purchase contract commitments and inventory. The Company periodically reviews estimates and assumptions, and the effects of revisions are reflected in the period in which the revision is made. Actual results could differ from those estimates.

Noncontrolling Interest

Amounts recorded as noncontrolling interest relate to the net investment by an unrelated party in Agrinatural. Income and losses are allocated to the members of Agrinatural based on their respective percentage of membership units held. Agrinatural will provide natural gas to the plant with a specified price per MMBTU for an initial term of 10 years, with two renewal options for five year periods.

Revenue Recognition

Revenue from sales is recorded when title transfers to the customer, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists, and the sales price is fixed and determinable. The title transfers when the product is loaded into the railcar or truck, the customer takes ownership and assumes risk of loss.

In accordance with the Company’s agreements for the marketing and sale of ethanol and related products, marketing fees and commissions due to the marketers are deducted from the gross sales price as earned. These fees and commissions are recorded net of revenues as they do not provide an identifiable benefit that is sufficiently separable from the sale of ethanol and related products. Shipping costs incurred by the Company in the sale of ethanol are not specifically identifiable and as a result, are recorded based on the net selling price reported to the Company from the marketer. Shipping costs incurred by the Company in the sale of ethanol related products are included in cost of goods sold.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

Derivative Instruments

From time to time, the Company enters into derivative transactions to protect gross margins from potentially adverse effects of market and price volatility in future periods. In order to reduce the risks caused by market fluctuations, the Company hedges a portion of its anticipated corn and natural gas purchases, and ethanol sales by entering into options and futures contracts. These contracts are used with the intention to fix the purchase price of anticipated requirements for corn and natural gas in the Company’s ethanol production activities and the related sales price of ethanol produced. The fair value of these contracts is based on quoted prices in active exchange-traded or over-the-counter market conditions.

The Company generally does not designate these derivative instruments as hedges for accounting purposes and derivative positions are recorded on the balance sheet at their fair market value, with changes in fair value caused from marking these instruments to market, recognized in current period earnings or losses on a monthly basis. While the Company does not designate the derivative instruments that it enters into as hedging instruments because of the administrative costs associated with the related accounting, the Company believes that the derivative instruments represent an economic hedge.

In order for a derivative to qualify as a hedge, specific criteria must be met and appropriate documentation maintained. If the derivative does qualify as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be either offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. Gains and losses from derivatives that do not qualify as hedges, or are undesignated, must be recognized immediately in earnings.

The Company evaluates its contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted as “normal purchases or normal sales.” Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Certain corn, ethanol and distillers grains contracts that meet the requirement of normal purchases or sales are documented as normal and exempted from the accounting and reporting requirements, and therefore, are not marked to market in our financial statements.

Other Intangibles

Other intangibles are stated at cost and include road improvements located near the plant in which the Company has a beneficial interest in but does not own the road. The Company amortizes the assets over the economic useful life of 15 years.

Property and Equipment

Property and equipment are recorded at cost. Depreciation is provided over an estimated useful life by use of the straight-line deprecation method. Maintenance and repairs are expensed as incurred; major improvements and betterments are capitalized. Construction in progress is comprised of costs related to the construction of the ethanol plant facilities. Interest is capitalized during the construction period. Depreciable useful lives are as follows:

Land improvements		15 Years
Plant building and equipment		7 - 40 Years
Vehicles and equipment		5 - 7 Years
Office buildings and equipment		3 - 40 Years

The Company has construction in progress at October 31, 2011 of approximately $4,133,000 related to the construction of the natural gas equipment and connection to the plant. The construction was completed in fiscal 2012 related to the conversion from coal. The Company had approximately $500,000 remaining on construction in progress at October 31, 2011.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

Long-Lived Assets

The Company reviews property and equipment and other long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Circumstances which could trigger a review include, but are not limited to: significant decreases in the market price of the asset; significant adverse changes in the business climate or legal factors; accumulation of costs significantly in excess of the amount originally expected for the acquisition of construction of the asset; current period cash flow or operating losses combined with a history of losses or a forecast of continuing losses associated with the use of the assets; and current expectation that the asset will more likely than not be sold or disposed significantly before the end of its estimated useful life. If circumstances require a long-lived asset be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary.

The Company’s ethanol production facilities, has an installed capacity of 50 million gallons per year. The carrying value of these facilities at October 31, 2011 was approximately $88.6 million. In accordance with the Company’s policy for evaluating impairment of long-lived assets described above, management has evaluated the recoverability of the facilities based on projected future cash flows from operations over the facilities’ estimated useful lives. Management has determined that the projected future undiscounted cash flows from operations of these facilities exceed their carrying value at October 31, 2011; therefore, no impairment loss was indicated or recognized. In determining the projected future undiscounted cash flows, the Company has made significant assumptions concerning the future viability of the ethanol industry, the future price of corn in relation to the future price of ethanol and the overall demand in relation to production and supply capacity. Given the uncertainties in the ethanol industry, should management be required to adjust the carrying value of the facilities at some future point in time, the adjustment could be significant and could significantly impact the Company’s financial position and results of operations. No adjustment has been made to these financial statements for this uncertainty.

Deferred Loan Costs

Costs associated with the issuance of the debt discussed in Note 9 and 10 were recorded as deferred loan costs, net of accumulated amortization. Loan costs are amortized to operations over the term of the related debt using the effective interest method. During fiscal 2009, the Company expensed the remaining unamortized loan costs totaling approximately $445,000 associated with this debt when it was classified as current.

Deferred Offering Costs

The Company defers the costs incurred to raise equity financing until that financing occurs. At such time that the issuance of new equity occurs, these costs will be netted against the proceeds received.

Fair Value of Financial Instruments

On November 1, 2008, the Company adopted guidance for accounting for fair value measurements of financial assets and financial liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis. On November 1, 2009, the Company adopted guidance for fair value measurement related to nonfinancial items that are recognized and disclosed at fair value in the financial statements on a nonrecurring basis. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to measurements involving significant unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

· Level 2 includes:

1. Quoted prices in active markets for similar assets or liabilities.

2. Quoted prices in markets that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability.

3. Inputs that derived primarily from or corroborated by observable market date by correlation or other means.

· Level 3 inputs are unobservable inputs for the asset or liability.

The level in the fair value hierarchy within which a fair measurement in its entirety falls is based on the lowest level input that is significant to the fair value measurement in its entirety.

Except for those assets and liabilities which are required by authoritative accounting guidance to be recorded at fair value in our balance sheets, the Company has elected not to record any other assets or liabilities at fair value. No events occurred during the years ended October 31, 2011 or 2010 that required adjustment to the recognized balances of assets or liabilities, which are recorded at fair value on a nonrecurring basis.

The carrying value of cash and equivalents, restricted cash, restricted certificates of deposit, accounts receivable, accounts payable and accrued liabilities approximates fair value due to the short maturity of these instruments. The fair value of long-term debt has been estimated using discounted cash flow analysis based upon the Company’s current incremental borrowing rates for similar types of financing arrangements. The fair value of outstanding debt will fluctuate with changes in applicable interest rates. Fair value will exceed carrying value when the current market interest rate is lower than the interest rate at which the debt was originally issued. The fair value of a company’s debt is a measure of its current value under present market conditions. It does not impact the financial statements under current accounting rules. The Company believes the carrying amount of the revolving term loan and line of credit approximates the fair value.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

The Company estimates the fair value of debt based on the difference between the market interest rate and the stated interest rate of the debt. The carrying amount and the fair value of long-term debt are as follows:

	Carrying Amount		Fair Value

Long-term debt at October 31, 2011	$	51,417,525	$	51,417,525
Long-term debt at October 31, 2010	$	54,899,287	$	52,885,420

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes and generally does not incur income taxes. Instead, its earnings and losses are included in the income tax returns of the members. Therefore, no provision or liability for federal or state income taxes has been included in these financial statements. Differences between financial statement basis of assets and tax basis of assets is related to capitalization and amortization of organization and start-up costs for tax purposes, whereas these costs are expensed for financial statement purposes. In addition, the Company uses the alternative depreciation system (ADS) for tax depreciation instead of the straight-line method that is used for book depreciation, which also causes temporary differences. The Company’s tax year end is December 31. Primarily due to the partnership tax status, the Company does not have any significant tax uncertainties that would require disclosure. The Company recognizes and measures tax benefits when realization of the benefits is uncertain under a two-step approach. The first step is to determine whether the benefit meets the more-likely-than-not condition for recognition and the second step is to determine the amount to be recognized based on the cumulative probability that exceeds 50%. Primarily due to the Company’s tax status as a partnership, the adoption of this guidance had no material impact on the Company’s financial condition or results of operations.

The Company files income tax returns in the U.S. federal and Minnesota state jurisdictions. The Company is no longer subject to U.S. federal and state income tax examinations by tax authorities for years before 2008.

Net Income (Loss) per Unit

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

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

Environmental Liabilities

The Company’s operations are subject to environmental laws and regulations adopted by various governmental entities in the jurisdiction in which it operates. These laws require the Company to investigate and remediate the effects of the release or disposal of materials at its location. Accordingly, the Company has adopted policies, practices, and procedures in the areas of pollution control, occupational health, and the production, handling, storage and use of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. Environmental liabilities are recorded when the liability is probable and the costs can be reasonably estimated.

Reclassifications

The Company made reclassifications to certain fees received in the Consolidated Statement of Operations for the 2010 and 2009 to conform to classifications for 2011. The Company also made reclassifications for certain restricted cash amounts to be included with restricted certificates of deposit in the Consolidated Balance Sheet as of October 31, 2010 to conform to classifications at October 31, 2011. These reclassifications had no effect on members’ equity or net income as previously presented. The change related to restricted certificates of deposit increased operating cash flows by $400,000 and increased cash used in financing activities.

2. GOING CONCERN

The financial statements have been prepared on a going-concern basis, which contemplates the recoverability of assets and the satisfaction of liabilities in the normal course of business. The Company has previously disclosed losses related to operations related to difficult market conditions and operating performance. The Company has had instances of unwaived debt covenant violations and had been operating under forbearance agreements with AgStar Financial Services, PCA (“AgStar”). In addition, the Company’s working capital was at a lower level than desired. These conditions contributed to the long-term debt with AgStar being classified as current in previously filed financial statements. These factors and the continual volatile commodity prices raise substantial doubt about the Company’s ability to continue as a going concern.

The Company has continued to make changes to operations of the plant, renegotiated with AgStar, and enhance working capital. To this end, the Company began converting the plant from a coal-fired ethanol plant to a natural gas plant in October 2011. This conversion was completed in fiscal 2012. The Company believes the conversion will reduce production and operating costs, reduce interest costs, and improve operating profitability. In May 2011, the Company raised an additional $3.5 million from Project Viking, LLC (“Project Viking”) to help finance the natural gas conversion and to improve working capital. The Company closed on approximately $707,000 of additional equity in November 2011.

In September 2011, the Company entered into a restructured loan agreement with AgStar that superseded and replaced past loan agreements with AgStar including the forbearance agreements. This restructured loan agreement extends the maturity date of the Company’s long-term debt, maintains and extends the existing available balance on the revolving portion of the long-term debt, and allowed the Company to reclassify the debt to long-term. As part of this restructured loan agreement, the Company repaid the revolving line of credit with AgStar in September 2011. The repayment of the revolving line of credit was done as part of the change in ethanol and distillers marketers to Gavilon, LLC (“Gavilon”) in September 2011 as described in Note 14. In addition to assuming responsibility for marketing the ethanol and distillers products for the Company, Gavilon will assist the Company with certain risk management activities.

While the Company believe these changes will improve the operating performance of the plant, provide additional working capital, and reduce the effects on our plant of volatility in the industry, it is not yet certain as to whether these efforts and changes will be successful.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

3. UNCERTAINTIES

The Company has certain risks and uncertainties that it experienced during volatile market conditions. These volatilities can have a severe impact on operations. The Company’s revenues are derived from the sale and distribution of ethanol and distillers grains to customers primarily located in the U.S. Corn for the production process is supplied to the plant primarily from local agricultural producers. Ethanol sales average 75% - 85% of total revenues and corn costs average 65% - 75% of cost of goods sold.

The Company’s operating and financial performance is largely driven by the prices at which it sells ethanol and the net expense of corn. The price of ethanol is influenced by factors such as supply and demand, the weather, government policies and programs, unleaded gasoline prices and the petroleum markets as a whole. Excess ethanol supply in the market, in particular, puts downward pressure on the price of ethanol. The largest cost of production is corn. The cost of corn is generally impacted by factors such as supply and demand, the weather, government policies and programs, and a risk management program used to protect against the price volatility of these commodities. Market fluctuations in the price of and demand for these products may have a significant adverse effect on the Company’s operations, profitability and the availability and adequacy of cash flow to meet the Company’s working capital requirements.

4. FAIR VALUE MEASUREMENTS

The following table provides information on those assets and liabilities measured at fair value on a recurring basis.

	Fair Value as of			Fair Value Measurement Using
	October 31, 2010			Level 1			Level 2		Level 3

Commodity derivative instruments	$	(101,388	)	$	(101,388	)	$	—	$	—

The fair value of the derivative instruments is based on quoted market prices in an active market.

5. CONCENTRATIONS

The Company sells all of the ethanol and distiller grains produced to one customer under marketing agreements at October 31, 2011. Prior to the change in marketers as describe in Note 13, the Company sold all of its ethanol and distillers grain to two customers. At October 31, 2011 and 2010, these customers comprised nearly all of accounts receivable.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

6. INVENTORY

Inventory consists of the following at October 31:

	2011		2010

Raw materials	$	593,761	$	5,995,564
Work in process	978,967		1,042,844
Finished goods	—		2,021,672
Supplies	840,756		826,213
Other grains	1,351,132		750,730
Totals	$	3,764,616	$	10,637,023

The Company recorded losses of approximately $15,000, $97,000 and $352,000 for the fiscal years ended October 31, 2011, 2010 and 2009 respectively, related to inventory, in addition to losses recorded on forward purchase contracts as noted in Note 14, where the market value was less than the cost basis, attributable primarily to decreases in market prices of corn and ethanol. The loss was recorded with the lower of cost or market adjustment in the statement of operations. In addition, the Company stored grain inventory for farmers. The value of these inventories owned by others is approximately $105,000 and $2,543,000 based on market prices at October 31, 2011 and 2010, respectively, and is not included in the amounts above.

7. DERIVATIVE INSTRUMENTS

As of October 31, 2011, the Company has no corn or ethanol derivative instruments, which are required to be recorded as either assets or liabilities at fair value in the Consolidated Balance Sheet. As of October 31, 2010, the Company recorded a liability for derivative instruments of approximately $101,000 at fair value in the Consolidated Balance Sheet. Derivatives qualify for treatment as hedges when there is a high correlation between the change in fair value of the derivative instrument and the related change in value of the underlying hedged item and when the Company formally documents, designates, and assesses the effectiveness of transactions that receive hedge accounting initially and on an on-going basis. The Company must designate the hedging instruments based upon the exposure being hedged as a fair value hedge or a cash flow hedge. The Company does not enter into derivative transactions for trading purposes.

The Company enters into corn and ethanol derivatives in order to protect cash flows from fluctuations caused by volatility in commodity prices for periods up to 24 months. These derivatives are put in place to protect gross profit margins from potentially adverse effects of market and price volatility on ethanol sales and corn purchase commitments where the prices are set at a future date. Although these derivative instruments serve the Company’s purpose as an economic hedge, they are not designated as effective hedges for accounting purposes. For derivative instruments that are not accounted for as hedges, or for the ineffective portions of qualifying hedges, the change in fair value is recorded through earnings in the period of change.

The following tables provide details regarding the gains and (losses) from the Company’s derivative instruments in Consolidated Statements of Operations, none of which are designated as hedging instruments:

	Statement of	Twelve Months Ended October 31,
	Operations location	2011			2010			2009
Corn contracts	Cost of goods sold	$	(432,000	)	$	(1,007,000	)	$	1,207,000
Ethanol contracts	Revenues	(24,000		)	(171,000		)	373,000
Totals		$	(456,000	)	$	(1,178,000	)	$	1,580,000

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

	October 31		October 31
	2011		2010
Balance from previous page	$	46,612,058	$	50,123,483

Assessment payable as part of water treatment agreement, due in semi-annual installments of $189,393 with interest at 6.55%, enforceable by statutory lien, with the final payment due in 2021. The Company is required to make deposits over 24 months, which began in January 2007, for one years’ worth of debt service payments that are held on deposit to be applied with the final payments of the assessment.	2,653,090		2,837,720

Assessment payable as part of water treatment agreement, due in semi-annual installments of $25,692 with interest at 0.50%, enforceable by statutory lien, with the final payment due in 2016.	253,118		302,988

Assessment payable as part of water supply agreement, due in monthly installments of $4,126 with interest at 8.73%, enforceable by statutory lien, with the final payment due in 2019.	264,309		290,462

Note payable for equipment, with monthly payments of $2,371 including effective interest of 6.345%, due in April 2012, secured by equipment.	13,860		40,505

Note payable to electrical provider, with monthly payments of $29,775 including implicit interest of 1.50%, due in December 2013, secured by equipment and restricted cash.	439,590		785,379

Note payable to electrical company with monthly payments beginning in October 2009 of $6,250 with a 1% maintenance fee due each October, due September 2017. The electrical company is a member of the Company.	443,750		518,750

Note payable to financial institutions initially for the construction of the pipeline assets due initially in December 2011, extended until February 2012. The note is convertible into a term loan upon meeting certain conditions in February 2012 with a three year repayment period. Interest is at 5.75% and the note is secured by substantially all assets of Agrinatural, LLC and a debt guarantee by as described in Note 10.	737,750		—
Totals	51,417,525		54,899,287
Less amounts due within one year	4,572,613		50,830,571

Net long-term debt	$	46,844,912	$	4,068,716

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

At October 31, 2010 and during 2011, the Company was not in compliance with certain provisions of the AgStar loan agreements and therefore had classified the loans with them as current. Following changes made to the loan agreements with AgStar in September 2011, the Company reclassified the debt to long-term.

Term Note Payable

In September 2011 AgStar replaced and superseded the Company’s existing loan agreements, related loan documents and the amended forbearance agreements. The Company has a five-year term loan initially amounting to $40,000,000, comprised of two tranches of $20,000,000 each, with the first tranche bearing interest at a variable rate equal to the greater of LIBOR plus 3.50% or 5.0%, and the second tranche bearing interest at 5.75%. The Company must make equal monthly payments of principal and interest on the term loan based on a ten-year amortization, provided the entire principal balance and accrued and unpaid interest on the term loan is due and payable in full on the maturity date of September 1, 2016. In addition, the Company is required to make additional payments annually on debt for up to 25% of the excess cash flow, as defined by the agreement, up to $2 million per year. As part of the agreement, the premium above LIBOR on the loans may be reduced based on a financial ratio. The loan agreements are secured by substantially all business assets and are subject to various financial and non-financial covenants that limit distributions and debt and require minimum debt service coverage, net worth, and working capital requirements.

Prior to the changes in 2011, the Company was charged interest on the term note payable at LIBOR plus 3.25%. The Company had locked in an interest rate of 6.58% on $45 million of the note for three years ending in April 2011. The term note scheduled to mature in October 2012.

Revolving Term Note

The Company also obtained a five-year term revolving loan commitment in the amount of $8,008,689, under which AgStar agreed to make periodic advances to the Company up to this original amount until September 1, 2016. Amounts borrowed by the Company under the term revolving loan and repaid or prepaid may be re-borrowed at any time prior to maturity date of the term revolving loan, provided that outstanding advances may not exceed the amount of the term revolving loan commitment. Amounts outstanding on the term revolving loan bear interest at a variable rate equal to the greater of a LIBOR rate plus 3.50% or 5.0%, payable monthly. The Company also pays an unused commitment fee on the unused portion of the term revolving loan commitment at the rate of 0.35% per annum, payable in arrears in quarterly installments during the term of the term revolving loan. Under the terms of the new agreement, the term revolving loan commitment is scheduled to decline by $500,000 annually, beginning on September 1, 2012 and each anniversary date thereafter. The maturity date of the term revolving loan is September 1, 2016. The Company does have a $600,000 outstanding standby letter of credit at October 31, 2011.

Prior to the changes in September 2011, the revolving term note had an interest rate of LIBOR plus 3.25%. The Company had accrued default interest of 2.0% from February 2010 to July 2010 because of covenant defaults. AgStar agreed in 2011 to waive 50% of the default interest during 2011. The revolving term note was scheduled to mature in October 2012.

Estimated maturities of long-term debt at October 31, 2011 are as follows:

2012	$	4,572,613
2013	3,745,574
2014	4,210,387
2015	4,563,146
2016	32,627,401
After 2016	1,698,404

Total long-term debt	$	51,417,525

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

10. MEMBERS’ EQUITY

The Company is authorized to issue 80,000,000 capital units, of which 65,000,000 have been designated Class A units and 15,000,000 have been designated as Class B units. Members of the Company are holders of units who have been admitted as members and who hold at least 2,500 units. Any holder of units who is not a member will not have voting rights. Transferees of units must be approved by our board of governors to become members. Members are entitled to one vote for each unit held. Subject to the Member Control Agreement, all units share equally in the profits and losses and distributions of assets on a per unit basis.

In July 2010, the Company sold to Project Viking, L.L.C. (“Project Viking”), a related party, 3,103,449 of its Class A units at a price per unit of $1.45 for total gross proceeds to the Company of approximately $4.5 million as described in Note 13.

In 2010 the Company commenced a subscription rights offering to holders of its Class A units who are residents of the State of Minnesota initially for 4,700,000 Class A units for $1.45 per unit. In 2011, this offering was changed to offer 16,500,000 Class A units at a purchase price of $0.50 per unit. No eligible Class A unit holder could purchase more than 77.73% of the Units currently held by such unit holder as of August 30, 2011. In addition, purchasers of units were also required to deposit $.125 per unit into an escrow account that will be held to guarantee any potential debt of the Agrinatural. The offering period expired on October 15, 2011. The Company closed on the offering in November 2011 having sold 1,414,033 Class A units for approximately $707,000. The Company also collected approximately $177,000 related to the debt guarantee of the Agrinatural debt. The purchase price, percentage limitation and offering period were determined to comply with the terms of the May 2011 Subscription Agreement between the Company and Project Viking. At that time, Project Viking invested $3.5 million in the Company for 7,000,000 Class B units. These units sold to Project Viking were subsequently converted to Class A units. Project Viking agreed to guarantee up to $1 million of Agrinatural’s debt as part of its investment.

11. LEASES

The Company leases equipment, primarily rail cars, under operating leases through 2017. Equipment under operating lease primarily represents rail cars for which the rentals began in August 2007. Rent expense for fiscal 2011, 2010, and 2009 was approximately $1.9 million, $1.9 million, and $844,000, respectively.

At October 31, 2011, the Company had the following minimum future lease payments, which at inception had non-cancelable terms of more than one year:

2012	$	1,647,589
2013	1,562,988
2014	1,216,009
2015	833,280
2016	832,720
Thereafter	693,000

Total lease commitments	$	6,785,586

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

12. INCOME TAXES

The differences between consolidated financial statement basis and tax basis of assets and liabilities are estimated as follows at October 31:

	2011			2010

Consolidated financial statement basis of assets	$	104,133,924		$	109,540,577
Plus: Organization and start-up costs capitalized	1,952,135			2,181,759
Less: Accumulated tax depreciation and amortization greater than financial statement basis	(25,804,453		)	(20,379,880		)

Income tax basis of assets	$	80,281,606		$	91,342,456

	2011			2010

Consolidated financial statement basis of liabilities	$	54,652,639		$	64,103,305
Less: Accrued expenses	(421,306		)	(881,922		)
Less: Unrealized losses on derivatives	—			(101,388		)

Income tax basis of liabilities	$	54,231,333		$	63,119,995

13. RELATED PARTY TRANSACTIONS

As discussed in Note 10, pursuant to a subscription agreement, Project Viking invested $3.5 million in May 2011 in the Company for 7,000,000 Class B units, which were subsequently converted to Class A units.

In July 2010, the Company issued to Project Viking 3,103,449 Class A units at a price per unit of $1.45 for total gross proceeds to the Company of approximately $4.5 million. All proceeds from the sale of the units to Project Viking were used to reduce the principal balance of the Company’s revolving line of credit note with AgStar.

The Company purchased approximately $57,451,000, $43,233,000and $45,266,000 of corn from members in fiscal years 2011, 2010 and 2009, respectively.

Please refer to the section titled “Legal Proceedings” in Note 14 for information on the settlement of the arbitration proceedings between the Company and Fagen, Inc., a related party through its relationship with Project Viking. In addition, one of the conditions to the effectiveness of the Settlement Agreement was the release of Roland J. Fagen by AgStar from his obligations under his personal guaranty of $3.74 million of the Company’s indebtedness to AgStar under the Company’s master loan agreement. The effective date of the release of Mr. Fagen’s personal guaranty was July 2, 2010.

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HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

14. COMMITMENTS AND CONTINGENCIES

Water Agreements

In October 2003, the Company entered into an industrial water supply development and distribution agreement with the City of Heron Lake for 15 years. The Company has the exclusive rights to the first 600 gallons per minute of capacity that is available from the well, and provides for the Company, combined with Minnesota Soybean Processors (MnSP), to approve any other supply contracts that the City may enter into. In consideration, the Company will pay one half of the City’s water well bond payments of $735,000, plus a 5% administrative fee, totaling approximately $594,000, and operating costs, relative to the Company’s water usage, plus a 10% profit. These costs will be paid as water usage fees. The Company recorded an assessment of approximately $367,000 with long-term debt as described in Note 9. The Company pays operating and administrative expenses of approximately $12,000 per year.

In May 2006, the Company entered into a water treatment agreement with the City of Heron Lake and Jackson County for 30 years. The Company will pay for operating and maintenance costs of the plant in exchange for receiving treated water. In addition, the Company agreed to an assessment for a portion of the capital costs of the water treatment plant. The Company recorded assessments with long-term debt of $500,000 and $3,550,000 in fiscal 2007 and 2006, respectively, as described in Note 9. The Company paid operating and maintenance expenses of approximately $287,000, $327,000 and 370,000 in fiscal 2011, 2010 and 2009, respectively.

Marketing Agreements

The Company entered into a termination agreement with its previous marketers to terminate the marketing agreements the Company had with each, with termination dates of August 31, 2011. The Company assumed certain rail car leases with the termination of the ethanol marketing agreement and will pay a termination fee of $325,000 over the remaining term of the original contract, which is scheduled to end September 30, 2012.

F-21

Table of Contents

HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

Legal Proceedings

Permit Matters

The costs associated with obtaining and complying with permits and complying with environmental laws have increased the Company’s costs of construction, production and continued operation. In particular, the Company has incurred significant expense relating to its air-emission permit in four categories: (1) obtaining the air emissions permit from the Minnesota Pollution Control Agency (“MPCA”); (2) compliance with the air emissions permit and the terms of the Company’s compliance agreement with the MPCA; (3) the Company’s dispute under the design-build agreement with Fagen, Inc. relating to equipment failures, warranty claims and other claims regarding air emissions at its plant that was the subject of an arbitration action that was settled on July 2, 2010 as described below; and (4) a March 2008 notice of violation from the MPCA that was resolved in December 2010 though a stipulation agreement.

On December 16, 2010, the MPCA issued a permit to the Company that supersedes its previously granted air permit and the compliance agreement. The permit establishes the applicable limits for each type of emission generated by the Company’s ethanol plant. The permit also requires the Company to take additional actions relating to its plant and its operations within certain time frames.

On December 16, 2010, the Company entered into a stipulation agreement with the MPCA relating to the March 2008 notice of violation. Under the stipulation agreement, the Company agreed to pay a civil penalty of $66,000, of which $54,000 was paid within thirty days and up to $12,000 may be satisfied through the Company’s delivery of a building capture efficiency study.

While the Company’s air emissions permit issue was resolved with the December 16, 2010 issuance of a new air permit by the MPCA, the Company’s arbitration action against Fagen, Inc. has been settled, and the Company has addressed the notice of violation through a stipulation agreement, the Company anticipates future expense associated with compliance with its air permit and environmental laws. A violation of environmental laws, regulations or permit conditions can result in substantial fines, natural resource damage, criminal sanctions, permit revocations and/or plant shutdown, any of which could have a material adverse effect on the Company’s operations.

Fagen Design-Build Dispute and Settlement

On September 28, 2005, the Company executed a Design-Build Agreement with Fagen, Inc. (“Fagen”) by which Fagen agreed to design and build a 50 million gallon per year coal-fired ethanol plant in Heron Lake, Minnesota, for a contract price of approximately $76,000,000. On September 18, 2009, the Company served and filed on Fagen a demand for arbitration and request for mediation relating to the Design-Build Agreement and the air emissions warranties under the Design-Build Agreement. In the demand for arbitration, the Company alleged various breaches of the Design-Build Agreement, negligence and negligent misrepresentation by Fagen. On January 4, 2010, Fagen requested to join ICM, Inc. (“ICM”) as a party to the arbitration action and on January 27, 2010, ICM, Inc. agreed to be joined.

On July 2, 2010, the Company, Fagen and ICM entered into a Mutual Release and Settlement Agreement (“Settlement Agreement”) relating to the arbitration commenced by the Company in September 2009. Although ICM joined in the arbitration action, no claims against ICM, or answers, defenses, counterclaims or cross-claims by ICM, had been filed as of the date the Settlement Agreement was entered into. Under the terms of the Settlement Agreement, Fagen made a one-time cash payment to the Company, and released its claims to other amounts it claimed were owed by the Company under the Design-Build Agreement. In the Settlement Agreement, each party provided the other with full releases of all claims in the arbitration, relating to the Company’s ethanol plant, or relating to the Design-Build Agreement, except for certain claims arising under the ICM license agreement, which license agreement continues in full force and effect following the Settlement Agreement. The effective date of the Settlement Agreement was July 2, 2010.

In furtherance of the Settlement Agreement, the Company, Fagen and ICM stipulated to the dismissal of the arbitration, along with their respective asserted and unasserted claims, with prejudice. The American Arbitration Association acknowledged the stipulation of dismissal with prejudice on July 27, 2010.

From the settlement, the Company recorded $2.6 million of settlement income from cash and noncash proceeds during July 31, 2010 representing reimbursement for incremental expenses incurred by the Company due to design issue of the plant. Also, the construction payable of approximately $3.8 million was extinguished during the quarter ended July 31, 2010, reducing current liabilities and fixed assets as this adjustment represented a price adjustment of the plant. In connection with the settlement and with the Company’s forbearance agreement with AgStar, the Company sold Class A units as described in Notes 10 and 13.

F-22

Table of Contents

HERON LAKE BIOENERGY, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2011 and 2010

Coal Contract Termination Dispute

Following conversion by the Company from coal to natural gas as its primary fuel, and specifically in late October 2011, the Company received correspondence from its coal supplier, Northern Coal Transportation Company, claiming that there was a “shortfall” in the Company’s coal purchases. The correspondence further claimed that the Company is indebted to Northern Coal for approximately $929,000 for this shortfall. The Company responded in December 2011 and contested both the claim that there was any shortfall in coal purchases, as well as the calculation of any claimed shortfall. In this response, the Company also sought documentary verification of the claim by Northern Coal. The Company has not received the requested information or documentary support from Northern Coal. In January 2012, the Company received additional correspondence from Northern Coal claiming the Company now owned approximately $1,800,000. The Company has not recorded an accrual for any possible settlement involved in this dispute.

Forward Contracts

The Company has natural gas agreements with a minimum commitment of approximately 1.9 million MMBTU per year until October 31, 2014.

The Company recorded a loss on corn purchase commitments of approximately $1,577,000, $807,000and 5,056,000 for the twelve months ended October 31, 2011, 2010 and 2009 respectively. The loss was recorded as a lower of cost or market adjustment on the Consolidated Statement of Operations. The amount of the loss was determined by applying a methodology similar to that used in the lower of cost or market evaluation with respect to inventory. Given the uncertainty of future ethanol prices, this loss may or may not be recovered, and further losses on the outstanding purchase commitments could be recorded in future periods.

15. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarterly results are as follows:

	First		Second		Third			Fourth
	Quarter		Quarter		Quarter			Quarter
Fiscal year ended October 31, 2011
Revenues	$	39,199,181	$	38,022,811	$	43,013,930		$	43,884,453
Gross profit (loss)	3,226,245		1,840,466		688,880			1,201,160
Operating income (loss)	2,530,477		1,071,699		(182,475		)	76,415
Net income (loss)	1,676,923		438,674		(724,737		)	(847,843		)
Basic and diluted earnings (loss) per unit	0.06		0.01		(0.02		)	(0.03		)

	First		Second			Third			Fourth
	Quarter		Quarter			Quarter			Quarter
Fiscal year ended October 31, 2010
Revenues	$	29,413,131	$	25,698,413		$	23,621,607		$	31,891,607
Gross profit (loss)	4,551,412		699,690			(822,069		)	2,505,517
Operating income (loss)	3,539,838		(342,423		)	934,978			1,544,666
Net income (loss)	2,618,162		(1,492,613		)	(173,026		)	730,998
Basic and diluted earnings (loss) per unit	0.10		(0.06		)	(0.01		)	0.03

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
Fiscal year ended October 31, 2009
Revenues	$	18,095,366		$	21,493,104		$	22,196,118		$	26,520,008
Gross profit (loss)	(3,792,335		)	(1,197,101		)	(1,088,284		)	3,525,069
Operating income (loss)	(4,800,853		)	(1,902,778		)	(2,720,450		)	2,355,954
Net income (loss)	(6,246,806		)	(2,777,933		)	(3,785,147		)	1,480,452
Basic and diluted earnings (loss) per unit	(0.23		)	(0.10		)	(0.14		)	0.05

The above quarterly financial date is unaudited, but in the opinion of management, all adjustments necessary for a fair presentation of the selected data for these periods presented have been included.

F-23

PART I

Item 1.	Business
Item 1A.	Risk Factors
Item 1B.	Unresolved Staff Comments
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	[Removed and Reserved]

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures
Item 9B.	Other Information

PART III

Item 10.	Directors, Executive Officers and Corporate Governance
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.	Certain Relationships and Related Transactions, and Director Independence
Item 14.	Principal Accountant Fees and Services

PART IV

Item 15.	Exhibits and Financial Statement Schedules

SIGNATURES

Exhibit Number	Exhibit Title	Incorporated by Reference To:
10.48	Corn Supply Agreement dated effective as of September 1, 2011 between Heron Lake BioEnergy, LLC and Gavilon, LLC†	Attached hereto.
10.49	Ethanol and Distiller’s Grains Marketing Agreement dated effective as of September 1, 2011 between Heron Lake BioEnergy, LLC and Gavilon, LLC†	Attached hereto.
10.50	Master Netting, Setoff, Credit and Security Agreement dated effective as of September 1, 2011 between Heron Lake BioEnergy, LLC and Gavilon, LLC†	Attached hereto.
10.51	Corn Storage Agreement dated effective as of September 1, 2011 between Lakefield Farmers Elevator, LLC, Heron Lake BioEnergy, LLC and Gavilon, LLC	Attached hereto.
21.1	Subsidiaries of the Registrant	Attached hereto.
31.1	Certification of Chief Executive Officer (principal executive officer) pursuant to Rules 13a-14(a) and 15d-14(a) of the Exchange Act.	Attached hereto.
31.2	Certifications of Chief Financial Officer (principal financial officer) pursuant to Rules 13a-14(a) and 15d-14(a) of the Exchange Act.	Attached hereto.
32	Certification pursuant to 18 U.S.C. § 1350.	Attached hereto.
101.1	The following materials from Heron Lake BioEnergy, LLC’s Annual Report on Form 10-K for the fiscal year ended October 31, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.

	Year Ended October 31, 2011		Year Ended October 31, 2010		Year Ended October 31, 2009

Supplemental Disclosure of Cash Flow Information
Interest expense paid	$	3,377,199	$	3,660,433	$	4,040,240

Supplemental Disclosure of Non-Cash Activities
Release of retainage payable as part of legal settlement	$	—	$	3,834,319	$	—
Fair value of equipment received as part of settlement income	$	—	$	500,000	$	—

	October 31		October 31
	2011		2010

Term note payable to lending institution, see terms below.	$	39,747,497	$	48,967,611

Revolving term note payable to lending institution, see terms below.	6,864,561		1,155,872

Balance forward	$	46,612,058	$	50,123,483

	Page Reference

Audited Financial Statements

Report of Independent Registered Public Accounting Firm	F-1

Consolidated Balance Sheets as of October 31, 2011 and 2010	F-2

Consolidated Statements of Operations for the fiscal years ended October 31, 2011, 2010 and 2009	F-4

Consolidated Statements of Changes in Members’ Equity for the fiscal years ended October 31, 2011, 2010 and 2009	F-5

Consolidated Statements of Cash Flows for the fiscal years ended October 31, 2011, 2010 and 2009	F-6

Notes to Consolidated Financial Statements	F-8

	/s/ Boulay, Heutmaker, Zibell & Co. P.L.L.P.

	Certified Public Accountants