UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
	For the fiscal year ended September 30, 2013
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 000-52033

RED TRAIL ENERGY, LLC

(Exact name of registrant as specified in its charter)

North Dakota	76-0742311
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
3682 Highway 8 South, P.O. Box 11, Richardton, ND 58652
(Address of principal executive offices)
(701) 974-3308
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None.
Securities registered pursuant to Section 12(g) of the Act: Class A Membership Units

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

o Yes     x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

o Yes     x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes     o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes     o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large Accelerated Filer o	Accelerated Filer  o
Non-Accelerated Filer x	Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes     x No

The aggregate market value of the membership units held by non-affiliates of the registrant as of March 31, 2013 was $33,734,203.  There is no established public trading market for our membership units.  The aggregate market value was computed by reference to the most recent offering price of our Class A units which was $1 per unit.

As of December 16, 2013, there were 40,148,160 Class A Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The registrant has incorporated by reference into Part III of this Annual Report on Form 10-K portions of its definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days after the close of the fiscal year covered by this Annual Report.

1

INDEX

	Page Number
PART I	3
Item 1. Business	4
Item IA. Risk Factors	11
Item 2. Properties	14
Item 3. Legal Proceedings	14
Item 4. Mine Safety Disclosures	14
PART II	14
Item 5. Market for Registrant's Common Equity, Related Member Matters and Issuer Purchases of Equity Securities	14
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	27
Item 8. Financial Statements and Supplementary Data	29
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A. Controls and Procedures	48
Item 9B. Other Information	49
PART III	49
Item 10. Directors, Executive Officers and Corporate Governance	49
Item 11. Executive Compensation	49
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Member Matters	49
Item 13. Certain Relationships and Related Transactions, and Director Independence	49
Item 14. Principal Accountant Fees and Services	49
PART IV	49
Item 15. Exhibits and Financial Statement Schedules	49
SIGNATURES	52

2

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

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

Ÿ	The reduction or elimination of the renewable fuels use requirement in the Federal Renewable Fuels Standard;
Ÿ	An unfavorable spread between the market price of our products and our feedstock costs;
Ÿ	Fluctuations in the price and market for ethanol, distillers grains and corn oil;
Ÿ	Availability and costs of our raw materials, particularly corn and coal;
Ÿ	Changes in or lack of availability of credit;
Ÿ	Changes in the environmental regulations that apply to our plant operations and our ability to comply with such regulations;
Ÿ	Ethanol supply exceeding demand and corresponding ethanol price reductions impacting our ability to operate profitably and maintain a positive spread between the selling price of our products and our raw material costs;
Ÿ	Our ability to generate and maintain sufficient liquidity to fund our operations, meet debt service requirements and necessary capital expenditures;
Ÿ	Our ability to continue to meet our loan covenants;
Ÿ	Limitations and restrictions contained in the instruments and agreements governing our indebtedness;
Ÿ	Results of our hedging transactions and other risk management strategies;
Ÿ	Changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices that currently benefit the ethanol industry including:
	Ÿ national, state or local energy policy - examples include legislation already passed such as the       California low-carbon fuel standard as well as potential legislation in the form of carbon cap and trade;
	Ÿ legislation mandating the use of ethanol or other oxygenate additives; or
	Ÿ environmental laws and regulations that apply to our plant operations and their enforcement.
Ÿ	Changes and advances in ethanol production technology; and
Ÿ	Competition from alternative fuels and alternative fuel additives.

Our actual results or actions could and likely will differ materially from those anticipated in the forward-looking statements for many reasons, including the reasons described in this report. We are not under any duty to update the forward-looking statements contained in this report. We cannot guarantee future results, levels of activity, performance or achievements. We caution you not to put undue reliance on any forward-looking statements, which speak only as of the date of this report. You should read this report and the documents that we reference in this report and have filed as exhibits completely and with the understanding that our actual future results may be materially different from what we currently expect. We qualify all of our forward-looking statements by these cautionary statements.

AVAILABLE INFORMATION

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

PART I

Change in Fiscal Year End

On January 1, 2011, our board of governors approved the change in our fiscal year end from December 31 to September 30, effective January 1, 2011. As a result of this change, this Annual Report on Form 10-K includes financial information for the nine-month transition period from January 1, 2011 to September 30, 2011 (the "Transition Period"). References in this Annual

3

Report on Form 10-K to fiscal year 2012 or fiscal 2012 refer to the period from October 1, 2011 until September 30, 2012. References to the Transition Period refer to the nine-month period from January 1, 2011 to September 30, 2011.

ITEM 1.BUSINESS

Business Development

Red Trail Energy, LLC was formed as a North Dakota limited liability company in July of 2003, for the purpose of constructing, owning and operating a fuel-grade ethanol plant near Richardton, North Dakota in western North Dakota. References to "we," "us," "our" and the "Company" refer to Red Trail Energy, LLC. We have been in production since January 2007.

Effective May 15, 2013, we executed a loan amendment with our primary lender, First National Bank of Omaha. This loan amendment extended the maturity date of our short-term revolving line of credit to April 15, 2014 and increased the maximum amount of principal that we can draw on the short-term revolving line of credit to $10 million.

On August 29, 2013, we executed a new Distillers Grain Marketing Agreement with RPMG, Inc. ("RPMG"). The new Distillers Grain Marketing Agreement was effective starting on October 1, 2013. RPMG is the same company that markets our ethanol and corn oil pursuant to separate marketing agreements. We are also an equity owner in Renewable Products Marketing Group, LLC ("RPMG, LLC"), the parent company of RPMG. Pursuant to the new Distillers Grain Marketing Agreement, RPMG will market all of the dried distillers grains we produce and we will continue to internally market our modified/wet distillers grains. Due to the fact that we are a part owner of RPMG, LLC, RPMG will only charge us its actual cost of marketing our distillers grains to its customers.  The initial term of the Distillers Grain Marketing Agreement is one year and thereafter the agreement will renew for additional one year periods. The agreement may be terminated by either party based on certain events described in the agreement or based on the bankruptcy or insolvency of either party.

Financial Information

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

Principal Products

The principal products that we produce are ethanol, distillers grains and corn oil. We did not commence production of corn oil until the end of our second fiscal quarter of 2012. Therefore, our corn oil revenue during our 2012 fiscal year is not indicative of what we would expect for a full year of production. The table below shows the approximate percentage of our total revenue which is attributed to each of our primary products for each of our last three fiscal years, including the Transition Period in 2011.

Product	Fiscal Year 2013		Fiscal Year 2012		Transition Period 2011
Ethanol	77	%	79	%	84	%
Distillers Grains	21	%	20	%	16	%
Corn Oil	2	%	1	%	—	%

Ethanol

Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains, which can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based gasoline substitute. Ethanol produced in the United States is primarily used for blending with unleaded gasoline and other fuel products. Ethanol blended fuel is typically designated in the marketplace according to the percentage of the fuel that is ethanol, with the most common fuel blend being E10, which includes 10% ethanol. The United States Environmental Protection Agency ("EPA") has approved the use of gasoline blends that contain 15% ethanol, or E15, for use in all vehicles manufactured in model year 2001 and later. In addition, flexible fuel vehicles can use gasoline blends that contain up to 85% ethanol called E85.

4

Distillers Grains

The principal co-product of the ethanol production process is distillers grains, a high protein animal feed supplement primarily marketed to the dairy and beef industry. We produce two forms of distillers grains: Distillers Dried Grains with Solubles ("DDGS") and Modified Distillers Grains with Solubles ("MDGS"). MDGS is processed corn mash that has been dried to approximately 50% moisture. MDGS has a shelf life of approximately seven days and is often sold to nearby markets. DDGS is processed corn mash that has been dried to approximately 10% moisture. It has a longer shelf life and may be sold and shipped to any market regardless of its vicinity to our ethanol plant.

Corn Oil

In March 2012, we commenced operating our corn oil extraction equipment. The corn oil that we are capable of producing is not food grade corn-oil and it cannot be used for human consumption. The primary uses of the corn oil that we produce are for animal feed, industrial uses and biodiesel production.

Principal Product Markets

We market nearly all of our products through a professional third party marketer, RPMG, Inc. ("RPMG"). The only products we sell which are not marketed by RPMG are certain MDGS which we market internally to local customers. RPMG is a subsidiary of Renewable Products Marketing Group, LLC ("RPMG, LLC"). We are a part owner of RPMG, LLC which allows us to realize favorable marketing fees for our products and allows us to share in the profits generated by RPMG, LLC. Our ownership interest in RPMG, LLC also entitles us to a seat on its board of directors which is filled by Gerald Bachmeier, our Chief Executive Officer.  Except for the MDGS we market locally, RPMG makes all decisions with regard to where our products are marketed and sold. Our products are primarily sold in the domestic market; however, as domestic production of ethanol, distillers grains and corn oil continue to expand, we anticipate increased international sales of our products. Currently, the United States exports a significant amount of distillers grains to China, Mexico, Turkey and Canada along with many Pacific Rim countries.

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

Distribution Methods

Our ethanol plant is located near Richardton, North Dakota in Stark County, in the western section of North Dakota. We selected the Richardton site because of its location to existing coal supplies and accessibility to road and rail transportation. Our plant is served by the Burlington Northern and Santa Fe Railway Company.

We sell and market the ethanol, distillers grains and corn oil produced at the plant through normal and established markets, including local, regional and national markets. Our products are primarily shipped by rail and by truck in our local market. We have separate marketing agreements with RPMG for our ethanol, distillers grains and corn oil. Whether or not our products are sold in local markets will depend on decisions made by RPMG, except for the MDGS which we internally market locally. Local markets are evaluated on a case-by-case basis.

Ethanol

We have an exclusive marketing agreement with RPMG for the purposes of marketing and distributing all of the ethanol we produce at the ethanol plant. Because we an owner of RPMG, LLC, our marketing fees are based on RPMG's actual cost to market our ethanol. Our ethanol marketing agreement provides that we can sell our ethanol either through an index arrangement or at a fixed price agreed to between us and RPMG. The term of our ethanol marketing agreement is perpetual, until it is terminated according to the terms of the agreement. The primary reasons the ethanol marketing agreement would terminate are if we cease to be an owner of RPMG, LLC, if there is a breach of the agreement which is not cured, or if we give advance notice to RPMG that we would like to terminate the agreement. Notwithstanding our right to terminate the ethanol marketing agreement, we may be obligated to continue to market our ethanol through RPMG for a period of time after the termination. Further, following the termination, we agreed to accept an assignment of certain railcar leases which RPMG has secured to service us. If the ethanol marketing agreement is terminated, it would trigger a redemption of our ownership interest in RPMG, LLC.

5

Distillers Grains

We have a distillers grains marketing agreement with RPMG that became effective following the end of our 2013 fiscal year, on October 1, 2013. Our previous distillers grains marketer was CHS, Inc. According to our new distillers grains marketing agreement, RPMG will market all of the dried distillers grains we produce and we will continue to internally market our MDGS. Due to the fact that we are a part owner of RPMG, LLC, RPMG will only charge us its actual cost of marketing our distillers grains to its customers.  The initial term of the Distillers Grain Marketing Agreement is one year and thereafter the agreement will automatically renew for additional one year periods. The agreement may be terminated by either party based on certain events described in the agreement or based on the bankruptcy or insolvency of either party.

We market and sell our MDGS internally.  Substantially all of our sales of MDGS are to local farmers and feed lots.

Corn Oil

In March 2012, we executed a corn oil marketing agreement with RPMG to sell all of the corn oil that we produce. We pay RPMG a commission based on each pound of corn oil that RPMG sells on our behalf. The initial term of the corn oil marketing agreement was one year and the agreement automatically renews for additional one year terms unless either party gives notice that it will not extend the agreement past the current term.

New Products and Services

We did not introduce any new products or services during our 2013 fiscal year.

Sources and Availability of Raw Materials

Corn

Our ethanol plant used approximately 18.5 million bushels of corn during our 2013 fiscal year, or approximately 51,000 bushels per day, as the feedstock for its dry milling process. Our commodity manager is responsible for purchasing corn for our operations, scheduling corn deliveries and establishing hedging positions to protect the price we pay for corn.

During 2013, we were able to secure sufficient corn to operate the plant and do not anticipate any problems securing enough corn during 2014.   Almost all of our corn is supplied from farmers and local elevators in North Dakota and South Dakota. While we do not anticipate encountering problems sourcing corn, a shortage of corn could develop, particularly if we experience an extended drought or other production problem.  Poor weather can be a major factor in increasing corn prices.  If the United States were to endure an entire growing season with poor weather conditions, it could result in a prolonged period of higher than normal corn prices similar to what we experienced during 2013.  

Corn prices depend on several other factors as well, including world supply and demand and the price of other commodities.  United States production of corn can be volatile as a result of a number of factors, including weather, current and anticipated stocks, domestic and export prices and supports and the government's current and anticipated agricultural policy.  The price of corn was volatile during our 2013 fiscal year and we anticipate that it will continue to be volatile in the future.  We anticipate that increases in the price of corn, which are not offset by corresponding increases in the prices we receive from the sale of our products, could have a negative impact on our financial performance.

Coal

Coal is also an important input to our manufacturing process. During our 2013 fiscal year, we used approximately 80,000 tons of coal.  Our plant was originally designed to run on lignite coal, however, we experienced problems running on lignite during start up which caused us to change to sub-bituminous Powder River Basin ("PRB") coal. We have also considered adding natural gas as the fuel source for our ethanol plant, which we may begin implementing during our 2014 fiscal year.  

We purchase the coal needed to power our ethanol plant from a supplier under a contract which specifies quantity and price. Our coal supply contract expires annually at the end of December and we anticipate continuing to renew the coal supply contract in the future. Management anticipates that it will be able to enter into a new coal supply contract prior to the expiration of the current coal supply contract. We believe we could obtain alternative sources of PRB coal if necessary, though we could suffer delays in delivery and higher prices that could hurt our business and reduce our profits. We believe there is sufficient supply of coal from the PRB coal regions in Wyoming and Montana to meet our demand for PRB coal.

6

Electricity

The production of ethanol uses significant amounts of electricity. We entered into a contract with Roughrider Electric Cooperative to provide our needed electrical energy.   The term of the contract was up for renewal in August 2013 at which time it automatically renewed for an additional three year period.

Water

To meet the plant's water requirements, we entered into a ten-year contract with Southwest Water Authority to purchase raw water.  Our contract requires us to purchase a minimum of 160 million gallons per year.  We anticipate receiving adequate water supplies during our 2014 fiscal year.

Patents, Trademarks, Licenses, Franchises and Concessions

We do not currently hold any patents, trademarks, franchises or concessions. We were granted a perpetual and royalty free license by ICM to use certain ethanol production technology necessary to operate our ethanol plant. The cost of the license granted by ICM was included in the amount we paid to Fagen to design and build the plant.

Seasonality of Sales

We experience some seasonality of demand for our ethanol, distillers grains and corn oil. Since ethanol is predominantly blended with gasoline for use in automobiles, ethanol demand tends to shift in relation to gasoline demand. As a result, we experience some seasonality of demand for ethanol in the summer months related to increased driving and, as a result, increased gasoline demand. In addition, we experience some increased ethanol demand during holiday seasons related to increased gasoline demand. We also experience decreased distillers grains demand during the summer months due to natural depletion in the size of cattle feed lots and during times when cattle are turned out to pasture. Finally, corn oil is used for biodiesel production which typically decreases in the winter months due to decreased biodiesel demand. This decrease in biodiesel demand leads to decreased corn oil demand during the winter months.

Working Capital

We primarily use our working capital for purchases of raw materials necessary to operate our ethanol plant and for capital expenditures to maintain and upgrade the plant. Our primary sources of working capital are income from our operations as well as our revolving lines of credit with FNBO. During our 2013 fiscal year we used a portion of our working capital for capital improvements to our scrubber, replaced fermenter heat exchanger plate packs and made improvements to our centrifuges. Management anticipates pursuing installation of equipment which will allow us to use natural gas instead of coal for certain energy needs at the ethanol plant. No definitive agreement has been reached with respect to this project, but management anticipates that it may commence in 2014.

Dependence on a Few Major Customers

As discussed above, we rely on RPMG for the sale and distribution of all of our ethanol, DDGS and corn oil. Accordingly, we are highly dependent on RPMG for the successful marketing of most of our products. We anticipate that we would be able to secure alternate marketers should RPMG fail, however, a loss of our relationship with RPMG could significantly harm our financial performance.

Competition

We are in direct competition with numerous ethanol producers, many of whom have greater resources than we have. Larger ethanol producers may be able to take advantages of economies of scale due to their larger size and increased bargaining power with both customers and raw material suppliers. Following the significant growth in the ethanol industry during 2005 and 2006, the ethanol industry has grown at a much slower pace. As of November 30, 2013 the Renewable Fuels Association estimates that there are 210 ethanol production facilities in the United States with capacity to produce approximately 14.8 billion gallons of ethanol annually. The RFA also estimates that approximately 7% of the ethanol production capacity in the United States is currently idled. The ethanol industry is continuing to experience consolidation where a few larger ethanol producers are increasing their production capacities and are controlling a larger portion of United States ethanol production. The largest ethanol producers include Archer Daniels Midland, Flint Hills Resources, LP, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, each of which are capable of producing significantly more ethanol than we produce.

7

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

U.S. FUEL ETHANOL PRODUCTION CAPACITY BY TOP PRODUCERS

Producers of Approximately 600

million gallons per year (MMgy) or more

Company	Current Capacity (MMgy)	Under Construction/Expansions (MMgy)	Percent of Total Industry Capacity
Archer Daniels Midland	1,720	—	12	%
POET Biorefining	1,629	—	11	%
Valero Renewable Fuels	1,130	—	8	%
Green Plains Renewable Energy	1,004	—	7	%
Flint Hills Resources	660	—	4	%

Updated: November 30, 2013

Ethanol is a commodity product where competition in the industry is predominantly based on price and consistent fuel quality. Larger ethanol producers may be able to realize economies of scale in their operations that we are unable to realize. Further, we have experienced increased competition from oil companies who have started purchasing ethanol production facilities, including Valero Renewable Fuels and Flint Hills Resources, which are subsidiaries of larger energy companies. These oil companies are required to blend a certain amount of ethanol each year. Therefore, the oil companies may be able to operate their ethanol production facilities at times when it is unprofitable for us to operate our ethanol plant. Further, some ethanol producers own multiple ethanol plants which may allow them to compete more effectively by providing them flexibility to run certain production facilities while they have other facilities shut down. This added flexibility may allow these ethanol producers to compete more effectively, especially during periods when operating margins are unfavorable in the ethanol industry. Finally some ethanol producers who own ethanol plants in geographically diverse areas of the United States may spread the risk they encounter related to feedstock prices. The drought that occurred during 2012 and 2013 led to some areas of the United States with very poor corn crops and other areas with plentiful corn crops. Ethanol producers that own production facilities in different areas of the United States may reduce their risk of experiencing higher feedstock prices due to localized decreased corn crops.

In addition to domestic producers of ethanol, we face competition from ethanol produced in foreign countries, particularly Brazil. Ethanol imports were lower during our 2013 fiscal year compared to 2012 which was one of the reasons for improved operating margins in the ethanol industry. As of May 1, 2013, Brazil increased its domestic ethanol use requirement from 20% to 25% which decreased the amount of ethanol available in Brazil for export. However, in the future we may experience increased ethanol imports from Brazil which could put negative pressure on domestic ethanol prices and result in excess ethanol supply in the United States.

Research and Development

We are continually working to develop new methods of operating the ethanol plant more efficiently. We continue to conduct research and development activities in order to realize these efficiency improvements.

Governmental Regulation and Federal Ethanol Supports

Federal Ethanol Supports

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

If the RFS were to be repealed or modified, ethanol demand may be significantly impacted. The RFS for 2013 was approximately 16.55 billion gallons, of which corn based ethanol could be used to satisfy approximately 13.8 billion gallons. The

8

statutory volume requirement of the RFS for 2014 is approximately 18.15 billion gallons, of which corn based ethanol can be used to satisfy approximately 14.4 billion gallons. Recently, there have been proposals in Congress to reduce or eliminate the RFS. In addition, on November 15, 2013, the EPA announced a proposal to significantly reduce the RFS levels for 2014 from the statutory volume requirement of 18.15 billion gallons to 15.21 billion gallons and reduce the renewable volume obligations that can be satisfied by corn based ethanol from 14.4 billion gallons to 13 billion gallons. This proposal would also result in a lowering of the 2014 numbers below the 2013 level of 13.8 billion gallons. The EPA proposal is subject to a 60-day public comment period which ends on January 28, 2014. The EPA is also seeking comment on several petitions it has received for partial waiver of the statutory volumes for 2014. If the EPA's proposal becomes a final rule significantly reducing the RFS or if the RFS were to be otherwise reduced or eliminated by the exercise of the EPA waiver authority or by Congress, the market price and demand for ethanol will likely decrease which will negatively impact our financial performance. Current ethanol production capacity exceeds the EPA's proposed 2014 renewable volume obligation which can be satisfied by corn based ethanol by approximately 1.8 billion gallons.

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

Most ethanol that is used in the United States is sold in a blend called E10. E10 is a blend of 10% ethanol and 90% gasoline. E10 is approved for use in all standard vehicles. Estimates indicate that gasoline demand in the United States is approximately 134 billion gallons per year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.4 billion gallons per year. This is commonly referred to as the "blending wall," which represents a theoretical limit where more ethanol cannot be blended into the national gasoline pool. This is a theoretical limit because it is believed that it would not be possible to blend ethanol into every gallon of gasoline that is being used in the United States and it discounts the possibility of additional ethanol used in higher percentage blends such as E85 used in flex fuel vehicles.

Many in the ethanol industry believe that it will be impossible to meet the RFS requirement in future years without an increase in the percentage of ethanol that can be blended with gasoline for use in standard (non-flex fuel) vehicles. The United States Environmental Protection Agency (the "EPA") has approved 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. However, there were still significant federal and state regulatory hurdles that needed to be addressed. The EPA has made recent gains towards clearing those federal regulatory hurdles. In February 2012, the EPA approved health effects and emissions testing on E15 which was required by the Clean Air Act before E15 can be sold into the market. In March 2012, the EPA approved a model Misfueling Mitigation Plan and fuel survey which must be submitted by applicants before E15 registrations can be approved. In April 2012, the EPA approved the first E15 registrations approving twenty producers who have successfully registered their product to be used as E15. Finally, in June 2012, the EPA gave the final approval to allow the sale of E15. Although management believes that these developments are significant steps towards introduction of E15 in the marketplace, there are still obstacles to meaningful market penetration by E15. Many states still have regulatory issues that prevent the sale of E15. Sales of E15 may be limited because it is not approved for use in all vehicles, the EPA requires a label that management believes may discourage consumers from using E15, and retailers may choose not to sell E15 due to concerns regarding liability. In addition, different gasoline blendstocks may be required at certain times of the year in order to use E15 due to federal regulations related to fuel evaporative emissions. This may prevent E15 from being used during certain times of the year in various states. As a result, E15 has not had an immediate impact on ethanol demand in the United States.

The Volumetric Ethanol Excise Tax Credit ("VEETC") provided a volumetric ethanol excise tax credit of 4.5 cents per gallon of gasoline that contains at least 10% ethanol (total credit of 45 cents per gallon of ethanol blended which is 4.5 divided

9

by the 10% blend). VEETC expired on December 31, 2011. In addition to the expiration of the tax incentives, a 54 cent per gallon tariff imposed on ethanol imported into the United States also expired on December 31, 2011. The ethanol industry in the United States experienced increased competition from ethanol produced outside of the United States during 2012. These increased ethanol imports were likely at least in part due to the expiration of the tariff on imported ethanol. Although ethanol imports have decreased somewhat in 2013, elimination of the tariff could continue to lead to increased importation of ethanol produced in other countries, especially in areas of the United States that are easily accessible by international shipping ports. Ethanol imported from other countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably. Management believes that the expiration of VEETC has not had a significant effect on ethanol demand and does not expect it to have a significant effect in the future provided the RFS is maintained.

Effect of Governmental Regulation

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

We have obtained all of the necessary permits to operate the ethanol plant. During our 2013 fiscal year, we incurred costs and expenses of approximately $1,071,000 complying with environmental laws, including the cost of obtaining permits. Although we have been successful in obtaining all of the permits currently required, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources in complying with such regulations.

In late 2009, California passed a Low Carbon Fuels Standard ("LCFS"). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which is measured using a lifecycle analysis, similar to the RFS. On December 29, 2011, a federal district court in California ruled that the California LCFS was unconstitutional which halted implementation of the California LCFS. However, the California Air Resources Board ("CARB") appealed this court ruling and on September 18, 2013, the federal appellate court reversed the federal district court finding the LCFS constitutional and remanding the case back to federal district court to determine whether the LCFS imposes a burden on interstate commerce that is excessive in light of the local benefits. In addition, a state court in California recently required that CARB take certain corrective actions regarding the approval of the LCFS regulations while allowing the LCFS regulations to remain in effect during this process. If federal and state challenges to the LCFS are ultimately unsuccessful, the LCFS could have a negative impact on demand for corn-based ethanol and result in decreased ethanol prices.

The European Union concluded an anti-dumping investigation related to ethanol produced in the United States and exported to Europe. As a result of this investigation, the European Union has imposed a tariff on ethanol which is produced in the United States and exported to Europe. This tariff could result in decreased exports of ethanol to Europe which could negatively impact the market price of ethanol in the United States.

Employees

As of December 16, 2013, we had 43 full-time employees. We typically have 42 full-time employees and we anticipate that we will have approximately 44 full-time employees during the next 12 months.

Financial Information about Geographic Areas

All of our operations are domiciled in the United States. All of the products sold to our customers for our 2013 and 2012 fiscal years and the Transition Period of 2011 were produced in the United States and all of our long-lived assets are domiciled in the United States. We have engaged a third-party professional marketer who decides where our products are marketed and we have limited control over the marketing decisions made by our marketer. Our marketer may decide to sell our products in countries other than the United States. However, we anticipate that our products will primarily be marketed and sold in the United States.

10

ITEM 1A. RISK FACTORS

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

Risks Relating to Our Business

A decrease in the spread between the price we receive for our products and our raw material costs will negatively impact our profitability. Practically all of our revenue is derived from the sale of our ethanol, distillers grains and corn oil. Our primary raw material costs are corn costs and energy costs. Our profitability depends on a positive spread between the market price of the ethanol, distillers grains and corn oil we produce and the raw material costs related to these products. While ethanol, distillers grains and corn oil prices typically change in relation to corn prices, this correlation may not always exist. In the event the prices of our products decrease at a time when our raw material costs are increasing, we may not be able to profitably operate the plant. In the event the spread between the price we receive for our products and the raw material costs associated with producing those products is negative for an extended period of time, we may not be able to maintain liquidity and we may fail which could negatively impact the value of our units.

We may violate the terms of our credit agreements and financial covenants which could result in our lender demanding immediate repayment of our loans. We have a comprehensive credit facility with FNBO, our primary lender. Our credit agreements with FNBO include various financial and non-financial loan covenants. We are currently in compliance with all of our loan covenants and we anticipate that we will be in compliance with our loan covenants for at least the next 12 months. However, unforeseen circumstances may develop which could result in us violating our loan covenants. If we violate the terms of our credit agreements, including our loan covenants, FNBO could deem us to be in default of our loans and require us to immediately repay the entire outstanding balance of our loans. If we do not have the funds available to repay the loans or we cannot find another source of financing, we may fail which could decrease or eliminate the value of our units.

We engage in hedging transactions which involve risks that could harm our business.  We are exposed to market risk from changes in commodity prices, including the prices we pay for our raw materials and the prices we receive for our finished products. We seek to minimize our exposure to fluctuations in the prices of corn, ethanol and distillers grains through the use of hedging instruments. However, our hedging activities may not successfully reduce the risk caused by price fluctuations which may leave us vulnerable to volatility in corn, ethanol and distillers grains prices. Alternatively, we may choose not to engage in hedging transactions in the future and our operations and financial conditions may be adversely affected during periods in which corn prices increase. Further, using cash for margin calls to support our hedge positions can have an impact on the cash we have available for our operations which could negatively impact our liquidity during times when corn prices fall significantly. The effects of our hedging activities may negatively impact our ability to profitably operate which could reduce the value of our units.

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

We depend on our management and key employees, and the loss of these relationships could negatively impact our ability to operate profitably. We are highly dependent on our management team to operate our ethanol plant. We may not be able to replace these individuals should they decide to cease their employment with us, or if they become unavailable for any other reason. While we seek to compensate our management and key employees in a manner that will encourage them to continue their employment with us, they may choose to seek other employment. Any loss of these officers and key employees may prevent us from operating the ethanol plant profitably and could decrease the value of our units.

11

Risks Related to the Ethanol Industry

Excess ethanol supply in the market could put negative pressure on the price of ethanol which could lead to tight operating margins and may impact our ability to operate profitably. In the past the ethanol industry has confronted market conditions where ethanol supply exceeded demand which led to unfavorable operating conditions. Most recently, in 2012, profitability in the ethanol industry was reduced due to increased ethanol imports from Brazil at a time when gasoline demand in the United States was lower and domestic ethanol supplies were higher. This disconnect between ethanol supply and demand resulted in lower ethanol prices at a time when corn prices were higher which led to unfavorable operating conditions. We may experience periods of time when ethanol supply exceeds demand which could negatively impact our profitability. We may experience periods of ethanol supply and demand imbalance during 2014 if the ethanol use requirement in the RFS is reduced as was recently proposed by the EPA. If we experience excess ethanol supply, either due to increased ethanol production or lower gasoline demand, it could negatively impact the price of ethanol which could hurt our ability to profitably operate the ethanol plant.

If exports to Europe are decreased due to the imposition by the European Union of a tariff on U.S. ethanol, ethanol prices may be negatively impacted. The European Union concluded an anti-dumping investigation related to ethanol produced in the United States and exported to Europe. As a result of this investigation, the European Union has imposed a tariff on ethanol which is produced in the United States and exported to Europe. If exports of ethanol to Europe decrease as a result of this tariff, it could negatively impact the market price of ethanol in the United States. Any decrease in ethanol prices or demand may negatively impact our ability to profitably operate the ethanol plant.

We operate in an intensely competitive industry and compete with larger, better financed entities which could impact our ability to operate profitably.  There is significant competition among ethanol producers. There are numerous producer-owned and privately-owned ethanol plants operating throughout the Midwest and elsewhere in the United States.  We also face competition from outside of the United States. The largest ethanol producers include Archer Daniels Midland, Flint Hills Resources, Green Plains Renewable Energy, POET, and Valero Renewable Fuels, all of which are each capable of producing significantly more ethanol than we produce. Further, many believe that there will be further consolidation occurring in the ethanol industry in the future which will likely lead to a few companies which control a significant portion of the United States ethanol production market. We may not be able to compete with these larger entities. These larger ethanol producers may be able to affect the ethanol market in ways that are not beneficial to us which could negatively impact our financial performance. 

Demand for ethanol may not continue to grow unless ethanol can be blended into gasoline in higher percentage blends for standard vehicles.  Currently, ethanol is primarily blended with gasoline for use in standard (non-flex fuel) vehicles to create a blend which is 10% ethanol and 90% gasoline.  Estimates indicate that approximately 134 billion gallons of gasoline are sold in the United States each year.  Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.4 billion gallons. This is commonly referred to as the "blend wall," which represents a theoretical limit where more ethanol cannot be blended into the national gasoline pool.  Many in the ethanol industry believe that the ethanol industry has reached this blend wall, especially in light of the proposed decrease to the 2014 renewable volume obligation.  In order to expand demand for ethanol, higher percentage blends of ethanol must be utilized in standard vehicles.  Such higher percentage blends of ethanol are a contentious issue.  Automobile manufacturers and environmental groups have fought against higher percentage ethanol blends. Recently, the EPA approved the use of E15 for standard vehicles produced in the model year 2001 and later. The fact that E15 has not been approved for use in all vehicles and the labeling requirements associated with E15 may lead to gasoline retailers refusing to carry E15.  Without an increase in the allowable percentage blends of ethanol that can be used in all vehicles, demand for ethanol may not continue to increase which could decrease the selling price of ethanol and could result in our inability to operate the ethanol plant profitably.  This could reduce or eliminate the value of our units.

Technology advances in the commercialization of cellulosic ethanol may decrease demand for corn-based ethanol which may negatively affect our profitability.  The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas of the country which are unable to grow corn.  The Energy Independence and Security Act of 2007 and the 2008 Farm Bill offer strong incentives to develop commercial scale cellulosic ethanol.  The RFS requires that 16 billion gallons per year of advanced bio-fuels must be consumed in the United States by 2022.  Additionally, state and federal grants have been awarded to several companies which are seeking to develop commercial-scale cellulosic ethanol plants.  This has encouraged innovation and has led to several companies which are either in the process or have completed construction of commercial scale cellulosic ethanol plants. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue and our financial condition will be negatively impacted.

12

Risks Related to Regulation and Governmental Action

Government incentives for ethanol production may be eliminated in the future, which could hinder our ability to operate at a profit. The ethanol industry is assisted by various federal ethanol production and tax incentives, including the RFS set forth in the Energy Policy Act of 2005. The RFS helps support a market for ethanol that might disappear without this incentive. Recently, there have been proposals in Congress to reduce or eliminate the RFS. In addition, on November 15, 2013, the EPA announced a proposal to significantly reduce the RFS levels for 2014 from the statutory volume requirement of 18.15 billion gallons to 15.21 billion gallons and reduce the renewable volume obligations that can be satisfied by corn based ethanol from 14.4 billion gallons to 13 billion gallons. This proposal would also result in a lowering of the 2014 numbers below the 2013 level of 13.8 billion gallons. The EPA is also seeking comment on several petitions it has received for partial waiver of the statutory volumes for 2014. If the EPA's proposal becomes a final rule significantly reducing the RFS or if the RFS were to be otherwise reduced or eliminated by the exercise of the EPA waiver authority or by Congress, it may lead to a significant decrease in ethanol demand which could negatively impact our results of operations.

The Secondary Tariff on Imported Ethanol expired on December 31, 2011, and its absence could negatively impact our profitability. The secondary tariff on imported ethanol was allowed to expire on December 31, 2011. This secondary tariff on imported ethanol was a 54 cent per gallon tariff on ethanol produced in certain foreign countries. Following the expiration of this tariff, the price of ethanol in the United States increased significantly, due in part to higher corn prices. This made the United States a favorable market for foreign ethanol producers to export ethanol, especially in areas of the United States which are served by international shipping ports. Ethanol imports increased significantly during 2012. This increase in ethanol imports resulted in lower demand for domestically produced ethanol. While imports were lower in 2013, partially due to increased ethanol use requirements in Brazil, these policies could change and market conditions could once again result in increased ethanol imports. Management believes that any increase in ethanol imports may result in less favorable operating margins which could decrease the value of our units.

Changes in environmental regulations or violations of these regulations could beexpensive and reduce our profitability.  We are subject to extensive air, water and other environmental laws and regulations.  In addition, some of these laws require the plant to operate under a number of environmental permits. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.  A violation of these laws and regulations or permit conditions can result in substantial fines, damages, criminal sanctions, permit revocations and/or plant shutdowns.  In the future, we may be subject to legal actions brought by environmental advocacy groups and other parties for actual or alleged violations of environmental laws or our permits.  Additionally, any changes in environmental laws and regulations, both at the federal and state level, could require us to spend considerable resources in order to comply with future environmental regulations. The expense of compliance could be significant enough to reduce our profitability and negatively affect our financial condition.

Carbon dioxide may be regulated in the future by the EPA as an air pollutant requiring us to obtain additional permits and install additional environmental mitigation equipment, which could adversely affect our financial performance. In 2007, the Supreme Court decided a case in which it ruled that carbon dioxide is an air pollutant under the Clean Air Act for the purposes of motor vehicle emissions. In 2011 the EPA issued a tailoring rule that deferred greenhouse gas regulations for ethanol plants until July of 2014. However, in July of 2013, the D.C. Circuit issued an opinion vacating the EPA's deferral of those regulations for biogenic sources, including ethanol plants. Our plant produces a significant amount of carbon dioxide. While there are currently no regulations restricting carbon dioxide emissions, if the EPA or the State of North Dakota were to regulate carbon dioxide emissions by plants such as ours, we may have to apply for additional permits or we may be required to install carbon dioxide mitigation equipment or take other as yet unknown steps to comply with these potential regulations. Compliance with any future regulation of carbon dioxide, if it occurs, could be costly and may prevent us from operating the ethanol plant profitably which could decrease or eliminate the value of our units.

The California Low Carbon Fuel Standard may decrease demand for corn based ethanol which could negatively impact our profitability. California passed a Low Carbon Fuels Standard ("LCFS") which requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which reductions are measured using a lifecycle analysis. Management believes that these regulations could preclude corn based ethanol produced in the Midwest from being used in California. California represents a significant ethanol demand market. If the ethanol industry is unable to supply corn based ethanol to California, it could significantly reduce demand for the ethanol we produce. Recently, a federal appellate court found the LCFS constitutional and remanded the case back to federal district court to determine whether the LCFS imposes a burden on interstate commerce that is excessive in light of the local benefits. If challenges to the LCFS are ultimately unsuccessful, the LCFS could have a negative impact on demand for corn-based ethanol negatively impacting ethanol prices. This could result in a reduction of our revenues and negatively impact our ability to profitably operate the ethanol plant.

13

ITEM 2. PROPERTIES

Our ethanol plant is located just east of the city limits of Richardton, North Dakota, and just north and east of the entrance/exit ramps to Interstate I-94. The plant complex is situated inside a footprint of approximately 25 acres of land which is part of an approximately 135 acre parcel.  We acquired ownership of the land in 2004 and 2005. Included in the immediate campus area of the plant are perimeter roads, buildings, tanks and equipment. An administrative building and parking area are located approximately 400 feet from the plant complex.  During our 2012 fiscal year, we purchased an additional approximately 110 acres of land that is adjacent to our current property. During 2008 we purchased an additional 10 acre parcel of land that is adjacent to our current property.  Our coal unloading facility and storage site was built on this property.

The site also contains improvements such as rail tracks and a rail spur, landscaping, drainage systems and paved access roads.  The ethanol plant was placed in service in January 2007 and is in excellent condition and is capable of functioning at 100 percent of its 50 million gallon name-plate production capacity.

All of our tangible and intangible property, real and personal, serves as the collateral for our senior credit facility with FNBO. Our senior credit facility is discussed in more detail under"ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS - Capital Resources."

ITEM 3.    LEGAL PROCEEDINGS

From time to time in the ordinary course of business, we may be named as a defendant in legal proceedings related to various issues, including without limitation, workers' compensation claims, tort claims, or contractual disputes. We are not currently involved in any material legal proceedings.

ITEM 4.    MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established trading market for our membership units.  We have engaged FNC Ag Stock, LLC to create a Qualified Matching Service ("QMS") in order to facilitate trading of our units.  The QMS consists of an electronic bulletin board that provides information to prospective sellers and buyers of our units.  Please see the table below for information on the prices of units transferred in transactions completed via the QMS.  We do not become involved in any purchase or sale negotiations arising from the QMS and we take no position as to whether the average price or the price of any particular sale is an accurate measure of the value of our units.  As a limited liability company, we are required to restrict the transfers of our membership units in order to preserve our partnership tax status.  Our membership units may not be traded on any established securities market or readily traded on a secondary market (or the substantial equivalent thereof).  All transfers are subject to a determination that the transfer will not cause the Company to be deemed a publicly traded partnership.

We have no role in effecting the transactions beyond approval, as required under our Operating Agreement and the issuance of new certificates.  So long as we remain a publicly reporting company, information about us will be publicly available through the SEC's EDGAR filing system.  However, if at any time we cease to be a publicly reporting company, we may continue to make information about us publicly available on our website.

As of December 16, 2013, there were 920 holders of record of our Class A units.

The following table contains historical information by quarter for the past two years regarding the actual unit transactions that were completed by our unit-holders during the periods specified. The information was compiled by reviewing the completed unit transfers that occurred on the QMS bulletin board or through private transfers during the quarters indicated.

14

Quarter	Low Price		High Price		Average Price		# of Units Traded
2012 1st	$	—	$	—	$	—	—
2012 2nd	$	0.55	$	0.65	$	0.63	137,372
2012 3rd	$	0.54	$	0.65	$	0.56	133,813
2012 4th	$	0.50	$	0.58	$	0.52	210,000
2013 1st	$	—	$	—	$	—	—
2013 2nd	$	0.50	$	0.50	$	0.50	100,068
2013 3rd	$	0.50	$	0.50	$	0.50	50,000
2013 4th	$	0.50	$	0.50	$	0.50	30,000

DISTRIBUTIONS

We did not make any distributions to our members during our 2012 or 2013 fiscal years. Distributions are payable at the discretion of our Board, subject to the provisions of the North Dakota Limited Liability Company Act and our Member Control Agreement. Distributions to our unit holders are also subject to certain loan covenants and restrictions that require us to make additional loan payments based on excess cash flow. These loan covenants and restrictions are described in greater detail under "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources." A unit holder's distribution is determined by dividing the number of units owned by such unit holder by the total number of units outstanding.

15

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected financial and operating data as of the dates and for the periods indicated. The selected balance sheet financial data as of September 30, 2011 and December 31, 2010 and 2009 and the selected income statement data and other financial data for the fiscal years years ended December 31, 2010 and 2009 have been derived from our audited financial statements that are not included in this Form 10-K. The selected balance sheet financial data as of September 30, 2013 and 2012 and the selected statement of operations data and other financial data for the fiscal years ended September 30, 2013 and 2012 and the Transition Period ended September 30, 2011 have been derived from the audited Financial Statements included elsewhere in this Form 10-K. You should read the following table in conjunction with "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and the accompanying notes included elsewhere in this Form 10-K. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following financial data.

	Fiscal Year Ended						Nine-Month Transition Period Ended		Fiscal Year Ended
Statement of Operations Data:	September 30, 2013			September 30, 2012			September 30, 2011		December 31, 2010			December 31, 2009
Revenues	$	154,790,603		$	131,458,769		$	112,290,222	$	109,895,184		$	93,836,661
Cost of Goods Sold	151,588,287			136,013,928			108,137,084		95,946,218			87,850,869
Gross Profit (Loss)	3,202,316			(4,555,159		)	4,153,138		13,948,966			5,985,792
General and Administrative	2,145,733			2,224,351			1,972,679		3,116,212			2,812,891
Operating Income (Loss)	1,056,583			(6,779,510		)	2,180,459		10,832,754			3,172,901
Other Income (Expense)	(422,420		)	2,081,535			1,671,836		(1,803,982		)	(2,812,241		)
Net Income (Loss)	$	634,163		$	(4,697,975	)	$	3,852,295	$	9,028,772		$	360,660
Weighted Average Units Outstanding - Basic	40,151,941			40,204,971			40,193,973		40,193,973			40,191,494
Weighted Average Units Outstanding - Diluted	40,153,201			40,217,471			40,213,973		40,193,973			40,191,494
Net Income (Loss) Per Unit - Basic and Diluted	$	0.02		$	(0.12	)	$	0.10	$	0.22		$	0.01

16

Balance Sheet Data:	September 30, 2013		September 30, 2012		September 30, 2011		December 31, 2010		December 31, 2009
Current Assets	$	16,511,489	$	17,716,814	$	24,318,071	$	22,292,500	$	25,384,612
Net Property and Equipment	52,193,186		55,372,225		63,363,997		66,544,644		71,415,582
Total Assets	71,740,861		75,748,166		89,197,878		89,924,953		97,677,401
Current Liabilities	10,958,459		12,184,043		42,060,094		20,451,155		18,634,421
Long-Term Liabilities	18,111,281		21,527,164		361,353		26,569,662		45,167,616
Members' Equity	42,671,121		42,036,959		46,776,431		42,904,136		33,875,364
Book Value Per Unit	$	1.06	$	1.05	$	1.17	$	1.07	$	0.84
Dividends Declared Per Unit	$	—	$	—	$	—	$	—	$	—

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

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

Results of Operations for the Fiscal Year Ended September 30, 2013 and 2012

The following table shows the results of our operations and the approximate percentage of revenues, costs of goods sold, general and administrative expenses and other items to total revenues in our statements of operations for the fiscal years ended September 30, 2013 and 2012:

	Fiscal Year Ended September 30, 2013					Fiscal Year Ended September 30, 2012
Statement of Operations Data	Amount			%		Amount			%
Revenues	$	154,790,603		100.00		$	131,458,769		100.00
Cost of Goods Sold	151,588,287			97.93		136,013,928			103.47
Gross Profit (Loss)	3,202,316			2.07		(4,555,159		)	(3.47	)
General and Administrative Expenses	2,145,733			1.39		2,224,351			1.69
Operating Income (Loss)	1,056,583			0.68		(6,779,510		)	(5.16	)
Other Income (Expense)	(422,420		)	(0.27	)	2,081,535			1.58
Net Income (Loss)	$	634,163		0.41		$	(4,697,975	)	(3.58	)

17

The following table shows additional data regarding production and price levels for our primary inputs and products for the fiscal years ended September 30, 2013 and 2012:

	Fiscal Year Ended September 30, 2013		Fiscal Year Ended September 30, 2012
Production:
Ethanol sold (gallons)	51,528,405		47,340,485
Dried distillers grains sold (tons)	91,304		95,953
Modified distillers grains sold (tons)	83,052		71,729
Corn oil sold (pounds)	7,988,680		2,180,690
Revenues:
Ethanol average price/gallon (net of hedging)	$	2.31	$	2.18
Dried distillers grains price/ton	240.78		205.88
Modified distillers grains price/ton	122.08		99.82
Corn oil price/pound	0.31		0.33
Primary Input:
Corn ground (bushels)	18,556,113		17,672,456
Costs of Primary Input:
Corn avg price/bushel (net of hedging)	$	6.80	$	6.57
Other Costs (per gallon of ethanol sold):
Chemical and additive costs	$	0.088	$	0.087
Denaturant cost	0.051		0.050
Electricity cost	0.053		0.051
Direct labor cost	0.050		0.048

Revenue

For our 2013 fiscal year, ethanol sales comprised approximately 77% of our revenues, distillers grains sales comprised approximately 21% of our revenues and corn oil sales comprised approximately 2% of our revenues. For our 2012 fiscal year, ethanol sales comprised approximately 79% of our revenues, distillers grains sales comprised approximately 20% of our revenues and corn oil sales comprised approximately 1% of our revenues.

The average ethanol sales price we received for our 2013 fiscal year increased by approximately 6% when compared to the same period in 2012. Management attributes this increase in ethanol prices with higher energy prices generally, particularly during our first three quarters of 2013, along with less ethanol imports from Brazil during our 2013 fiscal year compared to the same period of 2012. Many fuel blenders purchased a significant amount of excess ethanol towards the end of 2011 in order to receive the VEETC blenders' credit before it expired on December 31, 2011, which resulted in excess ethanol supply during our 2012 fiscal year. Further, ethanol demand was lower during our 2012 fiscal year due to lower gasoline demand which negatively impacted ethanol prices during our 2012 fiscal year. Since ethanol is primarily blended with gasoline for sale in the United States, when domestic gasoline demand decreases, so does demand for ethanol. In addition, ethanol prices can be impacted by corn prices, with ethanol prices typically increasing when corn prices increase. However, this correlation is not always proportionate, so changing corn prices are not always offset by proportionate changes in ethanol prices. Management anticipates that ethanol prices will continue to be subject to influences from energy and corn prices. Further, ethanol prices could be significantly impacted if the ethanol use requirements associated with the RFS are decreased or eliminated.

The average price we received for our dried distillers grains increased by approximately 17% during our 2013 fiscal year compared to the same period of 2012. The average price we received for our modified distillers grains increased by approximately 22% during our 2013 fiscal year compared to the same period of 2012. The price of distillers grains typically changes in proportion to the market price of corn and is impacted by the relative availability of corn. During times when corn supplies are lower, as was the case during our 2013 fiscal year, distillers grains prices can approach and in some cases exceed the per ton price of corn. As corn prices increased and corn availability was lower during our 2013 fiscal year, we experienced a significant increase in distillers grains demand which positively impacted distillers grains prices. However, due to the fact that the corn crop harvested during the fall of 2013 was larger than in previous years, corn prices have decreased significantly and management anticipates corn prices will remain lower than in previous years in the near term. This has resulted in lower distillers grains prices recently which

18

management anticipates will continue into our 2014 fiscal year. However, if we experience increasing corn prices and lower corn availability during our 2014 fiscal year, either due to increased corn demand or concerns regarding the amount of corn that will be harvested in the fall of 2014, we may again experience increasing distillers grains demand and prices.

We had significantly more corn oil revenue during our 2013 fiscal year compared to the same period of 2012 due to increased corn oil production, partially offset by lower average corn oil prices. We produced nearly four times as many pounds of corn oil during our 2013 fiscal year compared to our 2012 fiscal year due to the fact that we operated our corn oil extraction equipment throughout our 2013 fiscal year and our equipment was only operational for a portion of our 2012 fiscal year. In addition, we have improved the efficiency with which we extract corn oil during our 2013 fiscal year which has improved our corn oil yield. We also increased our total production of ethanol during our 2013 fiscal year compared to the same period of 2012 which positively impacted the amount of corn oil we produced.

The average price we received for our corn oil was approximately 6% less during our 2013 fiscal year compared to the same period of 2012 due to increased corn oil supplies in the market and relatively flat corn oil demand. As more ethanol producers have started producing corn oil, the supply of corn oil in the market has increased which has negatively impacted corn oil prices. Further, demand for corn oil from the biodiesel industry has been less than the increase in corn oil supply which has resulted in a decrease in corn oil prices. Some industrial users of corn oil have increased purchases of corn oil due to its lower price compared to other vegetable oils, however, this increase in demand was not enough to increase market corn oil prices.

Cost of Good Sold

Our cost of goods sold was higher for our 2013 fiscal year compared to 2012 fiscal year primarily due to an increase in our corn and coal consumption due to our increased production and higher corn prices. The average price we paid per bushel of corn was approximately 4% greater for our 2013 fiscal year compared to our 2012 fiscal year due to higher market corn prices, particularly during our first three quarters of 2013. Management attributes this increase in corn prices during our 2013 fiscal year to drought conditions, both during 2012 and 2013, which resulted in decreased corn carryover and concerns regarding the quality and quantity of corn that would be harvested in the fall of 2013. However, as harvest approached in 2013, corn prices decreased due to higher corn production estimates and more favorable weather conditions. These factors have continued after the end of our 2013 fiscal year and we have experienced continued lower corn prices through harvest. Management anticipates that corn prices during our 2014 fiscal year will be lower than in previous years due to the amount of corn that was harvested in the fall of 2013. Management expects continued corn price volatility in the future in the event we continue to experience drought conditions and unfavorable corn production in the future.

We included a larger market price adjustment to our corn and ethanol inventory and forward contracts, which increased our cost of goods sold for our 2013 fiscal year compared to the same period of 2012. We had a loss on firm purchase commitments of $1,091,000 during our 2013 fiscal year compared to $132,000 during our 2012 fiscal year which resulted in a larger increase in our cost of goods sold during the 2013 period. We had a loss on our lower of cost or market adjustment for our inventory of $665,300 during our 2013 fiscal year compared to $327,000 during our 2012 fiscal year which resulted in a larger increase in our cost of goods sold during the 2013 period. In addition, we experienced a gain of approximately $779,000 on our corn derivative instruments which decreased our cost of goods sold during our 2013 fiscal year. We experienced a loss of approximately $451,000 on our corn derivative instruments which increased our cost of goods sold during our 2012 fiscal year.

In addition to the increase in corn prices, we consumed approximately 5% more bushels of corn during our 2013 fiscal year compared to our 2012 fiscal year due to increased production at the ethanol plant. Management anticipates relatively flat corn consumption during our 2014 fiscal year as we anticipate continued profitable operating margins which will allow us to operate the ethanol plant at a consistent level going forward.

Our cost of goods sold related to coal costs increased during our 2013 fiscal year compared to our 2012 fiscal year due to increased coal consumption, partially offset by lower average coal prices. We consumed approximately 18% more tons of coal during our 2013 fiscal year compared to our 2012 fiscal year because of increased production at our ethanol plant. In addition, the average price we paid per ton of coal purchase was approximately 9% lower during our 2013 fiscal year compared to our 2012 fiscal year due to higher shrinkage/physical adjustments made during the 2012 fiscal year. Management anticipates that coal prices will remain relatively stable during our 2014 fiscal year.

General and Administrative Expenses

Our general and administrative expenses as a percentage of revenues were lower for our 2013 fiscal year compared to our 2012 fiscal year due to a slight decrease in the total amount of our general and administrative expenses along with an increase in our total revenue during the period 2013. These percentages were approximately 1.4% and approximately 1.7% for our 2013

19

fiscal year and our 2012 fiscal year, respectively. Management expects our general and administrative expenses to be relatively stable during our 2014 fiscal year.

Other Income/Expense

Our interest income was higher during our 2013 fiscal year compared to our 2012 fiscal year due to having more accounts receivable from customers during the 2013 period. Our other income was significantly lower during our 2013 fiscal year compared to our 2012 fiscal year primarily due to a significant decrease in our grant income related to an alternative fuel tax credit. We had a comparable amount of interest expense during our 2013 fiscal year compared to our 2012 fiscal year due to the net effect of having less borrowing outstanding on our loans offset by higher interest rates.

Comparison of the Fiscal Year Ended September 30, 2012 to the Nine Month Transition Period Ended September 30, 2011

Change in Fiscal Year End

On January 1, 2011, our board of governors approved the change in our fiscal year end from December 31 to September 30, effective January 1, 2011. As a result of this change, this Annual Report on Form 10-K includes financial information for the nine-month transition period from January 1, 2011 to September 30, 2011 (the "Transition Period"). References in this Annual Report on Form 10-K to fiscal year 2012 or our 2012 fiscal year refer to the period from October 1, 2011 until September 30, 2012. References to the Transition Period refer to the nine-month period from January 1, 2011 to September 30, 2011.

The following table shows the results of our operations and the approximate percentage of revenues, costs of goods sold, general and administrative expenses and other items to total revenues in our statements of operations for the fiscal year ended September 30, 2012 and the Transition Period ended September 30, 2011:

	Fiscal Year Ended September 30, 2012					Transition Period Ended September 30, 2011
Statement of Operations Data	Amount			%		Amount		%
Revenues	$	131,458,769		100.00		$	112,290,222	100.00
Cost of Goods Sold	136,013,928			103.47		108,137,084		96.30
Gross Profit (Loss)	(4,555,159		)	(3.47	)	4,153,138		3.70
General and Administrative Expenses	2,224,351			1.69		1,972,679		1.76
Operating Income (Loss)	(6,779,510		)	(5.16	)	2,180,459		1.94
Other Income	2,081,535			1.58		1,671,836		1.49
Net Income (Loss)	$	(4,697,975	)	(3.58	)	$	3,852,295	3.43

20

The following table shows additional data regarding production and price levels for our primary inputs and products for the fiscal year ended September 30, 2012 and the Transition Period ended September 30, 2011:

	Fiscal Year Ended September 30, 2012		Transition Period Ended September 30, 2011
Production:
Ethanol sold (gallons)	47,340,485		37,327,103
Dried distillers grains sold (tons)	95,953		81,046
Modified distillers grains sold (tons)	71,729		40,329
Corn oil sold (pounds)	2,180,690		—
Revenues:
Ethanol average price/gallon (net of hedging)	$	2.18	$	2.52
Dried distillers grains price/ton	205.88		176.72
Modified distillers grains price/ton	99.82		91.46
Corn oil price/pound	0.33		—
Primary Input:
Corn ground (bushels)	17,672,456		13,285,113
Costs of Primary Input:
Corn avg price/bushel (net of hedging)	$	6.57	$	6.76
Other Costs (per gallon of ethanol sold):
Chemical and additive costs	$	0.087	$	0.093
Denaturant cost	0.050		0.053
Electricity cost	0.051		0.047
Direct labor cost	0.048		0.048

Revenue

In our fiscal year endedSeptember 30, 2012, ethanol sales comprised approximately 79% of our revenues, distillers grains sales comprised approximately 20% of our revenues and corn oil sales comprised approximately 1% of our revenues. For the transition period ended September 30, 2011, ethanol sales comprised approximately 84% of our revenues and distillers grains sales comprised approximately 16% of our revenues. We had no corn oil sales during the 2011 Transition Period. Our ethanol revenue as a percent of total revenues declined in 2012 primarily due to substantially more revenue we received from our sales of distillers grains due to higher corn prices which positively impacted distillers grains demand and prices. We also experienced lower average ethanol prices during the 2012 period which decreased the percentage of our total revenue attributed to ethanol sales.

The average ethanol sales price we received for the fiscal year endedSeptember 30, 2012 decreased by approximately 13% when compared to the transition period ended September 30, 2011. Management attributes this decrease in ethanol prices with excess ethanol supply during the 2012 period which led to higher ethanol stocks. Many fuel blenders purchased a significant amount of excess ethanol during the fourth quarter of 2011 in order to receive the VEETC blenders' credit before it expired on December 31, 2011. Further, management attributes this decrease in ethanol prices to lower ethanol demand which resulted from lower gasoline demand during 2012.

The price we received for our dried distillers grains increased by approximately 16% during the fiscal year endedSeptember 30, 2012 compared to the transition period ended September 30, 2011. The price we received for our modified distillers grains increased by approximately 9% during our fiscal year endedSeptember 30, 2012 compared to the transition period ended September 30, 2011. For the fiscal year endedSeptember 30, 2012, this increase was not proportionate as our average price of corn, when compared to the transition period ended September 30, 2011, actually decreased. This was primarily due to strong demand for distillers grains.

We had corn oil revenue during our 2012 fiscal year which supplemented our revenue and we had no corn oil revenue during our 2011 Transition Period.

21

We sold more gallons of ethanol and more tons of distillers grains during our 2012 fiscal year compared to our 2011 Transition Period, primarily due to the fact that the 2012 period included an entire 12 months of operations while the 2011 Transition Period only included 9 months of operations.

Cost of Good Sold

Our cost of goods sold was higher for our fiscal year ended September 30, 2012 compared to our 2011 Transition Period primarily because we had an entire 12 months of operations during the 2012 period compared to 9 months of operations for the 2011Transition Period. We ground approximately 33% more bushels of corn during the 2012 period compared to the 2011 Transition Period. Offsetting this increase in our corn consumption was a decrease of approximately 3% in the average price we paid per bushel of corn, net of our hedging instruments, during our 2012 fiscal year compared to our 2011 Transition Period.

General and Administrative Expenses

Our general and administrative expenses as a percentage of revenues were lower for our fiscal year ended September 30, 2012 than they were for our Transition Period ended September 30, 2011. These percentages were approximately 1.7% and approximately 1.8% for our fiscal year ended September 30, 2012 and our Transition Period ended September 30, 2011, respectively. Our general and administrative expenses were higher during the 2012 period due to the fact that it included an entire 12 months of operations compared to the 9 months of operations included in our 2011 Transition Period. The relative decrease, on a percentage basis, of our general and administrative expenses during the 2012 period compared to our 2011 Transition Period was due to decreased management fees due to expiration of our management agreement with Greenway Consulting.

Other Income/Expense

Our interest income was higher during our 2012 fiscal year due to the fact that it included an entire 12 months of operations compared to 9 months during the 2011 Transition Period. Our other income was lower during our 2012 fiscal year compared to our 2011Transition Period primarily due to expiration in December 2011 of an alternative fuel tax credit. We had less interest expense during our 2012 fiscal year compared to our 2011 Transition Period due to a combination of having less debt outstanding and lower interest rates during the 2012 period compared to the 2011 Transition Period.

Changes in Financial Condition for the Fiscal Year Ended September 30, 2013 and 2012

Current Assets. Our accounts receivable was higher at September 30, 2013 compared to September 30, 2012 primarily due to higher prices for our products resulting in a higher receivable balance with RPMG. The value of our inventory was lower at September 30, 2013 compared to September 30, 2012 primarily due to significantly lower finished goods inventory which resulted from timing of shipments at our 2013 fiscal year end.

Property, Plant and Equipment. The gross value of our property, plant and equipment was higher at September 30, 2013 compared to September 30, 2012 primarily due to capital improvement projects completed during our annual maintenance shutdown. The net value of our property, plant and equipment was lower at September 30, 2013 compared to September 30, 2012 due to depreciation.

Other Assets. Our other assets were higher at September 30, 2013 compared to September 30, 2012 primarily due to an increase in our cooperative patronage equity associated with our electricity provider at September 30, 2013 compared to September 30, 2012.

Current Liabilities. Our current liabilities were lower at September 30, 2013 compared to September 30, 2012, primarily due to a significant decrease in our accrued expenses related to fewer basis and price later contracts. A significant percentage of basis and price later contracts were priced in July and August to be paid in September and October. We had more disbursements outstanding in excess of our bank balances at September 30, 2013 compared to September 30, 2012 due to the accounts payable that was due to our vendors. Amounts that are outstanding in excess of our bank balances are paid from our revolving loan when the checks are presented for payment. Our accounts payable was higher at September 30, 2013 compared to September 30, 2012 primarily due to the later timing of our maintenance shutdown. Payments for some expenses incurred during the shutdown were made at the beginning of October. Also, regular chemical purchases were made later as a result of the shutdown, increasing our accounts payable to our chemical vendors.

Long-term Liabilities. Our long-term liabilities were lower at September 30, 2013 compared to September 30, 2012, primarily due to periodic payments we make on our long-term debt with FNBO. We had a long-term liability of $275,000 at both

22

September 30, 2013 and September 30, 2012 related to repayment of a grant from the State of North Dakota. No time line has been established for the repayment of this grant.

Application of Critical Accounting Estimates

Management uses estimates and assumptions in preparing our financial statements in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Of the significant accounting policies described in the notes to our financial statements, we believe that the following are the most critical.

Inventory Valuation

The Company values inventory at the lower of cost or market.  Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable.  These valuations require the use of management's assumptions which do not reflect unanticipated events and circumstances that may occur.  In our analysis, we consider future corn costs and ethanol prices, break-even points for our plant and our risk management strategies in place through our derivative instruments. 

Patronage Equity

The Company receives, from certain vendors organized as cooperatives, patronage dividends, which are based on several criteria, including the vendor's overall profitability and the Company's purchases from the vendor. Patronage equity typically represents the Company's share of the vendor's undistributed current earnings which will be paid in either cash or equity interests to the Company at a future date. Investments in cooperatives are stated at cost, plus unredeemed patronage refunds received in the form of capital stock and are included in Other Assets on the Company's balance sheet.

Firm Purchase Commitments

The Company typically enters into fixed price contracts to purchase corn to ensure an adequate supply of corn to operate its plant. The Company will generally seek to use exchange traded futures, options or swaps as an offsetting position. The Company closely monitors the number of bushels hedged using this strategy to avoid an unacceptable level of margin exposure. Contract prices are analyzed by management at each period end and, if necessary, valued at the lower of cost or market in the balance sheets.

Long Lived Assets

The Company reviews 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. 

Property, plant, and equipment are stated at cost. Depreciation is provided over estimated useful lives by use of the straight line method. Maintenance and repairs are expensed as incurred. Major improvements and betterments are capitalized. The present values of capital lease obligations are classified as long-term debt and the related assets are included in property, plant and equipment. Amortization of equipment under capital leases is included in depreciation expense.

Derivative Instruments

The Company evaluates its contracts to determine whether the contracts are derivative instruments. Certain contracts that literally meet the definition of a derivative may be exempted from derivative accounting and treated as normal purchases or normal sales if documented as such. 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.

The Company enters into short-term cash, option and futures contracts as a means of securing corn for the ethanol plant and managing exposure to changes in commodity prices. All of the Company's derivatives are designated as non-hedge derivatives, with changes in fair value recognized in net income. Although the contracts are economic hedges of specified risks, they are not designated as and accounted for as hedging instruments.

23

As part of its trading activity, the Company uses futures and option contracts through regulated commodity exchanges to manage its risk related to pricing of inventories. To reduce that risk, the Company generally takes positions using cash and futures contracts and options.

Realized and unrealized gains and losses related to derivative contracts related to corn are included as a component of cost of goods sold and derivative contracts related to ethanol are included as a component of revenues in the accompanying financial statements. The fair values of contracts entered through commodity exchanges are presented on the accompanying balance sheet as derivative instruments.

Liquidity and Capital Resources

Our primary sources of liquidity are cash from our operations and amounts that we can draw on our lines of credit with our primary lender, FNBO. Based on financial forecasts performed by our management, we anticipate that we will have sufficient cash from our current credit facilities and cash from our operations to continue to operate the ethanol plant for the next 12 months. Should we experience unfavorable operating conditions in the future, we may have to secure additional debt or equity sources for working capital or other purposes.

The following table shows cash flows for the fiscal years ended September 30, 2013 and 2012:

	2013			2012
Net cash provided by (used in) operating activities	$	2,744,252		$	(198,828	)
Net cash used in investing activities	(838,549		)	(3,233,449		)
Net cash used in financing activities	(1,905,703		)	(1,239,720		)
Net decrease in cash	$	—		$	(4,671,997	)
Cash and cash equivalents, end of period	$	1,000		$	1,000

Cash Flow from Operations

Our operations provided cash during our 2013 fiscal year, whereas our operations used cash during our 2012 fiscal year. We had a significant net loss during our 2012 fiscal year compared to positive net income during our 2013 fiscal year. We also had a significant decrease in our accounts payable during the 2013 period which decreased the cash generated by our operating activities.

Cash Flow from Investing Activities

We used less cash for investing activities during our 2013 fiscal year compared to our 2012 fiscal year due to having fewer capital expenditures in 2013. We installed our corn oil extraction equipment during our 2012 fiscal year and had only smaller capital projects during our 2013 fiscal year, including our scrubber project and centrifuge improvements. We sold a residence adjacent to the ethanol plant during our 2013 fiscal year which provided cash from our investing activities.

Cash Flow from Financing Activities

We used more cash for financing activities during our 2013 fiscal year compared to our 2012 fiscal year due to an increase in our disbursements in excess of our bank balances which are paid from our lines-of-credit. We had a comparable amount of repayments on our credit facilities with FNBO during both our 2013 fiscal year and our 2012 fiscal year.

Our liquidity, results of operations and financial performance will be impacted by many variables, including the market price for commodities such as, but not limited to, corn, ethanol and other energy commodities, as well as the market price for any co-products generated by the facility and the cost of labor and other operating costs.  Assuming future relative price levels for corn, ethanol and distillers grains remain consistent, we expect operations to generate adequate cash flows to maintain operations.

24

The following table shows cash flows for the fiscal year ended September 30, 2012 and for the Transition Period ended September 30, 2011:

	2012			2,011
Net cash used in operating activities	$	(198,828	)	$	(835,836	)
Net cash used in investing activities	(3,233,449		)	(797,378		)
Net cash used for financing activities	(1,239,720		)	(3,497,355		)
Net decrease in cash	$	(4,671,997	)	$	(5,130,569	)
Cash and cash equivalents, end of period	$	1,000		$	4,672,997

Cash Flow from Operations

Our cash used in operations was lower during our fiscal year ended 2012 compared to the Transition Period ended September 30, 2011 due to changes in our accounts receivable, other receivables, inventory and accrued expenses which benefited our cash flow during the 2012 period. This effect was offset by our net loss during the 2012 period compared to net income during the 2011 Transition Period.

Cash Flow from Investing Activities

We used more cash for investing activities during the fiscal year ended September 30, 2012 compared to the Transition Period ended September 30, 2011 due primarily to our installation of the water filtration project, the purchase of employee housing and land, placing our corn oil extraction system in service, updating our process server and installing new bin sweeps. During the Transition Period ended September 30, 2011, we primarily used cash for investing activities related to capital expenditures we made to institute our alternative fuel burning project.

Cash Flow from Financing Activities

We used less cash for financing activities during the fiscal year ended September 30, 2012 as compared to the Transition Period ended September 30, 2011 primarily due to increased borrowings on our lines-of-credit during the 2012 period and an increase in our disbursements in excess of our bank balances which are paid from our lines-of-credit. These receipts were offset by payments we made on our long-term debt during the 2012 period. In addition to our scheduled amortizing bank debt payments, we made an additional principal payment on our bank debt of $3,300,000 during the 2012 period and also made a principal payment of $1,525,000 in 2012 on our subordinated debt.

Capital Resources

We have a comprehensive credit agreement with our primary lender, First National Bank of Omaha (FNBO). We currently have three loans outstanding with FNBO, a long-term loan (the "Term Note"), a long-term revolving loan (the "Long-Term Revolving Note") and an operating line-of-credit (the "Operating Line-of-Credit"). The principal balances, interest rates and other material terms of these loans are described below.

Short-Term Debt Sources

As of September 30, 2013, the maximum principal amount available on the Operating Line-of-Credit was $10,000,000, of which, we had drawn $0 as of September 30, 2013. Interest on the Operating Line-of-Credit accrues at 3.5% over the one-month London Interbank Offered Rate (LIBOR), reset monthly. Interest on the Operating Line-of-Credit accrued at an annual rate of 3.68% as of September 30, 2013. The maturity date of the Operating Line-of-Credit is April 15, 2014.

Long-Term Debt Sources

As of September 30, 2013, the maximum principal amount available on the Long-Term Revolving Note was $3,750,000, of which, we had drawn $3,708,000 as of September 30, 2013. Interest on the Long-Term Revolving Note accrued at an annual rate of 3.77% as of September 30, 2013. The variable interest rate on the Long-Term Revolving Note is 3.5% over the three-month LIBOR, reset monthly. The available balance of the Long-Term Revolving Note decreases by $125,000 quarterly. The maturity date of the Long-Term Revolving Loan is April 16, 2017.

25

As of September 30, 2013, the balance due on the Term Note was $17,000,000. Interest on the Term Note accrued at an annual rate of 3.77% as of September 30, 2013. The variable interest rate on the Term Note is 3.5% over the three-month LIBOR, reset monthly. Principal payments of $500,000 are due on the Term Note quarterly. The maturity date of the Term Note is April 16, 2017.

The following table summarizes our long-term debt instruments with FNBO.

	Outstanding Balance (Millions)		Interest Rate				Range of  Estimated
Term Note	September 30, 2013	September 30, 2012	September 30, 2013		September 30, 2012		Quarterly  Principal Payment Amounts	Notes
Term Note	17.00	19.00	3.77	%	3.93	%	$500,000	1, 2
Long-Term Revolving Note	3.71	4.75	3.77	%	3.93	%	$125,000	1, 2, 3

Notes

1 - Maturity date of April 2017.

2 - Variable interest rate at 3.5% over the three-month LIBOR, reset quarterly.

3 - Quarterly payments are equal to required quarterly reductions in total available/principal payments of $125,000.

Restrictive Covenants

We are subject to a number of covenants and restrictions in connection with our credit facilities, including:

• Providing FNBO with current and accurate financial statements;

• Maintaining certain financial ratios including minimum working capital and fixed charge coverage ratio;

• Maintaining adequate insurance;

• Making, or allowing to be made, any significant change in our business or tax structure;

• Limiting our ability to make distributions to members; and

• Maintaining a threshold of capital expenditures.

As of September 30, 2013, we were in compliance with our loan covenants with FNBO.

Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of September 30, 2013:

Contractual Obligations:	Total		Less than 1 Yr		1-3 Years		3-5 Years		More than 5 Yrs
Long-term debt obligations *	$	23,523,229	$	3,674,877	$	6,217,068	$	13,631,284	$	—
Corn Purchases **	8,822,845		8,822,845		—		—		—
Water purchases	1,060,000		424,000		636,000		—		—
Operating lease obligations	1,563,138		489,913		593,065		345,760		134,400
Capital leases	78,258		28,977		49,281		—		—
Total	$	35,047,470	$	13,440,612	$	7,495,414	$	13,977,044	$	134,400

* - We used the variable interest rates in effect as of September 30, 2013 (see Note 5 to our audited financial statements)

** - Amounts determined assuming prices, including freight costs, at which corn had been contracted for cash corn contracts and current market prices as of September 30, 2013 for basis contracts that had not yet been fixed.

Industry Support

North Dakota Grant

In 2006, we entered into a contract with the State of North Dakota through the Industrial Commission for a lignite coal grant not to exceed $350,000. We received $275,000 from this grant during 2006 with this amount currently shown in the long-term liability section of our Balance Sheet as Contracts Payable. Because we have not met the minimum lignite usage requirements

26

specified in the grant for any year in which the ethanol plant has operated, we expect to have to repay the grant and are awaiting instructions from the Industrial Commission as to the terms of the repayment schedule. This repayment could begin at some point during our 2014 fiscal year, but as of September 30, 2013, we have not received any instructions from the Industrial Commission.

Off-Balance Sheet Arrangements

We occasionally enter into operating lease obligations which would be considered off-balance sheet financing as the lease payments are expensed over the term of the operating lease and no liability is recorded on the balance sheet. These operating lease obligations are presented in the contractual obligation table above and are not a material component of our total contractual obligations and commitments.

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 Generally Accepted Accounting Principles ("GAAP"). 

Commodity Price Risk

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

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

Although we believe our hedge positions will accomplish an economic hedge against our future purchases, they are not designated as hedges for accounting purposes, which would match the gain or loss on our hedge positions to the specific commodity purchase being hedged.  We use fair value accounting for our hedge positions, which means as the current market price of our hedge positions changes, the gains and losses are immediately recognized in our cost of sales.  The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter and year to year due to the timing of the change in value of derivative instruments relative to the cost of the commodity being hedged.  However, it is likely that commodity cash prices will have the greatest impact on the derivatives instruments with delivery dates nearest the current cash price.

At September 30, 2013, the Company had various fixed price contracts for the purchase of approximately 1.3 million bushels of corn. Using the stated contract price for the fixed price contracts, the Company had commitments of approximately $6.4 million related to the 1.3 million bushels under contract. The Company also enters into fixed basis contracts with the actual price set by the supplier at a future date. Using current market prices, if these basis contracts were fixed at September 30, 2013, the Company would have commitments of approximately $2,500,000.   

It is the current position of our ethanol marketing company, RPMG, that under current market conditions selling ethanol in the spot market will yield the best price for our ethanol.  RPMG will, from time to time, contract a portion of the gallons they market with fixed price contracts.  

We estimate that our expected corn usage will be between 18 million and 20 million bushels per calendar year for the production of approximately 50 million to 54 million gallons of ethanol.  As corn prices move in reaction to market trends and information, our income statements will be affected depending on the impact such market movements have on the value of our derivative instruments.

To manage our coal price risk, we entered into a coal purchase agreement with our supplier to supply us with coal, fixing the price at which we purchase coal. If we are unable to continue buying coal under this agreement, we may have to buy coal in the open market.

27

Interest Rate Risk

We are exposed to market risk from changes in interest rates from holding term debt and revolving lines of credit which bear variable interest rates. As of September 30, 2013, we had $20,708,000 outstanding on variable interest debt which accrued interest at a rate of 3.77% per year. We anticipate that a hypothetical 1% change in the interest rate on our variable rate debt, from the rate in effect on September 30, 2013, would cause an adverse change to our income in the amount of approximately $207,000.

28

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Governors

Red Trail Energy, LLC

Richardton, North Dakota

We have audited the accompanying balance sheets of Red Trail Energy, LLC as of September 30, 2013 and 2012 and the related statements of operations, changes in members' equity, and cash flows for the twelve-month periods ended September 30, 2013 and 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC as of September 30, 2013 and 2012, and the results of their operations and their cash flows for the twelve-month periods ended September 30, 2013 and 2012 in conformity with U.S. generally accepted accounting principles.

Fargo North Dakota

December 16, 2013

29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Governors

Red Trail Energy, LLC

Richardton, North Dakota

We have audited the accompanying balance sheet of Red Trail Energy, LLC as of September 30, 2011, and the related statements of operations, changes in members’ equity, and cash flows for the nine-month period ended September 30, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC as of September 30, 2011, and the results of their operations and their cash flows for the nine months ended September 30, 2011 in conformity with U.S. generally accepted accounting principles.

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

Minneapolis, Minnesota

December 13, 2011

30

RED TRAIL ENERGY, LLC

Balance Sheets

ASSETS	September 30, 2013		September 30, 2012
Current Assets
Cash and equivalents	$	1,000	$	1,000
Restricted cash	153,210		6,904
Accounts receivable, primarily related party	4,048,686		3,750,301
Other receivables	42,472		40,069
Commodities derivative instruments, at fair value	—		180,110
Inventory	12,189,693		13,650,907
Prepaid expenses	76,428		87,523
Total current assets	16,511,489		17,716,814
Property, Plant and Equipment
Land	836,428		833,131
Land improvements	4,127,372		4,127,372
Buildings	5,492,612		5,634,430
Plant and equipment	77,660,841		76,696,675
Construction in progress	25,885		25,885
	88,143,138		87,317,493
Less accumulated depreciation	35,949,952		31,945,268
Net property, plant and equipment	52,193,186		55,372,225
Other Assets
Debt issuance costs, net of amortization	64,046		70,751
Investment in RPMG	605,000		605,000
Patronage equity	2,325,640		1,943,226
Deposits	41,500		40,150
Total other assets	3,036,186		2,659,127
Total Assets	$	71,740,861	$	75,748,166

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

31

RED TRAIL ENERGY, LLC

Balance Sheets

LIABILITIES AND MEMBERS' EQUITY	September 30, 2013		September 30, 2012
Current Liabilities
Disbursements in excess of bank balances	$	3,126,883	$	1,728,931
Accounts payable	3,577,647		1,354,988
Accrued expenses	1,052,314		6,273,695
Commodities derivative instruments, at fair value	48,638		—
Accrued loss on firm purchase commitments	203,000		—
Short-term borrowings	—		242,000
Current maturities of long-term debt	2,949,977		2,584,429
Total current liabilities	10,958,459		12,184,043
Long-Term Liabilities
Notes payable	17,836,281		21,252,164
Contracts payable	275,000		275,000
Total long-term liabilities	18,111,281		21,527,164
Commitments and Contingencies (Note 10)
Members’ Equity	42,671,121		42,036,959
Total Liabilities and Members’ Equity	$	71,740,861	$	75,748,166

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

32

RED TRAIL ENERGY, LLC

Statements of Operations

	Twelve-Month			Twelve-Month			Nine Month
	Period Ended			Period Ended			Transition Period Ended
	September 30, 2013			September 30, 2012			September 30, 2011
Revenues, primarily related party	$	154,790,603		$	131,458,769		$	112,290,222
Cost of Goods Sold
Cost of goods sold	149,831,987			135,554,928			107,243,084
Lower of cost or market inventory adjustment	665,300			327,000			450,000
Loss on firm purchase commitments	1,091,000			132,000			444,000
Total Cost of Goods Sold	151,588,287			136,013,928			108,137,084
Gross Profit (Loss)	3,202,316			(4,555,159		)	4,153,138
General and Administrative Expenses	2,145,733			2,224,351			1,972,679
Operating Income (Loss)	1,056,583			(6,779,510		)	2,180,459
Other Income (Expense)
Interest income	61,780			55,647			43,259
Other income	456,859			2,960,920			3,225,574
Interest expense	(941,059		)	(935,032		)	(1,596,997		)
Total other income (expense), net	(422,420		)	2,081,535			1,671,836
Net Income (Loss)	$	634,163		$	(4,697,975	)	$	3,852,295
Weighted Average Units Outstanding
Basic	40,151,941			40,204,971			40,193,973
Diluted	40,153,201			40,217,471			40,213,973
Net Income (Loss) Per Unit
Basic	$	0.02		$	(0.12	)	$	0.10
Diluted	$	0.02		$	(0.12	)	$	0.10

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

33

RED TRAIL ENERGY, LLC

Statements of Changes in Members' Equity

Twelve-Month Periods Ended September 30, 2013 and 2012

Nine-Month Transition Period Ended September 30, 2011

	Class A Member Units										Treasury Units
	Units (a)		Amount		Additional Paid in Capital			Accumulated Deficit/Retained Earnings			Units		Amount			Total Member Equity
Balance - December 31, 2010	40,193,973		37,810,408		56,825			5,242,043			180,000		(205,140		)	42,904,136
Unit-based compensation	—		—		20,000			—			—		—			20,000
Net Income	—		—		—			3,852,295			—		—			3,852,295
Balance - September 30, 2011	40,193,973		37,810,408		76,825			9,094,338			180,000		(205,140		)	46,776,431
Unit-based compensation	20,000		—		(12,800		)	—			(20,000	)	22,800			10,000
Units repurchased	(35,813	)	—		(29,800		)	—			35,813		(21,697		)	(51,497		)
Net Income (Loss)	—		—		—			(4,697,975		)	—		—			(4,697,975		)
Balance - September 30, 2012	40,178,160		37,810,408		34,225			4,396,363			195,813		(204,037)			42,036,959
Unit-based compensation	20,000		—		(22,800		)	—			(20,000	)	22,800			—
Units repurchased	(50,000	)	—		29,800			—			50,000		(29,800		)	—
Net Income (Loss)	—		—		—			634,163			—		—			634,163
Balance - September 30, 2013	40,148,160		$	37,810,408	$	41,225		$	5,030,526		225,813		$	(211,037	)	$	42,671,122
(a) - Amounts shown represent member units outstanding.

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

34

RED TRAIL ENERGY, LLC

Statements of Cash Flows

	Twelve-Month			Twelve-Month			Nine Month Transition
	Period Ended			Period Ended			Period Ended
	September 30, 2013			September 30, 2012			September 30, 2011
Cash Flows from Operating Activities
Net income (loss)	$	634,163		$	(4,697,975	)	3,852,295
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	4,057,965			4,304,071			4,448,266
Loss (gain) on disposal of fixed assets	(22,353		)	490			—
Change in fair value of derivative instruments	228,748			(201,173		)	102,825
Equity-based compensation	—			10,000			20,000
Lower of cost or market inventory adjustment	665,300			327,000			450,000
Loss on firm purchase commitments	1,091,000			132,000			444,000
Noncash patronage equity	(382,415		)	(1,217,566		)	(282,851	)
Change in operating assets and liabilities:
Restricted cash - commodities derivatives account including settlements	(146,306		)	(6,904		)	578,359
Accounts receivable	(298,385		)	2,554,108			(1,806,308	)
Other receivables	(2,403		)	1,480,628			(1,386,498	)
Inventory	(295,085		)	(2,450,044		)	(5,713,339	)
Prepaid expenses and deposits	11,095			72,582			(222,766	)
Other assets	(1,350		)	—			—
Accounts payable and accrued expenses	(2,998,722		)	765,842			(388,220	)
Accrued purchase commitment losses	203,000			(444,000		)	—
Cash settlements on interest rate swap	—			(827,887		)	(931,599	)
Net cash provided by (used in) operating activities	2,744,252			(198,828		)	(835,836	)
Cash Flows from Investing Activities
Proceeds from disposal of fixed assets	160,950			—			—
Capital expenditures	(999,499		)	(3,233,449		)	(797,378	)
Net cash used in investing activities	(838,549		)	(3,233,449		)	(797,378	)
Cash Flows from Financing Activities
Disbursements in excess of bank balances	1,397,952			1,728,931			—
Restricted cash	—			—			750,000
Unit repurchases	—			(51,497		)	—
Loan fees	(11,321		)	(77,891		)	—
Net advances on revolving lines-of-credit	(909,000		)	4,992,000			—
Debt repayments	(2,383,334		)	(7,831,263		)	(4,247,355	)
Net cash used in financing activities	(1,905,703		)	(1,239,720		)	(3,497,355	)
Net Increase (Decrease) in Cash and Equivalents	—			(4,671,997		)	(5,130,569	)
Cash and Equivalents - Beginning of Period	1,000			4,672,997			9,803,566
Cash and Equivalents - End of Period	$	1,000		$	1,000		4,672,997
Supplemental Disclosure of Cash Flow Information
Interest paid net of swap settlements	$	954,575		$	1,493,420		1,410,604
Noncash Investing and Financing Activities
Assets acquired under capital lease	$	81,160		$	—		470,241
Capital expenditures in accounts payable	$	—		$	—		53,448

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

35

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Red Trail Energy, LLC, a North Dakota limited liability company (the “Company”), owns and operates a 50 million gallon annual name-plate production ethanol plant near Richardton, North Dakota (the “Plant”). The plant commenced production on January 1, 2007. Fuel grade ethanol, distillers grains and corn oil are the Company's primary products. All products are marketed and sold primarily within the continental United States.

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. Significant items subject to such estimates and assumptions include the useful lives of property, plant and equipment, valuation of derivatives, inventory, and purchase commitments; the analysis of long-lived assets impairment and other contingencies. Actual results could differ from those estimates.

Cash and Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The carrying value of cash and equivalents approximates fair value.

Accounts Receivable and Concentration of Credit Risk

The Company generates accounts receivable from sales of ethanol, distillers grains and corn oil. The Company has entered into agreements with RPMG, Inc. (“RPMG”) and CHS, Inc. (“CHS”) for the marketing and distribution of the Company's ethanol, corn oil and dried distiller's grains, respectively. Under the terms of the marketing agreements, both RPMG and CHS bear the risk of loss of nonpayment by their customers. The Company markets its modified distiller's grains internally. Following the end of the Company's 2013 fiscal year, RPMG markets the Company's dried distillers grains.

For sales of modified distiller's grains, credit is extended based on evaluation of a customer's financial condition and collateral is not required. Accounts receivable are due 30 days from the invoice date. Accounts outstanding longer than the contractual payment terms are considered past due. Internal follow up procedures are followed accordingly. Interest is charged on past due accounts.

All receivables are stated at amounts due from customers net of any allowance for doubtful accounts. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company's previous loss history, the customer's perceived current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. The Company has an allowance for doubtful accounts of approximately $106,800 and $1,500 at September 30, 2013 and 2012, respectively.

Inventory

Corn is the primary raw material and, along with other raw materials and supplies, is stated at the lower of cost or market on a first-in, first-out (FIFO) basis.  Work in process and finished goods, which consists of ethanol, distillers grains and corn oil produced, is stated at the lower of average cost or market.  Spare parts inventory is valued at lower of cost or market on a FIFO basis.

Patronage Equity

The Company receives, from certain vendors organized as cooperatives, patronage dividends, which are based on several criteria, including the vendor's overall profitability and the Company's purchases from the vendor. Patronage equity typically represents the Company's share of the vendor's undistributed current earnings which will be paid in either cash or equity interests to the Company at a future date. Investments in cooperatives are stated at cost, plus unredeemed patronage refunds received in the form of capital stock and are included in Other Assets on the Company's balance sheet.

36

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Derivative Instruments

The Company enters into derivative transactions to hedge its exposure to commodity and interest rate price fluctuations. The Company is required to record these derivatives in the balance sheet at fair value.

In order for a derivative to qualify as a hedge, specific criteria must be met and appropriate documentation maintained. Gains and losses from derivatives that do not qualify as hedges, or are undesignated, must be recognized immediately in earnings. 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. Changes in the fair value of undesignated derivatives related to corn are recorded in costs of goods sold within the statements of operations. Changes in the fair value of undesignated derivatives related to ethanol are recorded in revenue within the statements of operations. Changes of fair value of undesignated interest rate swaps are recorded in interest expense within the statement of operations.

Additionally the Company is required to evaluate 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 distiller's grain 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.

Firm Purchase Commitments

The Company typically enters into fixed price contracts to purchase corn to ensure an adequate supply of corn to operate its plant. The Company will generally seek to use exchange traded futures, options or swaps as an offsetting economic hedge position. The Company closely monitors the number of bushels hedged using this strategy to avoid an unacceptable level of margin exposure. Contract prices are analyzed by management at each period end and, if necessary, valued at the lower of cost or market in the balance sheets.

Revenue Recognition

The Company generally sells ethanol and related products pursuant to marketing agreements. Revenues are recognized when the customer has taken title, which occurs when the product is shipped, has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues are shown net of any fees incurred under the terms of the Company's agreements for the marketing and sale of ethanol and related products.

Long-lived Assets

Property, plant, and equipment are stated at cost. Depreciation is provided over estimated useful lives by use of the straight line method. Maintenance and repairs are expensed as incurred. Major improvements and betterments are capitalized. The present values of capital lease obligations are classified as long-term debt and the related assets are included in property, plant and equipment. Amortization of equipment under capital leases is included in depreciation expense.

Depreciation is computed using the straight-line method over the following estimated useful lives:

	Minimum Years	Maximum Years
Land improvements	15	30
Buildings	10	40
Plant and equipment	7	40

37

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Long-lived assets, such as property, plant, and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 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, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including, but not limited to, discounted cash flow models, quoted market values and third-party independent appraisals.

Fair Value of Financial Instruments

The Company has 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 financial statements on a recurring basis. The Company has 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 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

·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 fiscal years ended September 30, 2013 and 2012 that required adjustment to the recognized balances of assets or liabilities, which are recorded at fair value on a nonrecurring basis.

Grants

The Company recognizes grant proceeds as other income for reimbursement of expenses incurred upon complying with the conditions of the grant. For reimbursements of capital expenditures, the grants are recognized as a reduction of the basis of the asset upon complying with the conditions of the grant. In addition, the Company considers production incentive payments received to be economic grants and includes such amounts in other income when received, as this represents the point at which they are fixed and determinable.

Shipping and Handling

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

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.

38

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Differences between financial statement basis of assets and tax basis of assets is primarily related to depreciation, interest rate swaps, derivatives, inventory, compensation and capitalization and amortization of organization and start-up costs for tax purposes, whereas these costs are expensed for financial statement purposes.

The Company has evaluated whether it has any significant tax uncertainties that would require recognition or disclosure. Primarily due to its partnership tax status, the Company does not have any significant tax uncertainties that would require recognition or disclosure.

The Company files income tax returns in the U.S. federal jurisdiction and various states. The Company is no longer subject to income tax examinations by U.S. federal tax authorities or the states where the Company files tax returns for tax years ended on or prior to December 31, 2009.

Net Income (Loss) Per Unit

Net income (loss) per unit is calculated on a basic and fully diluted basis using the weighted average units outstanding during the period.

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, if any, are recorded when the liability is probable and the costs can reasonably be estimated. The Company is not aware of any environmental liabilities identified as of September 30, 2013.

2. CONCENTRATIONS

Coal

Coal is an important input to our manufacturing process. During the fiscal year ended September 30, 2013, we used approximately 83,000 tons of coal. We have entered into a one year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through December 2013 and the Company does not anticipate any problems negotiating a renewal of this contract. The Company's intentions are to renew this supply agreement with its current coal supplier. We believe there is sufficient supply of coal from the PRB coal regions in Wyoming and Montana to meet our demand for PRB coal. In addition to coal, we could use natural gas as a fuel source if our coal supply is significantly interrupted. Because we are already operating on coal, we do not expect to need natural gas unless coal interruptions impact our operations.

Sales

We are substantially dependent upon RPMG for the purchase, marketing and distribution of our ethanol and corn oil. RPMG purchases 100% of the ethanol and corn oil produced at our plant, all of which is marketed and distributed to its customers. Therefore, we are highly dependent on RPMG for the successful marketing of our ethanol and corn oil. In the event that our relationship with RPMG is interrupted or terminated for any reason, we believe that we could locate another entity to market the ethanol and corn oil. However, any interruption or termination of this relationship could temporarily disrupt the sale and production of ethanol and corn oil and adversely affect our business and operations and potentially result in a higher cost to the Company. Amounts due from RPMG represent approximately 80% and 69% of the Company's outstanding trade receivables balance at September 30, 2013 and 2012, respectively. Approximately 79%, 79%, and 84% of revenues are comprised of sales to RPMG for the year ended September 30, 2013, the year ended September 30, 2012 and the nine months ended September 30, 2011, respectively.

During our 2013 fiscal year, we were substantially dependent on CHS for the purchase, marketing and distribution of our DDGS. CHS purchased 100% of the DDGS produced at the plant during our 2013 fiscal year, all of which are marketed and distributed to its customers. Effective as of October 1, 2013, RPMG will purchase 100% of the DDGS produced at the plant to market and

39

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

distribute to its customers. Therefore, we are highly dependent on RPMG for the successful marketing of our DDGS. In the event that our relationship with RPMG is interrupted or terminated for any reason, we believe that another company could be engaged to market the DDGS. However, any interruption or termination of this relationship could temporarily disrupt the sale and production of DDGS and adversely affect our business and operations.

3. DERIVATIVE INSTRUMENTS

Commodity Contracts

As part of its hedging strategy, the Company may enter into ethanol, soybean oil, and corn commodity-based derivatives in order to protect cash flows from fluctuations caused by volatility in commodity prices in order to protect gross profit margins from potentially adverse effects of market and price volatility on ethanol sales, corn oil sales, and corn purchase commitments where the prices are set at a future date. These derivatives 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. Ethanol derivative fair market value gains or losses are included in the results of operations and are classified as revenue and corn derivative changes in fair market value are included in cost of goods sold.

As of:	September 30, 2013						September 30, 2012
Contract Type	# of Contracts	Notional Amount (Qty)		Fair Value			# of Contracts	Notional Amount (Qty)		Fair Value
Corn options	—	—	bushels	$	—		400	2,000,000	bushels	$	173,750
Soybean oil futures	—	—	pounds	$	—		10	600,000	pounds	$	6,360
Corn futures	80	400,000	bushels	$	(48,638	)	—	—	—	$	—
Total fair value				$	(48,638	)				$	180,110
Amounts are recorded separately on the balance sheet - negative numbers represent liabilities

Interest Rate Contracts

During the Company's fiscal year ended September 30, 2012, the Company had interest rate swaps that matured in April 2012. Since April 2012, the Company has not engaged in any interest rate swap agreements. These agreements were not designated as effective hedges for accounting purposes and the change in fair market value and associated net settlements were recorded in interest expense.

The Company recorded net settlements of approximately zero, $828,000 and $932,000 for the twelve months ended September 30, 2013, 2012 and nine-month transitional period ended September 30, 2011, respectively.

The following tables provide details regarding the Company's derivative financial instruments at September 30, 2013 and 2012:

40

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Derivatives not designated as hedging instruments:
Balance Sheet - as of September 30, 2013	Asset		Liability
Commodity derivative instruments, at fair value	$	—	$	48,638
Total derivatives not designated as hedging instruments for accounting purposes	$	—	$	48,638
Balance Sheet - as of September 30, 2012	Asset		Liability
Commodity derivative instruments, at fair value	$	180,110	$	—
Total derivatives not designated as hedging instruments for accounting purposes	$	180,110	$	—

Statement of Operations Income/(expense)	Location of gain (loss) in fair value recognized in income	Amount of gain (loss) recognized in income during the year ended September 30, 2013		Amount of gain (loss) recognized in income during the year ended September 30, 2012			Amount of gain (loss) recognized in income during the nine months ended September 30, 2011
Corn derivative instruments	Cost of Goods Sold	$	778,559	$	(481,703	)	$	(1,086,381	)
Ethanol derivative instruments	Revenue	—		—			—
Soybean oil derivative instruments	Revenue	—		28,476			—
Interest rate swaps	Interest Expense	—		2,126			(53,562		)
Total		$	778,559	$	(451,101	)	$	(1,139,943	)

4. INVENTORY

Inventory is valued at lower of cost or market. Inventory values as of September 30, 2013 and 2012 were as follows:

As of	September 30, 2013		September 30, 2012
Raw materials, including corn, chemicals and supplies	$	7,510,059	$	7,455,660
Work in process	1,056,340		1,231,096
Finished goods, including ethanol and distillers grains	1,951,155		3,704,046
Spare parts	1,672,139		1,260,105
Total inventory	$	12,189,693	$	13,650,907

Lower of cost or market adjustments for the year ended September 30, 2013, 2012, and the nine months ended September 30, 2011 were as follows:

41

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

	For the year ended September 30, 2013		For the year ended September 30, 2012		For the nine months ended September 30, 2011
Loss on firm purchase commitments	$	1,091,000	$	132,000	$	444,000
Loss on lower of cost or market adjustment for inventory on hand	665,300		327,000		450,000
Total loss on lower of cost or market adjustments	$	1,756,300	$	459,000	$	894,000

The Company has entered into forward corn purchase contracts under which it is required to take delivery at the contract price. At the time the contracts were created, the price of the contract price approximated market price. Subsequent changes in market conditions could cause the contract prices to become higher or lower than market prices.

As of September 30, 2013, the average price of corn purchased under certain fixed price contracts, that had not yet been delivered, was higher than approximated market price. Based on this information, the Company accrued an estimated loss on firm purchase commitments of $1,091,000 for the twelve months ended September 30, 2013. Losses of $132,000 and $444,000 were accrued for the year ended September 30, 2012 and nine month period ended September 30, 2011, respectively. The loss is recorded in “Loss on firm purchase commitments” on the statements of operations. The amount of the loss was determined by applying a methodology similar to that used in the impairment valuation 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.

The Company recorded inventory valuation impairments of $665,300, $327,000 and $450,000 for the year ended September 30, 2013, the year ended September 30, 2012 and the nine month period ended September 30, 2011, respectively. The impairments, as applicable, were attributable primarily to decreases in market prices of ethanol. The inventory valuation impairment was recorded in “Lower of cost or market adjustment” on the statements of operations.

5. BANK FINANCING

As of	September 30, 2013		September 30, 2012
Long-term notes payable under loan agreement to bank	$	20,708,000	$	23,750,000
Capital lease obligations (Note 7)	78,258		86,593
Total Long-Term Debt	20,786,258		23,836,593
Less amounts due within one year	2,949,977		2,584,429
Total Long-Term Debt Less Amounts Due Within One Year	$	17,836,281	$	21,252,164

On May 15, 2013, the Company executed amended and restated loan agreements with its primary lender, First National Bank of Omaha ("FNBO"). The purposes of the amended and restated loan agreements were to extend the maturity date of the Company's current credit facilities, to adjust the interest rates payable pursuant to the Company's various credit facilities with FNBO and to change the amounts available under the Company's revolving loans. The loan agreements all provide for a variable interest rate as of September 30, 2013 with the term loan interest rate at 3.77% and long-term revolver interest rate at 3.77% and the operating line-of-credit interest rate at 3.68%. Repayment terms on the $20,000,000 term loan are $500,000 per quarter and $125,000 per quarter reduction in the total amount available from the initial $5,000,000 long-term revolver. Both of these loans mature on April 16, 2017. The $10,000,000 operating line-of-credit has a maturity date of April 15, 2014. At September 30, 2013, the Company had $3,708,000 drawn on the long-term revolver and $0 drawn on the operating line of credit.

42

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Scheduled debt maturities for the twelve months ending September 30
	Totals
2014	$	2,949,977
2015	2,549,281
2016	2,500,000
2017	12,787,000
Thereafter	—
Total	$	20,786,258

As of September 30, 2013, the Company was in compliance with its debt covenants.

Interest Rate Swap Agreements

The Company does not have any interest rate swap agreements in place pursuant to the terms of the refinance with its senior lender in April 2012.

Interest Expense	For the year ended September 30, 2013		For the year ended September 30, 2012			For the nine months ended September 30, 2011
Interest expense on long-term debt	$	941,059	$	934,692		$	1,543,435
Change in fair value of interest rate swaps	—		(827,547		)	(878,037		)
Net settlements on interest rate swaps	$	—	$	827,887		$	931,599
Total interest expense	$	941,059	$	935,032		$	1,596,997

6. FAIR VALUE MEASUREMENTS

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2013 and 2012, respectively.

					Fair Value Measurement Using
	Carrying Amount as of September 30, 2013		Fair Value as of September 30, 2013		Level 1		Level 2		Level 3
Liabilities
Commodities derivative instruments	$	48,638	$	48,638	$	48,638	$	—	$	—
					Fair Value Measurement Using
	Carrying Amount as of September 30, 2012		Fair Value as of September 30, 2012		Level 1		Level 2		Level 3
Assets
Commodities derivative instruments	$	180,110	$	180,110	$	180,110	$	—	$	—

The fair value of the corn, ethanol and soybean oil derivative instruments are based on quoted market prices in an active market.

43

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

Financial Instruments Not Measured at Fair Value

The estimated fair value of the Company's long-term debt, including the short-term portion, at September 30, 2013 and 2012 approximated the carrying value of approximately $20.8 million and $23.8 million, respectively. Fair value was estimated using estimated variable market interest rates as of September 30, 2013. The fair values and carrying values consider the terms of the related debt and exclude the impacts of debt discounts and derivative/hedging activity.

7. LEASES

The Company leases equipment under operating and capital leases through January 2020. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under operating lease includes a locomotive and rail cars. Rent expense for operating leases was approximately $503,000 for the year ended September 30, 2013, $670,000 for the year ended September 30, 2012 and $445,000 for the nine month period ended September 30, 2011. Equipment under capital leases consists of office equipment and plant equipment.

Equipment under capital leases is as follows at:

As of	September 30, 2013			September 30, 2012
Equipment	$	564,377		$	483,217
Less accumulated amortization	(49,894		)	(26,460		)
Net equipment under capital lease	$	514,483		$	456,757

At September 30, 2013, the Company had the following minimum commitments, which at inception had non-cancelable terms of more than one year. Amounts shown below are for the 12 months period ending September 30:

	Operating Leases		Capital Leases
2014	$	489,913	$	28,977
2015	347,765		49,281
2016	245,300		—
2017	208,920		—
Thereafter	271,240		—
Total minimum lease commitments	$	1,563,138	78,258
Less amount representing interest			—
Present value of minimum lease commitments included in liabilities on the balance sheet			$	78,258

8. MEMBERS' EQUITY

The Company has one class of membership units outstanding (Class A) with each unit representing a pro rata ownership interest in the Company's capital, profits, losses and distributions. As of September 30, 2013 and 2012 there were 40,148,160 and 40,178,160 units issued and outstanding, respectively. The Company held a total of 225,813 and 195,813 treasury units as of September 30, 2013 and 2012, respectively.

Total units authorized are 40,373,973 as of September 30, 2013 and 2012.

44

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

9. GRANTS

In 2006, the Company entered into a contract with the State of North Dakota through the Industrial Commission for a lignite coal grant not to exceed $350,000. The Company received $275,000 from this grant during 2006 with this amount currently shown in the liability section of the Company's Balance Sheet as Contracts Payable. Because the Company has not met the minimum lignite usage requirements specified in the grant for any year in which the plant has operated, it expects to have to repay the grant and is awaiting instructions from the Industrial Commission as to the terms of the repayment schedule. This repayment could begin in fiscal 2014.

The Company has entered into an agreement with Job Service North Dakota for a new jobs training program. This program provides incentives to businesses that are creating new employment opportunities through business expansion and relocation to the state. The program provides no-cost funding to help offset the cost of training. The Company is eligible to receive up to approximately $270,000 over ten years. The Company received and earned approximately $39,000, $41,000 and $29,000 for the years ended September 30, 2013, 2012, and the nine month period ended September 30, 2011, respectively.

10. COMMITMENTS AND CONTINGENCIES

Firm Purchase Commitments for Corn

To ensure an adequate supply of corn to operate the Plant, the Company enters into contracts to purchase corn from local farmers and elevators. At September 30, 2013, the Company had various fixed price contracts for the purchase of approximately 1.3 million bushels of corn. Using the stated contract price for the fixed price contracts, the Company had commitments of approximately $6.4 million related to the 1.3 million bushels under contract. The Company also enters into fixed basis contracts with the actual price set by the supplier at a future date. Using current market prices, if these basis contracts were fixed at September 30, 2013, the Company would have commitments of approximately $2,500,000.

11. DEFINED CONTRIBUTION RETIREMENT PLAN

The Company established a 401k retirement plan for its employees effective January 1, 2011. The Company matches employee contributions to the plan up to 4% of employee's gross income. The Company contributed approximately $73,000, $75,000, and $56,000 to the 401k plan for the years ended September 30, 2013 and 2012, and the nine month period ended September 30, 2011, respectively.

12. RELATED-PARTY TRANSACTIONS

The Company has balances and transactions in the normal course of business with various related parties for the purchase of corn, sale of distillers grains and sale of ethanol. The related parties include Unit holders, members of the board of governors of the Company, and RPMG, Inc. (“RPMG”). Significant related party activity affecting the financial statements are as follows:

45

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

			September 30, 2013		September 30, 2012
Balance Sheet
Accounts receivable			$	3,562,404	$	2,853,704
Accounts payable			872,827		839,059
	For the twelve months ended September 30, 2013		For the twelve months ended September 30, 2012		For the nine months ended September 30, 2011
Statement of Operations
Revenues	$	128,293,885	$	110,252,547	$	96,730,967
Cost of goods sold	3,058,668		2,432,609		2,057,245
General and administrative	101,506		103,371		60,804
Inventory Purchases	$	28,905,391	$	23,809,605	$	7,984,774

13. INCOME TAXES

As of September 30, 2013, the book basis of assets exceeded the estimated tax basis of assets by approximately $42.5 million and as of September 30, 2012, the book basis of assets exceeded the estimated tax basis of assets by approximately $28.3 million. As of September 30, 2013, there was no difference between the book basis of liabilities and the estimated tax basis of liabilities. As of September 30, 2012, there was no difference between the book basis of liabilities and the estimated tax basis of liabilities.

14. SUBSEQUENT EVENTS

We have evaluated for subsequent events and none have been found.

15. UNCERTAINTIES IMPACTING THE ETHANOL INDUSTRY AND OUR FUTURE OPERATIONS

The Company has certain risks and uncertainties that it experiences during volatile market conditions, which 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 and from purchases on the open market. The Company's operating and financial performance is largely driven by prices at which the Company sells ethanol and distillers grains and by the cost at which it is able to purchase corn for operations. The price of ethanol is influenced by factors such as prices, supply and demand, weather, government policies and programs, and unleaded gasoline and the petroleum markets, although since 2005 the prices of ethanol and gasoline began a divergence with ethanol selling for less than gasoline at the wholesale level. Excess ethanol supply in the market, in particular, puts downward pressure on the price of ethanol. The Company's largest cost of production is corn. The cost of corn is generally impacted by factors such as supply and demand, weather, government policies and programs. The Company's risk management program is used to protect against the price volatility of these commodities.

46

RED TRAIL ENERGY, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED SEPTEMBER 30, 2013 and 2012

16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary quarter results are as follows:

Year Ended September 30, 2013	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	42,258,878		$	37,514,330		$	43,669,509		$	31,365,622
Gross profit (loss)	547,252			2,545,703			1,461,626			(1,334,529		)
Operating income (loss)	21,005			2,007,135			965,239			(1,919,060		)
Net income (loss)	(171,309		)	1,790,968			749,392			(1,734,888		)
Net income (loss) per unit-basic and diluted	—			0.04			0.02			(0.04		)
Year Ended September 30, 2012	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	37,427,000		$	37,123,717		$	33,908,133		$	22,999,919
Gross profit (loss)	955,938			(405,303		)	(3,762,009		)	(1,343,785		)
Operating income (loss)	280,631			(979,526		)	(4,266,893		)	(1,813,722		)
Net income (loss)	1,620,750			(908,333		)	(4,291,284		)	(1,119,108		)
Net income (loss) per unit-basic and diluted	0.04			(0.02		)	(0.11		)	(0.03		)
Nine-Month Transition Period Ended September 30, 2011	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	31,953,093		$	35,142,332		$	45,194,797		N/A
Gross profit	998,644			277,220			2,877,274			N/A
Operating income (loss)	321,889			(340,688		)	2,199,258			N/A
Net income (loss)	(149,257		)	213,875			3,787,677			N/A
Net income per unit-basic and diluted	—			0.01			0.09			N/A

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

47

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

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures.  The term "disclosure controls and procedures," as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 ("Exchange Act"), as amended, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's ("SEC") rules and forms.  Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures as of September 30, 2013, have concluded that our disclosure controls and procedures are effective in ensuring that material information required to be disclosed is included in the reports that we file with the SEC.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the fiscal quarter ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Inherent Limitations on the Effectiveness of Controls

Management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all errors and all fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that objectives of the control systems are met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.  Because of the inherent limitations in a cost-effective control system, no evaluation of internal controls over financial reporting can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, have been detected or will be detected.

These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of a simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.  Projections of any evaluation of controls effectiveness to future periods are subject to risks.  Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies and procedures.

Management's Annual Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting purposes.

Management conducted an evaluation of the effectiveness of the Company's internal control over financial reporting based on the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") of 1992. Management's assessment included evaluation of elements such as the design and operating effectiveness of key financial reporting controls, process documentation, accounting policies, and overall control enviro

48

nment. Based on this evaluation, management has concluded that the Company's internal control over financial reporting was effective as of September 30, 2013.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. As we are a non-accelerated filer, management's report is not subject to attestation by our registered public accounting firm pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 that permits us to provide only management's report in this annual report.

ITEM 9B.    OTHER INFORMATION

None.

PART III

ITEM 10. GOVERNOR, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference in the definitive proxy statement from our 2014 Annual Meeting of Members to be filed with the Securities and Exchange Commission within 120 days of our 2013 fiscal year end. This proxy statement is referred to in this report as the "2014 Proxy Statement."

ITEM 11. EXECUTIVE COMPENSATION.

The information required by this Item is incorporated by reference to the 2014 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED MEMBER MATTERS.

The information required by this Item is incorporated by reference to the 2014 Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND GOVERNOR INDEPENDENCE

The information required by this Item is incorporated by reference to the 2014 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by this Item is incorporated by reference to the 2014 Proxy Statement.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Exhibits Filed as Part of this Report and Exhibits Incorporated by Reference.

The following exhibits and financial statements are filed as part of, or are incorporated by reference into, this report:

(1) Financial Statements

The financial statements appear beginning at page 30 of this report.

(2) Financial Statement Schedules

All supplemental schedules are omitted as the required information is inapplicable or the information is presented in the financial statements or related notes.

(3) Exhibits

49

Exhibit No.	Exhibit	Filed Herewith	Incorporated by Reference
3.1	Articles of Organization, as filed with the North Dakota Secretary of State on July 16, 2003.		Filed as Exhibit 3.1 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
3.2	Amended and Restated Operating Agreement of Red Trail Energy, LLC.		Filed as exhibit 3.1 to our Current Report on Form 8-K on August 6, 2008. (000-52033) and incorporated by reference herein.
4.1	Membership Unit Certificate Specimen.		Filed as Exhibit 4.1 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
4.2	Member Control Agreement of Red Trail Energy, LLC.		Filed as Exhibit 4.2 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.1	The Burlington Northern and Santa Fe Railway Company Lease of Land for Construction/ Rehabilitation of Track made as of May 12, 2003 by and between The Burlington Northern and Santa Fe Railway Company and Red Trail Energy, LLC.		Filed as Exhibit 10.1 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.2	Agreement for Electric Service made the dated August 18, 2005, by and between West Plains Electric Cooperative, Inc. and Red Trail Energy, LLC.		Filed as Exhibit 10.10 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.3	Security Agreement and Deposit Account Control Agreement made December 16, 2005, by and among First National Bank of Omaha, Red Trail Energy, LLC, and Bank of North Dakota.		Filed as Exhibit 10.19 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.4	Security Agreement given as of December 16, 2005, by Red Trail Energy, LLC, to First National Bank of Omaha.		Filed as Exhibit 10.20 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.5	Control Agreement Regarding Security Interest in Investment Property, made as of December 16, 2005, by and between First National Bank of Omaha, Red Trail Energy, LLC, and First National Capital Markets, Inc.		Filed as Exhibit 10.21 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.6	Southwest Pipeline Project Raw Water Service Contract, executed by Red Trail Energy, LLC, on March 8, 2006, by the Secretary of the North Dakota State Water Commission on March 31, 2006, and by the Chairman of the Southwest Water Authority on April 2, 2006.		Filed as Exhibit 10.28 to the registrant's registration statement on Form 10-12G (000-52033) and incorporated by reference herein.
10.7	Contract dated April 26, 2006, by and between the North Dakota Industrial Commission and Red Trail Energy, LLC.		Filed as Exhibit 10.29 to the registrant's second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.8	Subordination Agreement, dated May 16, 2006, among the State of North Dakota, by and through its Industrial Commission, First National Bank and Red Trail Energy, LLC.		Filed as Exhibit 10.30 to the registrant's second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.9	Firm Gas Service Extension Agreement, dated June 7, 2006, by and between Montana-Dakota Utilities Co. and Red Trail Energy, LLC.		Filed as Exhibit 10.31 to the registrant's second amended registration statement on Form 10-12G/A (000-52033) and incorporated by reference herein.
10.10	Security Agreement and Deposit Account Control Agreement effective August 16, 2006 by and among First National Bank of Omaha and Red Trail Energy, LLC.		Filed as Exhibit 10.34 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.11	Option to Purchase 200,000 Class A Membership Units of Red Trail Energy, LLC by Red Trail Energy, LLC from North Dakota Development Fund and Stark County dated December 11, 2006.		Filed as Exhibit 10.36 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.

50

10.12	Audit Committee Charter adopted April 9, 2007.	Filed as Exhibit 10.37 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.13	Senior Financial Officer Code of Conduct adopted March 28, 2007.	Filed as Exhibit 10.38 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.
10.14	Member Ethanol Fuel Marketing agreement by and between Red Trail Energy, LLC and RPMG, Inc dated January 1, 2008.	Filed as Exhibit 10.41 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.15	Contribution Agreement by and between Red Trail Energy, LLC and Renewable Products Marketing Group, LLC dated January 1, 2008.	Filed as Exhibit 10.42 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.16	Distillers Grain Marketing Agreement by and between Red Trail Energy, LLC and CHS, Inc dated March 10, 2008.	Filed as Exhibit 10.44 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.
10.17	Assignment and Assumption Agreement dated April 1, 2008, by and between Commodity Specialist Company and Red Trail Energy, LLC.	Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (000-52033) and incorporated by reference herein.
10.18	Employment Agreement dated August 8, 2008 by and between Red Trail Energy, LLC and Mark Klimpel.	Filed as exhibit 99.1 to our Current Report on Form 8-K filed with the SEC on August 13, 2008 (000-52033) and incorporated by reference herein.
10.19	Amended and Restated Member Control Agreement of Red Trail Energy, LLC.	Filed as exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on June 1, 2009 (000-52033) and incorporated by reference herein.
10.20	Amended and Restated Management Agreement made and entered into as of September 10, 2009 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC.	Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (000-52033) and incorporated by reference herein.
10.21	Employment Agreement between Red Trail Energy, LLC and Gerald Bachmeier dated July 8, 2010.	Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (000-52033) and incorporated by reference herein.
10.22	Mediated Settlement Agreement between Red Trail Energy, LLC, Fagen, Inc. and Fagen Engineering, LLC, and ICM, Inc. dated November 8, 2010. +	Filed as Exhibit 99.1 to our Current Report on Form 8-K filed with the SEC on December 20, 2010 (000-52033) and incorporated by reference herein.
10.23	Letter Agreement between Greenway Consulting, LLC and Red Trail Energy, LLC dated January 13, 2011.	Filed as Exhibit 10.56 to our Current Report on Form 10-K for the fiscal year ended December 31, 2010 (000-52033) and incorporated by reference herein.
10.24	First Amended and Restated Revolving Promissory Note dated June 1, 2011 by and between Red Trail Energy, LLC and First National Bank of Omaha.	Filed as Exhibit 99.2 to our Current Report on Form 8-K dated June 1, 2011 (000-52033) and incorporated by reference herein.
10.25	Equity Grant Agreement between Kent Anderson and Red Trail Energy, LLC dated July 1, 2011.	Filed as Exhibit 10.1 to our Current Report on Form 10-Q for the quarter ended June 30, 2011 (000-52033) and incorporated by reference herein.
10.26	Corn Oil Separation System Agreement between Solution Recovery Services, LLC and Red Trail Energy, LLC dated October 6, 2011. +	Filed as Exhibit 10.60 to our Current Report on Form 10-K for the transition period ended September 30, 2011 (000-52033) and incorporated by reference herein.
10.27	First Amended and Restated Construction Loan Agreement between First National Bank of Omaha and Red Trail Energy, LLC dated April 16, 2012.	Filed as Exhibit 10.1 to our Current Report on Form 10-Q for the quarter ended March 31, 2012 (000-52033) and incorporated by reference herein.
10.28	Amended and Restated Ethanol Marketing Agreement between RPMG, Inc. and Red Trail Energy, LLC dated August 27, 2012. +	Filed as Exhibit 10.62 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2012 (000-52033) and incorporated by reference herein.
10.29	Member Corn Oil Marketing Agreement between RPMG, Inc. and Red Trail Energy, LLC dated March 21, 2012. +	Filed as Exhibit 10.63 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2012 (000-52033) and incorporated by reference herein.

51

10.30	First Amendment of First Amended and Restated Construction Loan Agreement between First National Bank of Omaha and Red Trail Energy, LLC dated October 31, 2012.		Filed as Exhibit 10.64 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2012 (000-52033) and incorporated by reference herein.
10.31	Distillers' Grain Marketing Agreement between RPMG, Inc and Red Trail Energy, LLC dated October 1, 2013.+	X
31.1	Certificate Pursuant to 17 CFR 240.13a-14(a)	X
31.2	Certificate Pursuant to 17 CFR 240.13a-14(a)	X
32.1	Certificate Pursuant to 18 U.S.C. Section 1350	X
32.2	Certificate Pursuant to 18 U.S.C. Section 1350	X
101	The following financial information from Red Trail Energy, LLC's Annual Report on Form 10-K for the fiscal year ended September 30, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Balance Sheets as of September 30, 2013 and 2012, (ii) Statements of Operations for the fiscal year ended September 30, 2013, 2012, and the transition period ended September 30, 2011, (iii) Statement of Changes in Members' Equity; (iv) Statements of Cash Flows for the fiscal year ended September 30, 2013, 2012, and the transition period ended September 30, 2011, and (v) the Notes to Financial Statements.**

(+) Confidential Treatment Requested.

(X) Filed herewith.

(**) Furnished herewith

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.

		RED TRAIL ENERGY, LLC
Date:	December 16, 2013	/s/ Gerald Bachmeier
		Gerald Bachmeier
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	December 16, 2013	/s/ Jodi Johnson
		Jodi Johnson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

52

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

Date:	December 16, 2013	/s/ Gerald Bachmeier
		Gerald Bachmeier, Chief Executive Officer and President
		(Principal Executive Officer)
Date:	December 16, 2013	/s/ Jodi Johnson
		Jodi Johnson, Chief Financial Officer and Treasurer
		(Principal Financial Officer)
Date:	December 13, 2013	/s/ Sid Mauch
		Sid Mauch, Chairman and Governor
Date:	December 13, 2013	/s/ Anthony Mock
		Anthony Mock, Governor
Date:	December 13, 2013	/s/ Ambrose Hoff
		Ambrose Hoff, Secretary and Governor
Date:	December 13, 2013	/s/ Ron Aberle
		Ron Aberle, Governor
Date:	December 13, 2013	/s/ Mike Appert
		Mike Appert, Governor
Date:	December 13, 2013	/s/ Frank Kirschenheiter
		Frank Kirschenheiter, Governor
Date:	December 13, 2013	/s/ William A. Price
		William A. Price, Governor

53