RED TRAIL ENERGY, LLC - FORM 10-K

During 2009, our total revenues decreased by 28.9% to $93.8 million. Ethanol and distillers grains represented 83% and 17% of 2009 revenue, respectively. The decrease in revenue is attributable to a number of factors, including:

Ethanol prices, net of hedging activity, averaged 23% lower in 2009 than 2008 ($1.56 per gallon in 2009 vs. $2.01 per gallon in 2008). We believe ethanol prices were lower overall due to the generally lower commodity prices (primarily corn, crude oil and gasoline) during 2009 compared to 2008. All three of these commodities reached record prices in late June and early July 2008 and then declined sharply in the last four to five months of 2008. Prices rebounded somewhat during 2009 but were still lower overall than in 2008. The average price we received for ethanol during 2009 ranged from $1.41 to $1.95. The high was achieved in November 2009 as tight ethanol supplies during the last quarter of 2009 caused ethanol prices to increase relative to corn prices. During 2009 and 2008, the Company realized losses on ethanol hedging activity of approximately $1.6 million and $2.4 million, respectively.

We produced and sold approximately 5 million fewer gallons of ethanol during 2009 compared to 2008. Approximately 3 million gallons of the reduction in production and sales came in the first six months of 2009 when we experienced very poor margin conditions and chose to run our plant at a slower rate. The remaining decrease in production and sales came in October 2009 when we experienced an unplanned outage related to an issue with our boiler.

Distillers grains – Our 2009 distillers grain sales volumes were roughly split 70-30 between DDGS and DMWG compared to a 50-50 split during 2008. The change in product mix came as we changed the pricing on our DMWG product to more closely match that of DDGS. On a dry matter basis (converting all distillers grains produced to a DDGS equivalent) our overall production of distillers grains decreased approximately 12% which is line with the decrease in ethanol production noted above. We produced and sold approximately 3,000 more tons of DDGS so the decline in production was all in our DMWG product. All of our DMWG product is transported by truck but our DDGS product is transported by both truck and rail. As other ethanol plants located in North Dakota, that had been idled for various reasons, resumed production we saw a shift in our shipments of DDGS from truck to rail.

The average price we received for our DDGS product in 2009 declined approximately 19% compared to 2008 and our revenue decreased by approximately 16%. The average prices we received for DDGS during 2009 ranged from $81 per ton to $141 per ton with our overall average price for the year being approximately $111 per ton compared to an average of approximately $136 per ton for 2008. DDGS prices generally follow the price of corn which was significantly lower in 2009 compared to 2008. The average price we receive for DDGS was also impacted by the shift from truck transportation to rail transportation noted above. We typically receive a premium of $7 - $10 per ton for product shipped by truck vs. rail.

The average price we received for our DMWG product in 2009 declined approximately 6% compared to 2008 and our revenue decreased approximately 35%. The decrease in revenue is primarily related to lower production due to the change in product mix noted above. We produced and sold approximately 37,500 fewer tons of DMWG (81,700 tons in 2009 vs. 119,300 tons in 2008) in 2009 compared to 2008. Prices received for our DMWG in 2009 ranged from $47 to $64 per ton with our average selling price for the year being approximately $54 per ton compared to $57 per ton in 2008. Prices for DMWG also follow the price of corn but didn’t decrease as much compared to 2008 as our DDGS prices due to a price increase instituted for our 2009 contract year.

·	We entered into ethanol swap contracts at various times during both 2009 and 2008. We recognized losses on hedging from ethanol derivative instruments during 2009 and 2008 of approximately $1.6 million and $2.4 million, respectively. These losses are included in revenue on our financial statements.

During 2008, our total revenues increased by 29.5% to $131.9 million. Ethanol and distillers grains represented 84% and 16% of 2008 revenue, respectively. The increase in revenue is attributable to a number of factors, including:

Ethanol prices, net of hedging activity, averaged 10% higher in 2008 than 2007 ($2.01 per gallon in 2008 vs. $1.82 per gallon in 2007). We believe ethanol prices were higher overall due to the increase in commodity prices (primarily corn, crude oil and gasoline) during the first six months of 2008. We believe ethanol prices are generally positively impacted by higher corn, gasoline and crude oil prices. All three of these commodities reached record prices in late June and early July 2008. The average price we received for ethanol during 2008 ranged from $1.46 to $2.50. The high was achieved in June 2008. Prices steadily declined the rest of the year to the low of $1.46 received in December. We believe the decrease was again due to the decrease in corn, crude oil and gasoline prices the last half of the year along with decreases in demand for these commodities as well as ethanol due to the collapse of the world economy.

Distillers grains – Our 2008 and 2007 distillers grain sales volumes were roughly split 50-50 between DDGS and DMWG. Prices received by us for DDGS ranged from $126 to $157 per ton during 2008 with our average selling price for the year being approximately $136 per ton compared to an average of approximately $87 per ton in 2007. The price of DDGS generally follows the price of corn so, as corn prices increased during the first half of 2008, the price we received for DDGS also increased to the high of $157 per ton received in June 2008. Prices have since declined along with corn prices and we received an average price of approximately $135 per ton in December 2008. Due to the high quality of our DDGS and the markets in which our product is typically sold we have been able to capture a small premium for our DDGS relative to other markets and plants. Due to this premium, the price we receive for DDGS actually increased slightly from September 2008 through December 2008. Prices received by us for DMWG during 2008 ranged from $50 to $75 per ton with our average selling price for the year being approximately $57 per ton compared to an average of approximately $40 per ton for 2007. Prices for DMWG also follow the price of corn and, as such, our price for DMWG peaked in July 2008 and steadily declined the rest of the year. Our price was also positively impacted, compared to 2007, due to a change made in our contract pricing to index the price we receive for DMWG to the price of corn. All of our 2007 contracts were based on a flat pricing schedule.

During 2008 we recognized a loss on hedging from ethanol derivative instruments of approximately $2.4 million compared to a loss of approximately $2 million during 2007. We held some ethanol swap contracts through July 2008. The value of these swap contracts decreased as ethanol prices increased during the first half of 2008. We exited the swaps as ethanol prices started to decrease in July 2008. These losses are included in revenue on our financial statements.

Ethanol – ethanol prices that increased sharply during the last quarter of 2009 have declined rapidly during January - March 2010 as the supply of ethanol has become more readily available as production has increased industry wide. We anticipate that ethanol prices will continue to increase or decrease with the price of corn, gasoline and crude oil and also be impacted by blending economics and the supply and demand for ethanol. As plants have started up or increased production in response to the improved margins, some in the industry are predicting another possible oversupply situation similar to what the industry went through in late 2008 and early 2009. If that were to happen we believe ethanol prices would decline relative to corn prices and could again lead to negative margins. We believe there will continue to be a cyclical component to ethanol prices until demand for ethanol catches up with total available ethanol capacity but we cannot be certain of how the price of ethanol will change, as it is a market driven commodity.

At this time we cannot predict the impact of the implementation of the low carbon fuel standard (“LCFS”) in California. The LCFS is scheduled to take effect on January 1, 2011. As of March 15, 2010, the LCFS has not had any impact on our ethanol sales from companies trying to comply early with the standard.

·	Distillers Grains - Distillers grains prices normally follow the price of corn. We believe distillers grains prices will remain consistent with corn price fluctuations but we cannot be certain of how the price of distillers grains will change, as it is a market driven commodity.

Corn Oil Extraction – during 2009 we terminated an agreement we had to operate a third party’s corn oil extraction equipment at our plant. This agreement was entered into during 2008 and was contingent upon the third party obtaining financing for its project. The equipment was never installed at our plant site. We are not currently seeking to install corn oil extraction equipment and do not anticipate pursuing this project in 2010.

Cost of Goods Sold and Gross Margin

We experienced significantly lower costs of goods sold in 2009 compared to 2008 with a decrease of approximately $43 million. The decrease was largely due to lower corn costs (approximately $38 million) and were mostly offset by the lower revenues noted above. Our other costs of goods sold decreased by approximately $5 million and largely contributed to the increase in our gross margin of approximately the same amount.

Our gross margin for 2009 was approximately $6 million compared to $900,000 for 2008. Our total cost of goods sold per gallon of ethanol produced decreased by 27% compared to 2008 ($1.76 per gallon vs. $2.39 per gallon). The decrease in cost of goods sold is attributable to a number of factors including:

Corn cost – our corn costs per gallon of ethanol produced decreased 30% during 2009 due, in large part, to average market corn prices that were significantly lower in 2009 compared to 2008. During 2009 we also took measures to decrease our exposure to losses on firm purchase commitments by limiting the amount of corn we had under fixed price contracts at any one time. We also renewed our focus on procuring corn from and building relationships with local farmers and elevators. As an end user of corn we typically enter in to fixed price contracts to ensure an adequate supply of corn to operate our Plant. During 2008, we recognized losses on firm purchase commitments of approximately $3.5 million which resulted from having entered into fixed price contracts to purchase corn at prices that became significantly higher than market prices as corn prices dropped sharply during the last six months of 2008. During 2009 we recognized losses of approximately $169,000 on firm purchase commitments due to having fewer bushels under fixed price contracts and less volatility in the corn market during 2009 as compared to 2008. In addition, we had to write down our corn and ethanol inventory to the lower of cost or market. For the periods ended December 31, 2009 and 2008, we had recorded lower of cost or market adjustments related to our corn and ethanol inventories of approximately $1.5 million and $771,000, respectively.

·	We used options and futures contracts to hedge our long corn position during both 2008 and 2009. We recognized a loss of approximately $475,000 and a gain of approximately $6.2 million related to our corn hedging activities during 2009 and 2008, respectively.

Other cost of goods sold – our other cost of goods sold consists primarily of chemical ingredients, depreciation, denaturant, repairs, energy and labor needed to operate the Plant. These costs decreased approximately $5.2 million in 2009 compared to 2008. We experienced decreases in our chemical ($1.7 million), denaturant ($1.6 million) and coal costs ($1.2 million) during the year. Many of the chemicals we use, along with denaturant, are commodities – these items decreased in price during 2009 compared to 2008 as commodities in general decreased compared to the record highs in late June/early July 2008. Our coal costs decreased due to having our coal unloading facility operational for a full year. This facility was placed in service in September 2008 and has been operating as intended and providing a savings of between $9 and $10 per ton of coal used. These decreases were offset in part by an increase in our electrical costs ($262,000) as our rates increased in 2009 compared to 2008 and also an increase in depreciation ($100,000) as we started to depreciate our coal unloading facility.

Our gross margin for 2008 was approximately $900,000 compared to approximately $14.8 million for 2007. Our total cost of goods sold per gallon of ethanol produced increased by 38% compared to 2007 ($2.39 per gallon vs. $1.73 per gallon). The increase in cost of goods sold is attributable to a number of factors including:

Corn cost – our corn costs per gallon of ethanol produced increased 42.5% during 2008. As an end user of corn we typically enter in to fixed price contracts to ensure an adequate supply of corn to operate our Plant. We reaped the benefits of this strategy during the first seven months of 2008 as we had entered in to fixed price contracts to purchase corn at prices that became significantly under the market value of corn as commodity prices increased to their peak in late June/early July 2008. Because ethanol prices increased along with corn prices we were able to operate profitably during this period. The decrease in prices during the last half of 2008 had the opposite effect on our margins as we had entered in to fixed price contracts to purchase corn at prices that became significantly higher than the market value of corn. Because ethanol prices decreased along with corn prices we incurred significant losses during this period which more than offset the profit earned during the first six months of 2008. Further exacerbating our losses was the fact that we had to accrue losses on the corn under fixed price contracts that had not yet been delivered. We recognized a loss on firm purchase commitments of approximately $3.1 million during the third quarter of 2008 and had approximately $1.4 million accrued as of December 31, 2008. Our total loss on firm purchase commitments for 2008 was approximately $3.5 million. In addition, we had to write down our corn and ethanol inventory to the lower of cost or market. As of December 31, 2008 this amounted to a write down of $212,000 for corn inventory and $559,000 for ethanol. We did not have any losses on firm purchase commitments or lower of cost or market inventory adjustments during 2007.

Partially offsetting the increase in corn costs during 2008 were gains recognized from our corn hedging activities of approximately $6.2 million. During 2007, we recognized gains from our corn hedging activities of approximately $3 million. The losses we sustained during 2008 along with difficulties we encountered in trying to raise additional short term liquidity through increasing our short term line of credit have left us with an amount of available capital that will not allow us to take aggressive hedge positions even if the opportunity arises where we could lock in a margin using either corn or ethanol related derivative instruments.

Other cost of goods sold – our other cost of goods sold consists primarily of chemical ingredients, depreciation, repairs, energy and labor needed to operate the Plant. We experienced increases in our chemical, coal and repair costs during the year. Chemical costs increased due to price increases for some of our main chemicals (including anhydrous ammonia, sodium bicarbonate and sulfuric acid) as world demand for these chemicals increased causing a shortage in supply. Our coal costs increased due to running a full year on more expensive PRB coal during 2008. Repair costs increased as we entered our second year of operation and took the Plant down for two scheduled maintenance outages.

Corn – corn prices have remained fairly constant during January - March 2010. There has been a relative strengthening of corn prices vs. ethanol prices which has decreased margins in early 2010 compared to the fourth quarter of 2009. We cannot be certain how the price of corn will change as it is a market driven commodity.

·	Energy needs – we have contracts in place for our main energy needs. See below for information on our main energy costs:

Coal – we entered into a new two year coal supply agreement during 2009. Our raw coal costs increased approximately 6% under this new agreement. We anticipate that our coal costs for 2010 will be slightly higher during 2010 due to this price increase. A portion of our coal cost is related to removing and disposing of the ash generated from burning the coal. We currently pay to dispose of this waste. We are in the process of exploring alternative uses for our ash which may allow us to eliminate the cost of disposal. If we are successful in this venture we would anticipate a reduction in our coal and ash costs of approximately $300,000 on an annual basis.

o	Electricity – we have an agreement with Roughrider Electric for our electric needs. This contract does not offer price protection, however, and we have received notice that our rates will increase approximately 7% in 2010 compared to 2009 rates.

Chemicals – we have contracts in place for our chemical supply needs. The contracts call for competitive market pricing. It is difficult to predict the pricing for our chemicals and denaturant as they are market driven commodities. Through February 2010 we have seen some small increases in our main chemicals and denaturant – based on this information we would expect our chemical costs to be higher in 2010 compared to 2009.

·	Labor costs – we did institute some cost of living wage increases at the end of 2009 and are also considering the reinstatement of our quarterly bonus program. If the program is reinstated, we would expect our labor costs to be slightly higher in 2010 compared to 2009.

General and Administrative Expenses

General and administrative expenses for 2009 were approximately $44,000 lower than 2008.

A decrease of approximately $417,000 in management fees. Our management company is paid a monthly fee plus 4% of our net income. During 2008, the 4% of net income was paid based on our quarterly net income which resulted in an expense of approximately $325,000 compared to approximately $34,000 for 2009 based on our annual net income.

The Company also recognized a decrease of in various general and administrative costs of approximately $219,000 due to cost cutting measures instituted at the beginning of 2009. We had lower board meeting expense costs as our board members suspended their pay for 2009, we also had lower office supplies expense costs, lower purchased services costs and smaller decreases in other areas.

The decrease in general and administrative costs was partially offset by:

·	An increase in our bank fees of approximately $182,000 as we paid $175,000 in fees to our bank related to the negotiation of the principal deferral.

·	An increase in legal fees of approximately $170,000 as additional work was required on our proxy statement related to the amended and restated member control agreement, the development of our corn procurement program and various other matters that took place during 2009.

·	An increase in permitting and licensing fees of approximately $154,000. This included a one-time registration fee of approximately $66,000 to complete our registration as a fuel additive manufacturer and we also incurred additional permitting costs related to our new air permit application.

General and administrative expenses decreased approximately $357,000 (11.1%) primarily due to:

·	A decrease of approximately $534,000 in professional service fees (including legal, accounting, consulting on permits and other professional services) as our employees started to take over additional responsibilities in these areas in an effort to reduce our dependence on outside services.

The decrease in general and administrative costs was partially offset by:

·	An increase in our real estate taxes of approximately $157,000 as 2008 represented the first year of the phase-out of our tax exemption.

We anticipate our general and administrative expenses for 2010 to be similar to 2009 with the following exceptions: Our legal fees may increase as we move into mediation proceedings with our design builder. We are scheduled to have an increase in our real estate taxes of approximately $90,000 as we enter the third year of the phase out of our tax exemption.

Interest Expense

Our interest costs are made up of the following components:

Interest expense for the year ended December 31,	2009			2008		2007
Interest expense on long-term debt	$	2,930,910		$	3,545,910	$	5,160,282
Amortization/write-off of deferred financing costs		567,386			201,020		214,169
Change in fair value of interest rate swaps		(500,843	)		1,817,338		933,256
Net settlements on interest rate swaps		991,463			449,031		(39,000	)
Total interest expense	$	3,988,916		$	6,013,299	$	6,268,707

Interest expense on long-term debt – approximately $600,000 lower than 2008 due primarily to interest rates that averaged approximately 1% lower during 2009 than 2008. The amount reported as interest expense on our long-term debt in our Annual Report on Form 10-K for the year ended December 31, 2008 was $4 million which included the net settlements on interest rate swaps. This amount has been reported separately above.

·	Amortization of deferred financing costs – during the first quarter of 2009 we wrote off the remaining balance of our deferred financing costs (approximately $517,000) due to uncertainties in our ability to meet our debt obligations that existed at the time.

Change in fair value of interest rate swaps – we recorded a loss from the change in fair value of our interest rate swap during 2008 as interest rates decreased which decreases the value of our swap. During 2009 the replacement rates on our swaps remained fairly constant. The increase in the fair value of our swaps during 2009 had more to do with the passage of time - as we get closer to the expiration date of our swaps we anticipate the value of the swaps will move toward $0.

·	Net settlements on interest rate swaps – the replacement rates on our swaps were lower for the whole year in 2009 compared to 2008 which lead to an increase in the settlement payments on our swaps.

Change in fair value of interest rate swaps – interest rates continue to decrease during 2008 in response to the global economic crisis that developed during the last six months of 2008. The decrease in rates led to further declines in the fair value of our interest rate swaps which resulted in additional losses.

·	Interest expense on long-term debt – approximately $1.5 million lower than 2007 due to lower interest rates and also lower outstanding debt balances for a portion of the year as we paid down part of our Long-Term Revolving Note as a way to use our excess cash.

·	Net settlements on interest rate swaps – as the replacement rates on our swaps continued to decline during 2008 and became lower than our swap rates, we started to have to make settlement payments on our swaps.

Interest rates stayed relatively constant at very low levels during 2009. Because variable rates have been so low, the interest rate on our senior debt for most of 2009 was 6% which is the floor established in the 6th Amendment to our Construction Loan Agreement. We do not feel we can accurately predict interest rates for 2010 as it will largely depend on government monetary policy. In general, an increase in interest rates will have a positive impact on the value of our interest rate swaps but will increase the amount of interest we pay on the variable interest rate portion of our notes.

Other Income and Expense

Other income includes payments from our state ethanol incentive program, interest income and grant income. Other income, net was approximately $1.2 million, $2.6 million and $800,000 for the fiscal years ended December 31, 2009, 2008 and 2007, respectively.

During 2009, conditions were met that triggered payments to be made under the state of North Dakota’s ethanol incentive program. We received approximately $660,000 and $2.1 million and $0 under this program during 2009, 2008 and 2007, respectively. The program had a minimal amount of available funds at the end of 2009 and will not be funded again until June 2010. We cannot accurately predict how much we may receive from this program in the future and the amount could ultimately be $0.

Interest income was approximately $470,000, $426,000 and $432,000 for the fiscal years ended December 31, 2009, 2008 and 2007, respectively.

2009 interest income – primarily the result of interest earned on sales and use tax paid during Plant construction as explained below. We received the remaining portion of the sales tax refund during 2009 which included interest of approximately $390,000. The remaining interest income of approximately $80,000 was made up of interest earned on cash balances and finance charges charged to customers.

2008 interest income – primarily the result of interest earned on sales and use tax paid during Plant construction. We received an exemption from sales and use tax for items used in the construction of our Plant. Because our general contractor paid for most of the items and then billed us they had to pay the requisite sales and use tax and then turn around and request a refund of those amounts. Due to the volume of invoices for materials used to construct the Plant a refund request was not completed until June 2008. We have received a portion of the refund along with interest. The interest portion totaled approximately $380,000. The remaining interest income of approximately $46,000 was derived from excess operating cash and approximately $4.2 million set aside to cover the final construction costs that have not been paid to our general contractor.

·	2007 interest income – primarily the result of funds held in money market accounts. The funds consisted of excess operating cash along with approximately $3.9 million set aside to cover the final construction costs that have not been paid to Fagen.

Grant income was approximately $37,000, $73,000 and $27,750 for the fiscal years ended December 31, 2009, 2008 and 2007, respectively. We do not anticipate receiving any significant grant income during 2010.

During January 2010, we did record a business interruption insurance settlement of approximately $983,000 related to the unplanned outage we experienced in October 2009. We do not anticipate receiving any other significant amount of other income during 2010. We also do not anticipate receiving a significant amount of interest income during 2010. We do anticipate receiving interest income on the cash set aside to pay our general contractor for the final construction costs but, based on current interest rates paid on deposits, feel the amount will not be material.

Plant Operations

Operations of Ethanol Plant

We produced approximately 49.8 million gallons of ethanol in 2009 which is approximately 100% of name-plate capacity. At various times during 2009 we operated the plant at a reduced rate for economic reasons. Management will continue to evaluate the plant production rate based on a number of factors, including market economics and corn availability. Based on margins that currently exist in the industry we anticipate running the plant at what we consider its normal rate which would lead to production of approximately 54 million gallons of ethanol.

Due to the improvement in margins, the timely negotiation of the deferral of two principal payments with the Bank during 2009 and various cost containment measures implemented during 2009 the Company is now in a better financial position than at the end of 2008. We project that, under current market conditions, we will maintain compliance with our loan covenants, meet our debt obligations and be able to fund our operations through cash generated from operations during 2010.

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.

Derivative Instruments

From time to time the Company may enter into derivative transactions to hedge its exposure to commodity price and interest rate fluctuations. The Company is required to record these derivatives on the balance sheet at fair value.

In order to reduce the risk caused by market fluctuations of corn, ethanol and interest rates, we enter into option, futures and swap contracts. These contracts are used to fix the purchase price of our anticipated requirements of corn in production activities and the selling price of our ethanol product and limit the effect of increases in interest rates. The fair value of these contracts is based on quoted prices in active exchange-traded or over-the-counter markets and discounted cash flow analysis on the expected cash flows of each instrument. The fair value of the derivatives is continually subject to change due to the changes in market conditions and interest rates. We do not typically enter into derivative instruments other than for hedging purposes. On the date the derivative instrument is entered into, we will designate the derivative as either a hedge of the variability of cash flows of a forecasted transaction or will not designate the derivative as a hedge. Currently, none of our derivative instruments are classified as a cash flow hedge for accounting purposes. Changes in the fair value of a derivative instrument that is designated and meets all of the required criteria for a cash flow or fair value hedge is recorded in accumulated other comprehensive income and reclassified into earnings as the hedged items affect earnings. Changes in fair value of a derivative instrument that is not designated and accounted for as a cash flow or fair value hedge is recorded in current period earnings. Although certain derivative instruments may not be designated and accounted for as a cash flow or fair value hedge, they are effective economic hedges of specific risks.

Inventory

We value our 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, ethanol prices and distillers gains prices, the effective yield and estimated future profit margins. Our inventory consists of raw materials, work in process, and finished goods. The work in process inventory is based on certain assumptions. The assumptions used in calculating work in process are the quantities in the fermenter and beer well tanks, the lower of cost or market price used to value corn at the end of the month, the effective yield, and the amount of dried distillers grains assumed to be in the tanks.

Commitments and Contingencies

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

Long-Lived Assets

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

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

Liquidity and Capital Commitments

Statement of Cash Flows for the years ended December 31,	2009		2008			2007
Cash flows from operating activities	$	7,936,258	$	8,495,564		$	2,684,633
Cash flows from (used in) investing activities		532,170		(2,300,195	)		(3,974,839	)
Cash flows from (used in) financing activities		311,824		(9,993,239	)		9,100,193

Cash flows

As noted in the footnotes to the financial statements on page F-7 of this Annual Report, certain items in the cash flow statement have been reclassified to conform to the presentation provided in fiscal year 2009. The reclassification had no effect on total operating, investing or financing cash flows, net income (loss) or members’ equity as previously reported.

Operating activities.

Typically our net income (loss) before depreciation, amortization and certain other noncash charges is a significant contributor to cash flows from operating activities. The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.

2009 Compared to 2008

Cash flows provided by operating activities in 2009 decreased approximately $600,000 from the comparable prior period, as a result of:

A net decrease in the change in various non-cash charges of approximately $2.9 million primarily related to a decrease in the change in market value of our interest rates swaps and other derivative instruments of approximately $3.4 offset by an increase in depreciation of approximately $100,000 and an increase in amortization of approximately $360,000 due to the write-off of our remaining deferred financing costs earlier in 2009.

A net decrease in cash flow from changes in working capital items of approximately $3.4 million. This change is primarily the result of a decrease in the change in the accrual for our loss on firm purchase commitments of approximately $2.9 million along with normal changes in other working capital items of approximately $500,000.

Partially offsetting the decrease in cash flows from working capital items was:

·	An increase in net income of approximately $5.7 million. Please review the “Results of Operations” for an in depth explanation of our net income for 2009 as compared to 2008.

2008 Compared to 2007

Cash flows provided by operating activities in 2008 increased $5.8 million from the comparable prior period, as a result of:

·	A net increase in cash flow from changes in working capital items of approximately $11.9 million. This change is primarily the result of:

A net decrease in cash flow from working capital items during 2007 as the Plant started operations. Most production related working capital items started at a balance close to zero on January 1, 2007 and were built to their resulting balance at the end of December 31, 2007 through normal plant operations. This resulted in a net use of cash from changes in working capital items of approximately $7.4 million.

o	At December 31, 2008, the change in the balance of our working capital items resulted in a positive cash flow of approximately $4.5 million - primarily as a result of the following:

§	Our receivable balances were lower by approximately $3.3 million due to lower ethanol prices.

§	The combined total of inventory and prepaid inventory decreased approximately $557,000 due lower inventories on hand, the result of normal fluctuations and timing of production and delivery of corn.

§	The cash held in our margin account was lower by approximately $1.5 million as our risk management committee had reduced our hedging position in response to the uncertain market conditions.

§	An increase in the accrued loss on firm purchase commitments of approximately $1.4 million

Offset in part by:

§	Our accounts payable and accrued expenses decreased by a combined $1.8 million due to lower inventories being maintained and the fluctuations due to the timing of purchases.

§	Net settlements on our interest rate swaps of approximately $450,000

A net increase in various non-cash charges of approximately $5.4 primarily related to an increase in the change in the fair value of our hedging derivative instruments of approximately $4 million and an increase in the change in the fair value of our interest rates swaps of approximately $1.4 million

Partially offsetting the increase in cash flows from working capital items was:

·	A decrease in net income of approximately $11.5 million. Please review the “Results of Operations” for an in depth explanation of our net income for 2008 as compared to 2007.

Investing activities.

Cash flows used in investing activities in 2009 decreased $2.8 million compared to 2008, the result of lower capital expenditures in 2009. We had very minimal capital expenditures during 2009 as we didn’t have any major projects to complete and conserved cash in an effort to maintain liquidity. We also received a refund of sales tax amounts paid on the original construction of our plant which reduced the cost of our plant and are shown as an offset to our capital expenditures on the cash flow statement. We had one major capital project during 2008 which was our coal unloading facility.

Cash flows used in investing activities in 2008 decreased $1.7 million compared to 2007, the result of lower capital expenditures in 2008. We only had one major capital project during 2008 which was to build a coal unloading facility on our site. The capital expenditures made during 2007 were made to finalize Plant construction.

Financing activities.

Cash flows used in financing activities in 2009 decreased $10.3 million compared to 2008 primarily related to lower debt payments in 2009 and borrowing the remaining capacity on our Long-Term Revolving note during 2009. Our bank allowed us to defer two principal payments during 2009 which decreased our debt service requirements by approximately $2.2 million. These payments will be added to the end of the term of the loan. We made scheduled debt service payments of approximately $2.5 million. In addition we borrowed the remaining $3.5 million of available capacity on our Long-Term Revolving note during 2009.

Cash flows used in financing activities in 2008 decreased $19.1 million compared to 2007, primarily the result of a transition to debt service. We borrowed approximately $9.3 million of long-term debt under our construction loan agreements during 2007 as Plant construction was finalized. During 2008 we made principal payments of approximately $10.1 million on our long term debt. This consisted of our scheduled principal payments of approximately $4.3 million along with an additional principal payment of $2.3 million in accord with the excess cash flow payment terms of our note agreements. In addition we made a temporary pay down of $3.5 million on our Long-Term Revolving note as a way to better use our excess cash.

Capital Expenditures

We did not incur any significant capital expenditures during 2009 and had one major project during 2008 which was the construction of our coal unloading facility. For 2010 we anticipate that we may have approximately $500,000 of capital expenditures related to the replacement of certain rolling stock and upgrades to our Plant. We could also have additional capital expenditures related to meeting emissions requirements and/or preparing to try and meet requirements of low-carbon fuel standards. At this time we cannot accurately estimate the dollar amount of these potential expenditures and whether we would be able to fund them from operations. Based on our projections as of March 2010, we believe we can fund our planned capital expenditures from our operating cash flows and/or financing options that may be available to us.

Capital Resources

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

	•		Providing the Bank with current and accurate financial statements;

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

	•		Maintaining adequate insurance;

	•		Make, or allow to be made, any significant change in our business or tax structure; and

	•		Limiting our ability to make distributions to members.

The original construction loan agreement, as amended, also contains a number of events of default (including violation of our loan covenants) which, if any of them were to occur, would give the Bank certain rights, including but not limited to:

	•		declaring all the debt owed to the Bank immediately due and payable; and

	•		taking possession of all of our assets, including any contract rights.

The Bank could then sell all of our assets or business and apply any proceeds to repay their loans. We would continue to be liable to repay any loan amounts still outstanding.

During 2009, we successfully negotiated the deferral of two principal payments with our Bank which allowed us sufficient liquidity to continue operations through 2009. In March 2010, we also entered into the 7th Amendment which changed the definition of some of our loan covenants and waived all prior covenant violations. These changes allowed us to regain compliance with all of our loan covenants as of December 31, 2009, and we project that, under market conditions that exist during March 2010 and our assumptions about future market conditions, we will maintain compliance with those covenants throughout 2010. Our projections assume slight improvement in the spread between ethanol and corn prices during the last six months of 2010 as we anticipate that the current oversupply situation will be mitigated, in part, by an increase in gasoline demand through the summer driving season and more discretionary blending due to the significant favorable spread that currently exists between gasoline and ethanol prices (when ethanol prices are lower than gasoline prices, blenders have an incentive to blend more ethanol into gasoline).

As of February 2010, we had available cash of approximately $10 million. We did not have any available borrowing capacity as our Bank did not renew our $3.5 million line of credit when it expired in July 2009. Our available cash does not include approximately $4.2 million that has been aside in conjunction with amounts withheld from Fagen as described earlier in this document. Under current market conditions and our assumptions about future margins, we anticipate that we will have sufficient available capital to meet all of our obligations during 2010.

Short-Term Debt Sources

We do not currently have any short-term debt sources as our $3.5 million line of credit was not renewed during July 2009. Under current market conditions and our assumptions about future margins, we would not anticipate needing to borrow any funds from a short-term line of credit to fund our operations during 2010.

Long-Term Debt Sources

The Company has four long-term notes (collectively the “Term Notes”) in place as of December 31, 2009. Three of the notes were established in conjunction with the termination of the original construction loan agreement on April 16, 2007. The fourth note was entered into during December 2007 (the “December 2007 Fixed Rate Note”) when the Company entered into a second interest rate swap agreement which effectively fixed the interest rate on an additional $10 million of debt. The construction loan agreement requires the Company to maintain certain financial ratios and meet certain non-financial covenants. Each note has specific interest rates and terms as described below.

Term Notes - Construction Loan

		Outstanding Balance (Millions)			Interest Rate					Range of Estimated Quarterly Principal		Estimated Final
Term Note		December 31, 2009		December 31, 2008	December 31, 2009		December 31, 2008			Payment Amounts		Payment (millions)	Notes
Fixed Rate Note	$	23.60	$	24.70	6.00	%	5.79	%	$	540,000 - $650,000	$	18.30	1, 2, 4
Variable Rate Note		2.10		3.00	6.00	%	6.04	%	$	450,000 - $460,000		1.20	1, 2, 3, 5
Long-Term Revolving Note		10.00		6.40	6.00	%	5.74	%	$	277,000 - $535,000		7.70	1, 2, 6, 7
2007 Fixed Rate Note		8.80		9.20	6.00	%	6.19	%	$	200,000 - $239,000		6.10	1, 2, 5

Notes

1 -	The scheduled maturity date is April 2012

2 -	Range of estimated quarterly principal payments is based on principal balances and interest rates as of December 31, 2009

3 -

Quarterly payments of $634,700 are applied first to interest on the Long-Term Revolving Note, next to accrued interest on theVariable Rate Note and finally to principal on the Variable Rate Note. Variable Rate Note is estimated to be paid off in April 2010 as Excess Cash Flow payment that is due will be applied to the Variable Rate Note and to the Long-Term Revolving Note.

4 -	Interest rate based on 5.0% over three-month LIBOR with a 6% minimum, reset quarterly

5 -	Interest rate based on 5.0% over three-month LIBOR with a 6% minimum, reset quarterly

6 -	Interest rate based on 5.0% over one-month LIBOR with a 6% minimum, reset monthly

7 -	Principal payments would be made on the Long-Term Revolving Note once the Variable Rate Note is paid in full.

The Company also has $5.5 million in subordinated debt that matures in February 2011. Interest is charged on these notes at 2% over the rate charged on the variable rate note.

Please see Note 5 to our Financial Statements in this Annual Report for a comprehensive discussion of our Long-Term Debt Sources.

Interest Rate Swap Agreements

In December 2005, we entered into an interest rate swap transaction that effectively fixed the interest rate at 8.08% on the outstanding principal of the Fixed Rate Note. In December 2007, we entered into a second interest rate swap transaction that effectively fixed the interest rate at 7.695% on the outstanding principal of the December 2007 Fixed Rate Note.

The interest rate swaps were not designated as either a cash flow or fair value hedge. Market value adjustments and net settlements were recorded in interest expense.

Letters of Credit

During 2009, the Company issued $750,000 in letters of credit from the Bank in conjunction with the issuance of two bonds needed for operations. There is no expiration date on the letters of credit and the Company does not anticipate the Bank having to advance any funds under these letters of credit. The $137,000 letter of credit that was outstanding at December 31, 2008 has been allowed to expire.

Contractual Obligations and Commercial Commitments

We have the following contractual obligations as of December 31, 2009:

Contractual Obligations	Total		Less than 1 Yr		1-3 Years		3-5 Years		More than 5 Yrs
Long-term debt obligations *	$	57,494,934	$	9,911,028	$	47,561,776	$	22,130	$	―
Capital leases		56,978		45,518		6,708		4,752		―
Operating lease obligations		1,411,065		489,660		886,705		34,700		―
Corn Purchases **		4,095,920		4,095,920		―		―		―
Coal purchases		2,895,300		1,408,050		1,487,250		―		―
Contractual Obligation		176,000		176,000		―		―		―
Management Agreement		343,200		171,600		171,600		―		―
Water purchases		2,844,800		406,400		812,800		812,800		812,800
Total	$	69,318,197	$	16,704,176	$	50,926,839	$	874,382	$	812,800

* - Long-term debt obligations shown in this table are based on the scheduled payments contained in the Term Notes including the effects of the waiver of principal and interest rate floor provided for in the Sixth Amendment as well as provisions of the Seventh Amendment. We used the rates fixed in the interest rate swap agreements (see “Interest Rate Swap Agreements” in Note 5 to our audited financial statements) for the Fixed Rate Note and December 2007 Fixed Rate Note, respectively which should account for possible net cash settlements on the interest rate swaps.

** - Amounts determined assuming prices, including freight costs, at which corn had been contracted for cash corn contracts and current market prices as of December 31, 2009 for basis contracts that had not yet been fixed.

Grants

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. We are in the process of submitting the final report to the Industrial Commission at which time repayment of the grant will commence. Because we have not met the minimum lignite usage requirements specified in the grant for any year in which the Plant has operated, we expect to repay the grant at a rate of approximately $35,000 per year. This repayment could begin in 2010.

We have 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. We will receive up to approximately $270,000 over ten years. For the years ended December 31, 2009, 2008 and 2007 we received approximately $37,000, $73,000 and $0, respectively. We anticipate receiving approximately $40,000 from this grant for the year ended December 31, 2010.

North Dakota Ethanol Incentive Program

Under the program, eligible ethanol plants may receive a production incentive based on the average North Dakota price per bushel of corn received by farmers during the quarter, as established by the North Dakota agricultural statistics service, and the average North Dakota rack price per gallon of ethanol during the quarter, as compiled by AXXIS Petroleum. We received approximately $660,000, $2.1 million and $0 from this program during 2009, 2008 and 2007, respectively. Because we cannot predict the future prices of corn and ethanol, we cannot predict whether we will receive any funds in the future. The fund used to pay for this incentive program receives most of its funds on an annual basis. Currently, there are no funds available for this program and it will not be funded again until June 2010. The incentive received is calculated by using the sum arrived at for the corn price average and for the ethanol price average as calculated in number 1 and number 2 below:

	1.		Corn Price :

	a.		For every cent that the average quarterly price per bushel of corn exceeds $1.80, the state shall add to the amounts payable under the program $.001 multiplied by the number of gallons of ethanol produced by the facility during the quarter.

	b.		If the average quarterly price per bushel of corn is exactly $1.80, the state shall not add anything to the amount payable under the program.

	c.		For every cent that the average quarterly price per bushel of corn is below $1.80, the state shall subtract from the amounts payable under the program $.001 multiplied by the number of gallons of ethanol produced by the facility during the quarter.

	2.		Ethanol Price:

	a.		For every cent that the average quarterly rack price per gallon of ethanol is above $1.30, the state shall subtract from the amounts payable under the program $.002 multiplied by the number of gallons of ethanol produced by the facility during the quarter.

	b.		If the average quarterly price per gallon of ethanol is exactly $1.30, the state shall not add anything to the amount payable under the program.

	c.		For every cent that the average quarterly rack price per gallon of ethanol is below $1.30, the state shall add to the amounts payable under the program $.002 multiplied by the number of gallons of ethanol produced by the facility during the quarter.

Under the program, no facility may receive payments in excess of $1.6 million during the State of North Dakota’s fiscal year (July 1 – June 30). If corn prices are low compared to historical averages and ethanol prices are high compared to historical averages, we will receive little or no funds from this program.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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 Unites States 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 we use ethanol swaps to hedge changes in the commodity price of 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 SFAS 133, Accounting for Derivative Instruments and Hedging Activities.

Interest Rate Risk

We are exposed to market risk from changes in interest rates. Exposure to interest rate risk results primarily from holding a revolving promissory note and construction term notes which bear variable interest rates. Approximately $17.6 million of our outstanding long-term debt is at a variable rate as of December 31, 2009. The Sixth Amendment to our Construction Loan Agreement places a minimum interest rate of 6% on our long-term debt outstanding with FNBO and increased the spread on the variable rate notes to 400 basis points over the one-month or three-month LIBOR rates. One-month and three-month LIBOR rates were very low as of December 31, 2009 and, therefore, the interest rate on our debt was set at the floor of 6%. Because of the interest rate floor placed on our debt we will not benefit from a decrease in rates from their current levels. We anticipate that a hypothetical 1% increase in interest rates, from those in effect on December 31, 2009, would have a minimal impact on our interest expense as the variable rates noted above are almost 1% lower than the interest rate floor. In order to achieve a fixed interest rate on the construction loan and reduce our risk to fluctuating interest rates, we entered into an interest rate swap contract that effectively fixes the interest rate at 8.08% on approximately $23.6 million of the outstanding principal of the construction loan. We entered into a second interest rate swap in December 2007 and effectively fixed the interest rate at 7.695% on an additional $10 million of our outstanding long-term debt. The interest rate swaps are not designated as either a cash flow or fair value hedge. Fair value adjustments and net settlements are recorded in interest expense. We anticipate that a hypothetical 1% change in interest rates, from those in effect on December 31, 2009, would change the fair value of our interest rate swaps by approximately $650,000.

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.

As of December 31, 2009 we had approximately 1.1 million bushels of corn under fixed price contracts. These contracts were priced below current market prices so we did not have any accrued a loss on firm purchase commitments related to these contracts. We would expect a sustained $0.10 change in the price of corn to have an approximate $110,000 impact on our net income.

We entered into ethanol swap contracts and corn futures and options positions equivalent to approximately 3.2 million bushels of corn to offset our net long position which includes corn in inventory, corn purchased under fixed price contracts and corn converted to ethanol but not yet priced. The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged. There are several variables that could affect the extent to which our derivative instruments are impacted by price fluctuations in the cost of corn or ethanol. 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.

It is the current position of RPMG (our ethanol marketing company) 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 had no fixed price contracts for the sale of physical ethanol outstanding at December 31, 2009 or 2008.

We estimate that our expected corn usage will be between 18 million and 20 million bushels per 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our financial statements and supplementary data are included on pages F-1 to F-22 of this Report.

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

Boulay, Heutmaker, Zibell & Co., P.L.L.P. has been our independent auditor since 2005 and is our independent auditor at the present time. We have had no disagreements with our auditors.

ITEM 9A(T). 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 Rule 13a-15(e) and rule 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 December 31, 2009, have concluded that our disclosure controls and procedures are effective and are adequately designed to ensure that information required to be disclosed by us in the reports we file or submit under with the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control–Integrated Framework.

Based on our evaluation under the framework in Internal Control–Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2009.

This report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to the attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this Annual Report.

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 December 31, 2009, 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.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Red Trail Energy has seven (7) governors. Each governor is elected to a three year term. The terms of the governors are staggered, so that the terms of two governors expire in one year (Group I), two expire the next year (Group II), and three expire the following year (Group III). The staggering of the terms of the governors commenced at the Annual Meeting of the members which was held on May 30, 2007, at which meeting two governors were elected to an initial one year term, two governors were elected to an initial two year term, and three governors were elected to an initial three year term. The governors’ seats, as voted on at the 2007 Annual Meeting, were assigned to a class as follows:

Group I: Jody Hoff and Ronald Aberle

Group II: Mike Appert and William Price

Group III: Tim Meuchel, Frank Kirschenheiter and Roger Berglund (now filled by Sid Mauch)

The initial two year term of the governors in Group II expired at the 2009 Annual Meeting and the Group II governor seats were filled via the election of Mr. Price and Mr. Appert for an additional three-year term. The initial three year term of governors in Group III expires at the 2010 Annual Meeting, and nominees elected at the 2010 Annual Meeting will serve for an additional three year term that will expire at the 2013 Annual Meeting. One Group III governor, Roger Berglund, resigned as a governor of the Company effective December 10, 2008. At a March 31, 2009 Board of Governors meeting, the Board filled Mr. Berglund’s seat by the appointment of Sid Mauch, who will serve the remainder of Mr. Berglund’s term.

GOVERNORS

Our Board of Governors

Our current Board of Governors consists of seven (7) governors. The names and ages of all of our governors and the positions held by each with the Company are as follows:

Name	Age	Position
Mike Appert	41	Governor, Chairman
William Price	47	Governor, Secretary
Jody Hoff	37	Governor, Vice Chairman
Frank Kirschenheiter	59	Governor, Treasurer
Tim Meuchel	51	Governor
Ronald Aberle	47	Governor
Sid Mauch	64	Governor

Identification of Governors

Mike Appert

Mr. Appert currently serves as the Chairman of the Board of Governors. He previously served as Secretary. He is a member of our Acquisition, Governance, Nominating and Risk Management Committees and has been a Governor since our inception.

Mr. Appert has been the owner and president of Appert Acres, Inc., a corn, soybean, sunflowers and small grains farming operation since 1991, as well as operating a Mycogen Seeds Dealership. He also serves on several boards which include the Hazelton Airport Authority as president, the Goose Lake Chapter Pheasants Forever as Treasurer and the Hazelton Lions Club.

William Price

Mr. Price has served as a Governor since our inception and is a member of our Acquisition Committee. He served as Vice President from inception of the Company until May 2007, and currently serves as Secretary and is the chairman of the Nominating Committee.

Since 1980, Mr. Price has been the managing partner and is currently vice president of Price Cattle Ranch LLP, a cattle operation. Since 1997, he has been the managing partner and is currently the president of Missouri River Feeders LLP, a feedlot and diversified farm. He also serves as a governor of Quality Dairy Growers, LLC, a dairy operation, and is a governor of Sunnyside Feeds, LLC, a custom feed plant. Mr. Price is also a governor of North Dakota Sow Center LLLP, a 10,000 head ISO wean facility. Mr. Price is a member of multiple associations, including the North Dakota Stockmen’s Association, the National Cattlemen’s Beef Association, and the Great Bend Irrigation District, and has served on the Missouri Slope Irrigation Board of Governors and served as Chairman of the North Dakota Feeder Council.

Jody Hoff

Mr. Hoff currently serves as Vice Chairman, has served as a Governor since our inception and serves as the chairman of our Audit Committee and is a member of our Acquisition, Compensation and Nominating Committees.

Mr. Hoff is a Mechanical Engineer, registered with the State of North Dakota. Since 2002, he has been a partner, vice president, chief engineer and head of operations of Amber Waves, Inc., a manufacturing company. Prior to starting Amber Waves, Inc., Mr. Hoff spent over five years working for Fagen Engineering where he led a design team working on commercial and industrial projects including ethanol plant design. Mr. Hoff holds a BS degree in mechanical engineering from North Dakota State University.

Frank Kirschenheiter

Mr. Kirschenheiter currently serves as Treasurer of the Board of Governors and is a member of our Audit Committee. He has been a Governor since May 2007.

Mr. Kirschenheiter has served as the chief executive officer of Charmark International, LLC since 2005. He and his wife Earlene are involved with their children in a small cattle operation. Mr. Kirschenheiter has served as the mayor of the City of Richardton for the past 14 years.

Tim Meuchel

Mr. Meuchel has been the president of Modern Grain, Inc., a grain elevator located in Hebron, North Dakota, since 1986. Mr. Meuchel currently serves as a member of the Governance, Acquisition and Risk Management. He has been a Governor since May 2007.

Ronald Aberle

Mr. Aberle has served as a Governor since our inception and is the chairman of our Nominating Committee and also serves as a member of our Audit, Acquisition, Compensation, Nominating and Risk Management Committees.

Mr. Aberle is an owner and managing partner of Aberle Farms, a diversified farm and ranch, and most recently added an RV Campground to the enterprise. Mr. Aberle serves as an Advisory Board member of U.S. Bank in Bismarck, North Dakota, and is a Trustee of St. Hildegards Church.

Sid Mauch

Mr. Mauch has served as a Governor since March 2009, replacing Roger Berglund, who resigned as a Governor of the Company in December 2008. He serves on our Risk Management committee.

Mr. Mauch has been the manager and controller of Maple River Grain & Agronomy, LLC, a grain elevator and agronomy supplier located in Casselton, North Dakota, since 1976.

There are no material proceedings to which any of our governors or executive officers or any associates of any of our governors or executive officers are a party adverse to us or have material interests adverse to us.

INFORMATION ABOUT OFFICERS

The names, ages, and positions of our executive officers are as follows:

Name	Age	Position
Calvin Diehl	49	Chief Executive Officer
Mark E. Klimpel	37	Chief Financial Officer

Calvin Diehl, Chief Executive Officer

Mr. Diehl was appointed Chief Executive Officer of the Company on January 1, 2010 and previously served as the Company’s Grain Merchandiser from December 2008 to December 2009. Prior to joining the Company, he was the General Manager for James Valley Grain, a grain elevator with shuttle car loading capabilities located in Oakes, North Dakota. Mr. Diehl was also previously employed as a field representative with Cenex Harvest States from June 1996 to June 2005. In his capacity as a field representative, Mr. Diehl consulted with various elevators on their financing, insurance and risk management needs.

Mark E. Klimpel, Chief Financial Officer

Mr. Klimpel is currently and has been since October 2007 the Chief Financial Officer for the Company. Prior to joining the Company, he worked for Knife River Corporation in Bismarck, North Dakota beginning in 1998. At Knife River he held various positions within the corporate accounting department and, most recently, was ERP Implementation Project Manager. Mr. Klimpel is a Certified Public Accountant with a Bachelors of Accountancy degree from the University of North Dakota, located in Grand Forks, North Dakota.

Mick Miller, Former Chief Executive Officer

Mr. Miller resigned his position as President and Chief Executive Officer of the Company effective on June 15, 2009, a position to which he was appointed in August 2006. From June 2005 to August 2006, he was the General Manager for the Company. Prior to joining the Company, he worked for Diversified Energy Company LLC (DENCO), an ethanol plant in Morris, Minnesota beginning in September 1999. At DENCO, Mr. Miller was Operations Supervisor from July 2000 through May 2002 and Plant Manager from May 2002 to June 2005. Mr. Miller also served as the Vice President of Operations for Greenway. Mr. Miller also represented the Company on the board of directors of RPMG, Inc. He has served since May 2005 to the present on the Advisory Board for the Process Plant Technology Program at Bismarck State College in Bismarck, North Dakota and has served on the board since October 2006 as the Vice President for the North Dakota Ethanol Producers Association.

Gerald Bachmeier, Former Interim Chief Executive Officer

Mr. Bachmeier was appointed Interim Chief Executive Officer effective on June 15, 2009. Mr. Bachmeier is also the Chief Manager of our management consulting company, Greenway, and is also the Company’s largest shareholder through his affiliation with RTSB, LLC. Under the terms of the Management Agreement, Greenway was responsible to provide the Company’s Chief Executive Officer and Plant Manager. Upon Mr. Miller’s resignation, Mr. Bachmeier assumed the duties of Chief Executive Officer pursuant to the terms of the Management Agreement until he was replaced by Mr. Diehl on January 1, 2010.

Mr. Bachmeier has been involved in the ethanol industry for the past eighteen years. He has served as a Plant Manager of Morris Ag Energy and Chief Marketing Manager of United Ethanol Sales. He was instrumental in the formation of DENCO, LLC and was the major role player for the acquisition of Morris Ag Energy. He was also instrumental in the design and construction of DENCO, LLC as it stands today. He is currently the Chief Manager of DENCO, LLC and Greenway and has held various board positions with many industry trade groups.

CORPORATE GOVERNANCE

Governor Independence

The Company has voluntarily adopted the NASDAQ Marketplace Rules for determining whether a governor is independent and our Board of Governors has determined that three (3) of our current seven (7) governors are “independent” within the meaning of Rule 4200(a)(15) of the NASDAQ Marketplace Rules. As a non-listed issuer, we are not required to comply with the NASDAQ Marketplace Rules, but have voluntarily adopted the Rule 4200(a)(15) definition. Our independent governors under the definition are Jody Hoff, Sid Mauch and Frank Kirschenheiter. None of our governors are officers. Mike Appert, Ron Aberle and Tim Meuchel are not considered independent because of their sales of corn to the Company. William Price is not considered independent because of his ownership in operations that purchase distillers grains from the Company. Transactions with our governors are based on the same terms and conditions as those that are available to the public. In evaluating the independence of our governors, we considered the following factors: (i) the business relationships of our governors; (ii) positions our governors hold with other companies; (iii) family relationships between our governor and other individuals involved with the Company; (iv) transactions between our governors and the Company; and (v) compensation arrangements between our governors and the Company.

Board Meetings and Committees; Annual Meeting Attendance

The Board of Governors generally meets once per month. The Board of Governors is directly responsible for governance of the Company. The Board held regular meetings on twelve (12) occasions in fiscal 2009; additionally the Board held six (6) special meetings. The Board has a standing acquisition committee, audit committee, compensation committee, governance committee, nominating committee, and risk management committee. Each governor attended 75% or more of the aggregate number of meetings of the Board and of committees of which he was a member.

Member Communication with the Board of Governors

Members seeking to communicate with the Board of Governors should submit their written comments to the Secretary of the Company, P.O. Box 11, 3682 Highway 8 South, Richardton, ND 58652. The Secretary will forward all such communications (excluding routine advertisements and business solicitations and communications which the Secretary, in his or her sole discretion, deems to be a security risk or for harassment purposes) to each member of the Board or, if applicable, to the individual governors(s) named in the correspondence.

Governor Attendance at Annual Meeting of Members

The Board of Governors does not have a policy with regard to governors’ attendance at annual meetings, but governors are encouraged to attend each Annual Meeting. All Board members were present at the 2009 Annual Meeting.

Code of Ethics

The Company has adopted a Code of Business Conduct that applies to all of our employees, officers and governors, and a Code of Ethics for Senior Financial Officers that applies to our Chief Executive Officer, Chief Financial Officer or Controller and other persons performing similar functions. The Code of Business Conduct and Code of Ethics are available on the Investors section of our website at http://redtrailenergyllc.com/investors. The Company intends to satisfy the disclosure requirements of Form 8-K involving an amendment to, or a waiver from, a provision of its code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, by posting such information on the Investors section of our website, located at http://redtrailenergyllc.com/investors, or in a current report on Form 8-K.

Audit Committee

The Audit Committee of the board of governors operates under a charter adopted by the board of governors on April 9, 2007. Under the charter, the Audit Committee must have at least three members. Our audit committee members are Mr. Hoff, Mr. Kirschenheiter and Mr. Aberle. The chairperson of the Audit Committee is Mr. Hoff. Our audit committee currently does not have an individual designated as a financial expert and has communicated this to the Nominating Committee for their consideration as they review potential nominees for the board of governors. The Audit Committee is exempt from the independence listing standards because the Company’s securities are not listed on a national securities exchange or listed in an automated inter-dealer quotation system of a national securities association or to issuers of such securities. Under NASDAQ rules 4200 and 4350, a majority of our Audit Committee is independent within the definition of independence provided by NASDAQ rules 4200 and 4350. In addition, our Audit Committee charter requires a majority of our committee members to be independent. A majority of the members of our Audit Committee is independent as required by our Audit Committee charter.

The Audit Committee held 6 meetings during the fiscal year ended December 31, 2009. All of our Audit Committee members attended at least 75% of the audit committee meetings.

Audit Committee Report

The Audit Committee delivered the following report to the board of governors of the Company on March 31, 2010. The following report of the Audit Committee shall not be deemed to be incorporated by reference in any previous or future documents filed by the Company with the Securities and Exchange Commission under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates the report by reference in any such document.

The Audit Committee reviews the Company’s financial reporting process on behalf of the board of governors. Management has the primary responsibility for the financial statements and the reporting process. The Company’s independent auditors are responsible for expressing an opinion on the conformity of the audited financial statements to generally accepted accounting principles. The Audit Committee reviewed and discussed with management the Company’s audited financial statements as of and for the fiscal year ended December 31, 2009. The Audit Committee has discussed with Boulay, Heutmaker, Zibell & Co. P.L.L.P., its independent auditors, the matters required to be discussed by ASU section 380 Communication with audit committees, as amended, by the Auditing Standards Board of the American Institute of Certified Public Accountants and as adopted by the Public Company Accounting Oversight Board in Rule 3200T. The Audit Committee has received and reviewed the written disclosures and the letter to management from Boulay, Heutmaker, Zibell & Co. P.L.L.P., as required by Independence Standards Board Standard No. 1, as adopted by the Public Company Accounting Oversight Board in Rule 3600T, and has discussed with the independent accountants the independent accountants’ independence. The Audit Committee has considered whether the provision of services by Boulay, Heutmaker, Zibell & Co. P.L.L.P., not related to the audit of the financial statements referred to above and to the reviews of the interim financial statements included in the Company’s Forms 10-Q, and concluded that the provision of such services is compatible with maintaining Boulay, Heutmaker, Zibell & Co. P.L.L.P’s independence.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of governors that the audited financial statements referred to above be included in the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2009.

Audit Committee

Jody Hoff, Frank Kirschenheiter, Ron Aberle

Compensation Committee

The Company's standing compensation committee consists of Jody Hoff and Ron Aberle, however, the Company’s board of governors has the overall responsibility for approving and evaluating the Company's governor and executive compensation plans, policies and programs. The compensation committee was formed primarily to review an employment agreement and make a recommendation to the board of governors on this matter. Neither the Company nor the compensation committee has historically engaged compensation consultants to assist in determining or recommending the amount or form of executive or governor compensation, but would consider doing so in those situations where either the Company or the compensation committee felt it was warranted or appropriate. The compensation committee did not hold any meetings during the fiscal year ended December 31, 2009.

The compensation committee does not operate under a charter. The compensation committee is exempt from the independence listing standards because the Company's securities are not listed on a national securities exchange or listed in an automated inter-dealer quotation system or a national securities association or to issuers of such securities.

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires the Company's officers and governors, and persons who own more than 10% of a registered class of the Company's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission. Officers, governors and greater than 10% percent Unit holders are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file. All of our Section 16(a) reporting persons timely filed reports during the fiscal year ended December 31, 2009, except that Jody Hoff and Gerald Bachmeier failed to file a Form 4 related to various transfers, which were later reported in a timely filed Form 5.

ITEM 11. EXECUTIVE COMPENSATION

EXECUTIVE OFFICER AND GOVERNOR COMPENSATION

Compensation Discussion and Analysis

The compensation committee has responsibility for establishing, implementing and regularly monitoring adherence to the Company’s compensation philosophy and objectives. The compensation committee ensures that the total compensation paid to the named Chief Executive Officer and Chief Financial Officer is fair, reasonable and competitive.

The compensation committee receives input from the Chief Executive Officer on his personal performance achievements and that of the employees who report to him. This individual performance assessment determines a portion of the annual compensation for the Chief Executive Officer.

The compensation committee does its own performance review of the Chief Executive Officer. The compensation committee annually evaluates the performance of our Chief Executive Officer in light of the Company’s goals and objectives and determines and approves the executive’s compensation level based on this evaluation.

Compensation Committee Report

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based upon this review and discussion, the board of governors determined that the Compensation Discussion and Analysis should be included in this annual report.

Compensation Committee

Jody Hoff, Ron Aberle, Mike Appert, William Price, Tim Meuchel, Sid Mauch, Frank Kirschenheiter

Governors’ compensation

The following table sets forth all compensation paid or payable by the Company during the 2009 fiscal year to our governors.

Name	Fees Earned or Paid in Cash		Total
Jody Hoff	$	1,000	$	1,000
Mike Appert	$	1,000	$	1,000
Ronald Aberle	$	900	$	900
William Price	$	1,000	$	1,000
Sid Mauch	$	8,400	$	8,400
Tim Meuchel	$	900	$	900
Frank Kirschenheiter	$	500	$	500

Our Board of Governors adopted a governor compensation policy on July 24, 2007. However, in December 2008, compensation was suspended on a voluntary basis and subsequently reinstated during January 2010. Pursuant to the governor compensation policy, we pay governor fees as follows:

$500.00 per Board meeting

$400.00 per audit committee meeting

$100.00 per meeting for all other committee meetings

The compensation policy also provides for reimbursement to governors for all out-of-pocket costs and mileage for travel to and from meetings and other locations to perform these tasks.

In the year ending December 31, 2009, the Company had incurred an aggregate of $13,700 in governor fees and related expenses.

The following table sets forth all compensation paid or payable by us during the last two fiscal years to our President and Chief Executive Officer, who functions as our principal executive officer, and our Chief Financial Officer, who functions as our principal financial and accounting officer (the “Named Executive Officers”). The Company has no other executive officers that received in excess of $100,000 during the fiscal years ended December 31, 2009 and 2008, respectively. While the Company does have a standing compensation committee, the main focus of that committee was to review and approve the employment agreement entered into with Mr. Klimpel during 2008. Prior to January 1, 2010, the Chief Executive Officer was an employee of Greenway Consulting, LLC, our management consulting company and was compensated pursuant to the terms of our Management Agreement with Greenway. The full board was involved in selecting and determining the compensation for Mr. Diehl who is an employee of the Company.

Summary Compensation Table
	Annual Compensation
Name and Principal Position	Year	Salary			Bonus			Stock Award			Total
Calvin Diehl(1)	2009	$	―		$	―		$	―		$	―
Chief Executive Officer	2008	$	―		$	―		$	―		$	―

Gerald Bachmeier(2)	2009	$	76,154		$	―		$	―		$	76,154
Former Chief Executive Officer	2008	$	―		$	―		$	―		$	―

Mick J. Miller(3)	2009	$	65,154		$	―		$	―		$	65,154
Former Chief Executive Officer	2008	$	135,000		$	―		$	15,000	(4)	$	150,000

Mark E Klimpel	2009	$	119,475	(7)	$	25,500	(6)	$	―		$	144,975
Chief Financial Officer	2008	$	116,327		$	3,087	(5)	$	―		$	119,414

(1)	Mr. Diehl was appointed Chief Executive Officer on January 1, 2010. Mr. Diehl is an employee of Red Trail Energy, LLC where our previous Chief Executive Officer’s have been employees of our management company – Greenway Consulting, LLC (“Greenway”). His salary for 2010 has been set at $116,000.

(2)	Mr. Bachmeier was appointed interim Chief Executive Officer on June 15, 2009 and was compensated pursuant to the Management Agreement with Greenway. Mr. Bachmeier resigned his position as CEO on December 31, 2009.

(3)	Mr. Miller resigned his position as CEO effective June 15, 2009. Mr. Miller was compensated pursuant to our Management Agreement with Greenway.

(4)

On September 8, 2006, Mr. Miller was awarded an equity based, incentive compensation award of up to 150,000 Units, effective as of July 7, 2005, the date he formally began working in the role of General Manager (the “Grant Date”). The first 15,000 Units vested on July 1, 2008. All remaining unvested Units were lost upon Mr. Miller’s resignation.

(5)	Bonus reflects payment from the employee bonus program for the first quarter of fiscal 2008. Mr. Klimpel ceased participation in the employee bonus program upon executing his employment agreement with the Company in August 2008.

(6)	Paid pursuant to the terms of Mr. Klimpel’s employment agreement – see additional information below under “Employment Agreements.” This reflects payment for 2008 and 2009.

(7)	Mr. Klimpel voluntarily took a salary reduction at the beginning of 2009 so the increase in base salary does not equal 6%.

EMPLOYMENT AGREEMENTS

As disclosed in footnotes 2 and 3 to the Summary Compensation Table, Mick Miller and Gerald Bachmeier, both of whom served as our former Chief Executive Officer, were compensated pursuant to our Management Agreement with Greenway, executed in December 2003 and Amended and Restated during 2009. The original Management Agreement provided that the Company would reimburse Greenway for the salary and benefit package of the Chief Executive Officer, in addition to a monthly payment to Greenway for management of plant operations. The Amended and Restated Management Agreement now allows the Company the flexibility to hire its own Chief Executive Officer.

Mark Klimpel, our Chief Financial Officer, executed a written employment agreement with the Company in August 2008. The agreement provides that Mr. Klimpel’s base salary shall increase at a rate of six percent per year, and that Mr. Klimpel is eligible for a bonus of 20 percent of base salary per year, which bonus is based 50% on remaining employed with the Company and 50% on a performance determination by the Compensation Committee of the Board in consultation with the President and Chief Executive Officer. The Agreement also provides that if Mr. Klimpel is terminated by the Company without cause or because of a change-in-control, Mr. Klimpel is entitled to unpaid base salary and benefits up to the date of termination, and six months salary thereafter.

The Company recently announced that Mr. Klimpel has resigned his position as the Company’s Chief Financial Officer effective May 13, 2010. Pursuant to the terms of Mr. Klimpel’s employment agreement, the Company is required to pay any accrued salary and benefits through the effective date of the resignation.

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

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED MEMBER MATTERS

The following table sets forth certain information concerning the beneficial ownership of persons known to management of the Company owning 5% or greater of the outstanding Class A Membership Units, based on 40,193,973 Units outstanding as of March 15, 2010, as follows:

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
RTSB, LLC		2,619,500	(1)		6.52	%
3150 136th Avenue NE
Baldwin, ND 58521

(1)	RTSB, LLC is a limited liability company, whose members have direct beneficial ownership of all of the Units. Mr. Bachmeier was our interim Chief Executive Officer from June 15, 2009 through December 31, 2009 and is a principal owner in RTSB, LLC.

The Named Executive Officers, including our former CEO’s who served the Company during our fiscal year ended December 31, 2009, and the Governors own the following number of Class A Membership Units as of March 15, 2010, based on 40,193,973 Membership Units outstanding, as follows:

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
Mick J. Miller		67,500	(1)		*
Mark E. Klimpel		0			*
William A. Price		400,000	(2)		*
Calvin Diehl		0			*
Tim Meuchel		1,020,000	(3)		2.54	%
Frank Kirschenheiter		100,000	(4)		*
Ron Aberle		372,920	(5)		*
Mike Appert		1,095,000	(6)		2.72	%
Jody Hoff		437,241	(7)		1.09	%
Gerald Bachmeier		2,619,500	(8)		6.52	%
Sid Mauch		1,000			*
Officers/Governors as a Group (9 persons)		6,113,161			15.21	%

*	Designates less than one percent ownership.

(1)	Includes 30,000 Units which Mr. Miller holds beneficially in his IRA account. As mentioned above, Mr. Miller served as the Company’s President and Chief Executive Officer until June 15, 2009.

(2)	Includes 300,000 Units which Mr. Price owns jointly with his brother and 100,000 Units held jointly with his brother and mother.

(3)	Includes 110,000 Units indirectly held by Mr. Meuchel for the benefit of his son, and 200,000 Units owned by Mr. Meuchel’s spouse of which Mr. Meuchel disclaims beneficial ownership.

(4)	Includes 37,500 Units which are held by Richardton Investments, LLC, of which Mr. Kirschenheiter is a partial owner.

(5)	Includes 160,000 Units held jointly with Mr. Aberle’s spouse and 12,920 held beneficially in Mr. Aberle’s IRA account. Additionally, 200,000 Units are held by Aberle Farms of which Mr. Aberle is a partner and of which Mr. Aberle disclaims beneficial ownership.

(6)

Includes 375,000 Units which Mr. Appert owns jointly with his spouse and 100,000 Units held directly by his son of which Mr. Appert disclaims beneficial ownership. Additionally, 160,000 Units are held by Appert Acres, Inc., of which Mr. Appert is a partial owner and of which Mr. Appert disclaims beneficial ownership and 160,000 Units are held by Appert Farms, Inc., of which Mr. Appert is a partial owner and of which Mr. Appert disclaims beneficial ownership.

(7)	Includes 20,000 Units owned jointly with Mr. Hoff’s spouse. Additionally, 417,241 Units are held by Richardton Investments, LLC, of which Mr. Hoff is a partial owner and of which Mr. Hoff disclaims beneficial ownership.

(8)	Includes 2,619,500 Units owned by RTSB, LLC of which Mr. Bachmeier is a principal owner and of which Mr. Bachmeier disclaims beneficial ownership. As mentioned above, Mr. Bachmeier served as the Company’s interim Chief Executive Officer from June 15, 2009 through December 31, 2009.

EQUITY COMPENSATION PLAN INFORMATION

With the departure of Mr. Miller and Mr. Thomas, the Company’s former plant manager, the Company no longer has any equity compensation plans in place.

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

TRANSACTIONS WITH RELATED PERSONS, PROMOTERS AND CERTAIN CONTROL PERSONS

The Board has adopted a policy requiring all governors, officers and employees, and their immediate family members to notify the Board about any transaction, of any size, with the Company. Some of our governors, officers and employees and their immediate family members have sold corn to the Company or purchased distillers grains from the Company. These purchases and sales were made on terms available to all parties that do business with the Company, and were as follows for the last two fiscal years.

Ron Aberle, a governor, and a company owned in part by Mr. Aberle, sold corn to the Company in an amount equal to $537,616 and $677,760 during the years ended December 31, 2009 and 2008, respectively.

Mike Appert, a governor, and a company owned in part by Mr. Appert, sold corn to the Company in an amount equal to $2,116,091 and $2,183,781 during the years ended December 31, 2009 and 2008, respectively.

Tim Meuchel, a governor, and a company owned in part by Mr. Meuchel, sold corn and provided trucking services to the Company in an amount equal to $1,690,775 and $4,637,594 during the years ended December 31, 2009 and 2008, respectively.

William Price, a governor, and a company owned in part by him, purchased distillers grains from the Company in an amount equal to $12,386 and $381,693 during the years ended December 31, 2009 and 2008, respectively. Another company owned in part by Mr. Price sold corn to the Company in an amount equal to $299,760, $0 during the years ended December 31, 2009 and 2008, respectively.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Auditors’ Fees

Boulay, Heutmaker, Zibell & Co., P.L.L.P. billed the Company the following amounts for services provided during fiscal 2009 and 2008:

	2009		2008
Audit Fees	$	98,879	$	113,737
Audit-Related Fees		957		21,274
Tax Fees		0		0
All Other Fees		25,908		96
Total Fees	$	125,774	$	135,107

•

Audit Fees. This category includes the fees and out-of-pocket expenses for professional services rendered by the principal accountant for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Form 10-Q or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements.

•

Audit-Related Fees. Audit related fees relate to assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under the above item.

•

Tax Fees. This category consists of fees for tax compliance, tax advice and tax planning.

•

All Other Fees. This category consists of fees for other non-audit services.

The Board of Governors is required to pre-approve all audit and non-audit services performed by the Company’s independent auditor to assure that the provision of such services does not impair the auditor’s independence. The Board will not authorize the independent auditor to perform any non-audit service which independent auditors are prohibited from performing under the rules and regulations of the Securities and Exchange Commission or the Public Company Accounting Oversight Board. The Board may delegate its pre-approval authority to one or more of its governors, but not to management. The governor or governors to whom such authority is delegated shall report any pre-approval decisions to the Board at its next scheduled meeting.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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

(1) Financial Statements

An index to the financial statements included in this Report appears at page F-1. The financial statements appear beginning at page F-3 of this Annual 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


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**		Management Agreement made and entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.2 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.3		Development Services Agreement entered into as of December 17, 2003 by and between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as Exhibit 10.3 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.4		The Burlington Northern and Santa Fe Railway Company Real Estate Purchase and Sale Agreement with Red Trail Energy, LLC, dated January 14, 2004. Filed as Exhibit 10.4 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.


10.5		Warranty Deed made as of January 13, 2005 between Victor Tormaschy and Lucille Tormaschy, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.8 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.


10.6		Warranty Deed made as of July 11, 2005 between Neal C. Messer and Bonnie M. Messer, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as Grantee. Filed as Exhibit 10.9 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.7		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.

10.8+		Lump Sum Design-Build Agreement between Red Trail Energy, LLC, and Fagen, Inc. dated August 29, 2005. Filed as Exhibit 10.12 to the registrant’s registration statement on Form 10-12G/A-3 (000-52033) and incorporated by reference herein.

10.9		Construction Loan Agreement dated as of the December 16, 2005 by and between Red Trail Energy, LLC, and First National Bank of Omaha. Filed as Exhibit 10.14 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.10		Construction Note for $55,211,740.00 dated December 16, 2005, between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.15 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.11		International Swap Dealers Association, Inc. Master Agreement dated as of December 16, 2005, signed by First National Bank of Omaha and Red Trial Energy, LLC. Filed as Exhibit 10.18 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.12		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.

10.13		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.

10.14		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.

10.15		Loan Agreement between Greenway Consulting, LLC, and Red Trail Energy, LLC, dated February 26, 2006. Filed as Exhibit 10.22 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.16		Promissory Note for $1,525,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to Greenway Consulting, LLC. Filed as Exhibit 10.23 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.17		Loan Agreement between ICM Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.24 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.18		Promissory Note for $3,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to ICM Inc. Filed as Exhibit 10.25 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.19		Loan Agreement between Fagen, Inc. and Red Trail Energy, LLC, dated February 28, 2006. Filed as Exhibit 10.26 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.20		Promissory Note for $1,000,000.00, dated February 28, 2006, given by Red Trail Energy, LLC, to Fagen, Inc. Filed as Exhibit 10.27 to the registrant’s registration statement on Form 10-12G (000-52033) and incorporated by reference herein.

10.21		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.

10.22		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.

10.23		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.

10.24		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.

10.25		First Amendment to Construction Loan Agreement dated August 16, 2006 by and between Red Trail Energy, LLC and First National Bank of Omaha. Filed as Exhibit 10.32 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.

10.26		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.

10.27**		Equity Grant Agreement dated September 8, 2006 by and between Red Trail Energy, LLC and Mickey Miller. Filed as Exhibit 10.35 to our Annual Report on Form 10-K for the year ended December 31, 2006. (000-52033) and incorporated by reference herein.

10.28		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.

10.29		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.

10.30		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.

10.31		Long Term Revolving Note for $10,000,000, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by reference herein.

10.32		Variable Rate Note for $17,065,870, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033).

10.33		Fixed Rate Note for $27,605,870, dated April 16, 2007 between Red Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed as Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by reference herein.

10.34		$3,500,000 Revolving Promissory Note given by the Company to First National Bank of Omaha dated July 18, 2007. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (000-52033) and incorporated by reference herein.

10.35		Second Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated July 18, 2007. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (000-52033) and incorporated by reference herein.

10.36		Third Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated November 15, 2007. Filed as Exhibit 10.38 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.

10.37		Fourth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007. Filed as Exhibit 10.39 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.

10.38		Interest Rate Swap Agreement by and between the Company and First National Bank of Omaha dated December 11, 2007. Filed as Exhibit 10.40 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.

10.39		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.

10.40		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.

10.41		Coal Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal Sales Company dated December 5, 2007. Filed as Exhibit 10.43 to our Annual Report on Form 10-K for the year ended December 31, 2007 (000-52033) and incorporated by reference herein.

10.42		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.

10.43		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.

10.44		$3,500,000 Revolving Promissory Note given by the Company to First National Bank of Omaha dated July 19, 2008. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (000-52033) and incorporated by reference herein.

10.45		Fifth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated July 19, 2008. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (000-52033) and incorporated by reference herein.

10.46**		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.

10.47		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.

10.48		Sixth Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha effective date April 16, 2009. Filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 2, 2009 (000-52033) and incorporated by reference herein.

10.49+		Coal Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal Sales Company dated November 5, 2009. Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (000-52033) and incorporated by reference herein.

10.50**		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.

10.51*		Seventh Amendment to Construction Loan Agreement by and between the Company and First National Bank of Omaha dated March 1, 2010.

31.1*		Certification by Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).

31.2*		Certification by Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934).

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

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

+	Confidential treatment has been requested and obtained with respect to certain portions of this exhibit. Omitted portions have been filed separately with the Securities and Exchange Commission.

*	Filed herewith.

**	Management contract or compensatory plan or arrangement.

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.


		/s/ Calvin Diehl
Date: March 31, 2010		Calvin Diehl
		Chief Executive Officer
		(Principal Executive Officer)

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

		/s/ Calvin Diehl
Date: March 31, 2010		Calvin Diehl
		President and Chief Executive Officer
		(Principal Executive Officer)

		/s/ Mark E. Klimpel
Date: March 31, 2010		Mark E. Klimpel
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

Date: March 31, 2010		/s/ Mike Appert
		Mike Appert, Chairman of the Board

Date: March 31, 2010		/s/ William A. Price
		William A. Price, Secretary and Governor

		/s/ Ron Aberle
Date: March 31, 2010		Ron Aberle, Governor

		/s/ Jody Hoff
Date: March 31, 2010		Jody Hoff, Vice Chairman and Governor

		/s/ Frank Kirschenheiter
Date: March 31, 2010		Frank Kirschenheiter, Treasurer and Governor

		/s/ Sid Mauch
Date: March 31, 2010		Sid Mauch, Governor

Financial Statements

C O N T E N T S


	Page
Report of Independent Registered Public Accounting Firm		F-2

Financial Statements

Balance Sheet		F-3

Statement of Operations		F-4

Statement of Changes in Members’ Equity		F-5

Statement of Cash Flows		F-6

Notes to Financial Statements		F-7 -20

F-1

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 December 31, 2009 and 2008, and the related statements of operations, changes in members’ equity, and cash flows for each of the years in a three-year period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audits 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 provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Red Trail Energy, LLC as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in a three-year period ended December 31, 2009 in conformity with U.S. generally accepted accounting principles.

/s/ Boulay, Heutmaker, Zibell & Co. PLLP

Certified Public Accountants

Minneapolis, Minnesota

March 31, 2010

F-2

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

Balance Sheet

December 31,	2009		2008
ASSETS
Current Assets
Cash and equivalents	$	13,214,091	$	4,433,839
Restricted cash - collateral		750,000	―
Restricted cash - margin account		1,467,013		1,498,791
Accounts receivable		2,635,775		2,697,695
Derivative instruments, at fair value		129,063	―
Inventory		6,993,031		3,353,592
Prepayments of corn purchases	―			4,398,046
Prepaid expenses		195,639		41,767
Total current assets		25,384,612		16,423,730

Property, Plant and Equipment
Land		351,280		351,280
Plant and equipment		79,199,850		79,898,657
Land improvements		3,970,500		3,939,294
Buildings		5,312,995		5,312,995
Construction in progress	―			33,679
		88,834,625		89,535,905

Less accumulated depreciation		17,419,043		11,525,863
Net property, plant and equipment		71,415,582		78,010,042

Other Assets
Debt issuance costs, net of amortization	―			567,385
Investment in RPMG		605,000		605,000
Patronage equity		192,207		116,296
Deposits		80,000		80,000
Total other assets		877,207		1,368,681

Total Assets	$	97,677,401	$	95,802,453

LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
Current maturities of long-term debt	$	6,500,000	$	49,063,201
Accounts payable		7,605,302		5,720,764
Accrued expenses		2,634,534		1,845,101
Derivative instruments, at fair value		806,490		1,051,052
Accrued loss on firm purchase commitments		―		1,426,800
Interest rate swaps, at fair value		2,360,686		2,861,530
Total current liabilities		19,907,012		61,968,448

Other Liabilities
Contracts payable		275,000		275,000

Long-Term Debt		43,620,025	―

Commitments and Contingencies

Members' Equity		33,875,364		33,559,005

Total Liabilities and Members' Equity	$	97,677,401	$	95,802,453

F-3

Statement of Operations

Years ended December 31,	2009		2008			2007

Revenues
Ethanol, net of derivative activity	$	77,700,414	$	111,086,858		$	90,100,581
Distillers grains		16,136,247		20,816,656			11,785,388
Total Revenues		93,836,661		131,903,514			101,885,969

Cost of Goods Sold
Cost of goods sold		80,376,609		121,042,965			81,358,010
Loss on firm purchase commitments		169,000		3,470,110			―
Lower of cost or market adjusment for inventory on hand		1,464,500		771,200			―
Depreciation		5,840,760		5,740,963			5,655,198
Total Cost of Goods Sold		87,850,869		131,025,238			87,013,208

Gross Margin		5,985,792		878,276			14,872,761

General and Administrative		2,812,891		2,857,091			3,214,002

Operating Income (Loss)		3,172,901		(1,978,815	)		11,658,759

Interest Expense		3,988,916		6,013,299			6,268,707

Other Income, net		1,176,675		2,625,542			767,276

Net Income (Loss)	$	360,660	$	(5,366,572	)	$	6,157,328

Weighted Average Units Outstanding - basic		40,191,494		40,176,974			40,371,238
Weighted Average Units Outstanding - diluted		40,191,494		40,176,974			40,416,238
Net Income (Loss) Per Unit - basic	$	0.01	$	(0.13	)	$	0.15
Net Income (Loss) Per Unit - diluted	$	0.01	$	(0.13	)	$	0.15

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

F-4

Statement of Changes in Members’ Equity

Years Ended December 31, 2009, 2008 and 2007

	Class A Member Units					Additional Paid			Accumulated			Treasury Units						Total Members'
	Units (a)			Amount		in Capital			Deficit			Units			Amount			Equity

Balance - January 1, 2007		40,373,973		$	37,810,408	$	56,825		$	(4,938,145	)		―		$	―		$	32,929,088

Unit-based compensation		―			―		45,000			―			―			―			45,000
Treasury units repurchased
$1.13 per unit, December 2007		(200,000	)		―		―			―			200,000			(227,933	)		(227,933	)
Net Income		―			―		―			6,157,328			―			―			6,157,328

Balance - December 31, 2007		40,173,973			37,810,408		101,825			1,219,183			200,000			(227,933	)		38,903,483

Unit-based compensation		―			―		20,000			―			―			―			20,000
Units issued under compensation
agreement		15,000			―		(15,000	)					(15,000	)		17,094			2,094
Net Loss		―			―		―			(5,366,572	)		―			―			(5,366,572	)

Balance - December 31, 2008		40,188,973			37,810,408		106,825			(4,147,389	)		185,000			(210,839	)		33,559,005

Unit-based compensation		―			―		(55,000	)		―			―			―			(55,000	)
Units issued under compensation
agreement		5,000			―		5,000						(5,000	)		5,699			10,699
Net Income		―			―		―			360,660			―			―			360,660

Balance - December 31, 2009		40,193,973		$	37,810,408	$	56,825		$	(3,786,729	)		180,000		$	(205,140	)	$	33,875,364

(a) - Amounts shown represent member units outstanding. Authorized and issued units were 40,373,973 as of the end of each period presented

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

F-5

RED TRAIL ENERGY, LLC

Statements of Cash Flows

Years ended December 31,	2009			2008			2007
Cash Flows from Operating Activities
Net income (loss)	$	360,660		$	(5,366,572	)	$	6,157,328
Adjustment to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depreciation		5,893,180			5,796,805			5,713,042
Amortization and write-off of debt issuance costs		567,385			201,020			214,169
Change in fair value of derivative instruments		(373,625	)		1,238,979			(2,870,449	)
Change in fair value of interest rate swap		490,619			2,266,371			894,256
Equity-based compensation		3,334			22,094			20,000
Equity-based compensation non-cash write-off		(52,635	)		―			―
Non-cash patronage equity		(75,911	)		(116,296	)		―
Grant income applied to long-term debt		―			(59,874	)		―
Changes in assets and liabilities
Restricted cash - margin account		31,778			1,504,072			―
Accounts receivable		61,920			3,262,346			(5,960,041	)
Inventory		(3,639,439	)		4,943,764			(4,341,227	)
Prepaid expenses		4,244,174			(4,386,402	)		10,371
Accounts payable		2,053,648			(1,130,676	)		2,603,723
Accrued expenses		789,433			(657,835	)		204,461
Accrued loss on firm purchase commitments		(1,426,800	)		1,426,800			―
Net settlements on derivative instruments		(991,463	)		(449,032	)		39,000
Net cash provided by operating activities		7,936,258			8,495,564			2,684,633
Cash Flows from Investing Activities
Investment in RPMG		(169,110	)		(435,890	)		―
Refund of sales tax on property, plant and equipment		763,630			―			―
Capital expenditures		(62,350	)		(1,864,305	)		(3,974,839	)
Net cash provided by (used in) investing activities		532,170			(2,300,195	)		(3,974,839	)
Cash Flows from Financing Activities
Debt repayments		(2,516,684	)		(10,153,739	)		(1,813,376	)
Proceeds from long-term debt		3,573,508			160,500			11,141,502
Restricted cash - collateral		(750,000	)		―			―
Treasury units issued		5,000			―			(227,933	)
Net cash provided by (used in) financing activities		311,824			(9,993,239	)		9,100,193

Net Increase (Decrease) in Cash and Equivalents		8,780,252			(3,797,870	)		7,809,987
Cash and Equivalents - Beginning of Period		4,433,839			8,231,709			421,722
Cash and Eqivalents - End of Period	$	13,214,091		$	4,433,839		$	8,231,709

Supplemental Disclosure of Cash Flow Information
Interest paid net of swap settlements	$	3,026,980		$	4,404,790		$	4,119,744

SUPPLEMENT DISCLOSURE OF NON-CASH
INVESTING AND FINANCING ACTIVITIES

Investments included in accounts payable	$	―		$	169,110		$	―

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

F-6

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 production ethanol plant near Richardton, North Dakota. The Plant commenced production on January 1, 2007. Fuel grade ethanol and distillers grains are the Company’s primary products. Both products are marketed and sold primarily within the continental United States.

Fiscal Reporting Period

The Company adopted a fiscal year ending December 31 for reporting financial operations.

Use of Estimates

The preparation of the financial statements, in accordance with generally accepted principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Significant items subject to such estimates and assumptions include the useful lives of property, plant and equipment; valuation of derivatives, inventory, patronage equity and purchase commitments; analysis of intangibles impairment, the analysis of long-lived assets impairment and other contingencies. Actual results could differ from those estimates.

Reclassifications

The presentation of certain items in the financial statements for the years ended December 31, 2008 and 2007 have been changed to conform to the classifications used in 2009. The reclassifications had no effect on members’ equity, net income (loss) or operating cash flows as previously reported.

Restricted Cash

During June 2009, the Company was required to restrict cash for use as collateral on two letters of credit issued in relation to its distilled spirits and grain warehouse bonds. As of December 31, 2009 and 2008, the total amount of restricted cash related to these bonds was $750,000 and $0, respectively. The Company also had restricted cash to meet its derivative hedge account requirements. The total amount of cash restricted in its hedge account at December 31, 2009 and 2008 was approximately $1.5 million.

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 the fair value. The Company has money market funds in cash equivalents at December 31, 2009 and 2008.

The Company maintains its accounts at various financial institutions. At times throughout the year, the Company’s cash and equivalents balances may exceed amounts insured by the Federal Deposit Insurance Corporation.

Accounts Receivable and Concentration of Credit Risk

The Company generates accounts receivable from sales of ethanol and distillers grains. The Company has entered into agreements with RPMG, Inc. (“RPMG”) and CHS, Inc. (“CHS”) for the marketing and distribution of the Company’s ethanol and dried distillers 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 wet distillers grains internally.

The Company is substantially dependent upon RPMG for the purchase, marketing and distribution of the Company’s ethanol. RPMG purchases 100% of the ethanol produced at the Plant, all of which is marketed and distributed to its customers. Therefore, the Company is highly dependent on RPMG for the successful marketing of the Company’s ethanol. In the event that the Company’s relationship with RPMG is interrupted or terminated for any reason, the Company believes that another entity to market the ethanol could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale and production of ethanol and adversely affect the Company’s business and operations. Amounts due from RPMG represent approximately 77% and 61% of the Company’s outstanding receivable balance as of December 31, 2009 and 2008, respectively.

The Company is substantially dependent on CHS for the purchase, marketing and distribution of the Company’s dried distillers grains. CHS purchases 100% of the dried distillers grains produced at the Plant, all of which are marketed and distributed to its customers. Therefore, the Company is highly dependent on CHS for the successful marketing of the Company’s dried distillers grains. In the event that the Company’s relationship with CHS is interrupted or terminated for any reason, the Company believes that another entity to market the dried distillers grains could be located. However, any interruption or termination of this relationship could temporarily disrupt the sale of dried distillers grains and adversely affect the Company’s business and operations.

F-7

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

For sales of wet distillers 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. There was no allowance for doubtful accounts at December 31, 2009 or December 31, 2008.

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 to the Company at a future date. Because these patronage dividends are in return for the Company’s current purchases, the Company records the value of these future payments using a discounting approach that incorporates interest and collection risk factors.

Derivative Instruments

The Company enters into derivative transactions to hedge its exposure to commodity 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. Changes in the fair value of undesignated derivatives related to ethanol are recorded in revenue.

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. As of December 31, 2009 and 2008 the Company has no derivatives instruments that meet this criterion.

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.

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 plant and equipment. Amortization of equipment under capital leases is included in depreciation expense.

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.

F-8

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

Indefinite lived intangible assets are reviewed for impairment at least annually and if events or changes in circumstances indicate that the carrying amount of the indefinite lived intangible may not be recoverable.

Debt Issuance Costs

Debt issuance costs were amortized over the term of the related debt by use of the effective interest method. Amortization commenced June 2006 when the Company began drawing on the related bank loan. Due to uncertainties with our loan agreements, the Company wrote off the remaining balance (approximately $517,000) of its debt issuance costs during the first quarter of 2009. Amortization and impairment expense totaled $567,000 and $201,000 for the years ended December 31, 2009 and 2008, respectively. These amounts are included in interest expense.

Fair Value of Financial Instruments

The fair value of the Company’s cash and equivalents, accounts receivable, accounts payable, and derivative instruments approximate their carrying value. The Company evaluated the fair value of its long-term debt at December 31, 2009 and 2008 and the fair value approximated the carrying value (see Note 6 for additional information).

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.

Grant income received for incremental expenses that otherwise would not have been incurred is netted against the related expenses.

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.

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 adopted guidance for accounting for uncertainty in income taxes on January 1, 2007. As a result of the adoption of this guidance, the Company has evaluated whether they have 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.

Equity-Based Compensation

The Company recognizes the related costs under these agreements using the straight-line attribution method over the grant period and the grant date fair value unit price. As of June 30, 2009, the personnel covered by the Plan had either left employment or given notice that they were going to leave employment. Leaving employment resulted in these employees forfeiting the award and prior recognized equity-based compensation expense related to these grants were reversed through compensation expense during the three months ended June 30, 2009. During June 2009, 5,000 units were issued under the terms of the Plan.

During 2007, the Company exercised an option to repurchase 200,000 Units in association with this Plan. 180,000 Units are still held in treasury and will not be issued under the Plan. While the Company does not have any other equity-based compensation plans currently in place, these Units could be used for that purpose in the future. Equity-based compensation expense was $(-53,334) and $22,000 for the years ended December 31, 2009 and 2008, respectively. As of December 31, 2009, the total equity-based compensation expense related to nonvested awards not yet recognized was $0.

F-9

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

Earnings (Loss) Per Unit

Basic earnings (loss) per unit is calculated by dividing net earnings (loss) by the weighted average units outstanding during the period. Fully diluted earnings per unit is calculated by dividing net earnings by the weighted average member units and member unit equivalents outstanding during the period. For 2009, 2008, and 2007, the Company had 0, 50,000 and 45,000 member unit equivalents, respectively. For 2008, member unit equivalents were not included in diluted equivalents outstanding as their effect is anti-dilutive.

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. No such liabilities have been identified as of December 31, 2009 and 2008.

Going Concern and Management’s Plans

Certain factors existed as of December 31, 2008 that raised substantial doubt about the Company’s ability to continue as a going concern. These included poor market conditions, negative operating cash flows and past and projected violations of its loan covenants that had not been waived by its Bank. Those uncertainties have been removed as of December 31, 2009 as market conditions have improved, the Company has negotiated favorable amendments to its loan agreements, the Company has regained compliance with its loan covenants and has received waivers for all past covenant violations. In addition, the Company projects that it will be able to meet its covenants throughout 2010, based on market conditions as of March 2010 along with its assumptions about future market conditions. Our projections assume slight improvement in the spread between ethanol and corn prices during the last six months of 2010 as we anticipate that the current oversupply situation will be mitigated, in part, by an increase in gasoline demand through the summer driving season and more discretionary blending due to the significant favorable spread that currently exists between gasoline and ethanol prices (when ethanol prices are lower than gasoline prices, blenders have an incentive to blend more ethanol into gasoline). Based on this information, the Company’s long-term debt has been reclassified as a non-current liability as of December 31, 2009 with only the portion due within one year shown as current.

2. CONCENTRATIONS

Coal

Coal is an important input to our manufacturing process. During the fiscal year ended December 31, 2009, we used approximately 88,800 tons of coal. We have entered into a new two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2011. Whether the Plant runs long-term on lignite or PRB coal, there can be no assurance that the coal we need will always be delivered as we need it, that we will receive the proper size or quality of coal or that our coal combustor will always work properly with lignite or PRB coal. Any disruption could either force us to reduce our operations or shut down the Plant, both of which would reduce our revenues.

In addition to coal, we could use natural gas as a fuel source if our coal supply is significantly interrupted. There is a natural gas line within three miles of our Plant and we believe we could contract for the delivery of enough natural gas to operate our Plant at full capacity. Natural gas tends to be significantly more expensive than coal and we would also incur significant costs to adapt our power systems to natural gas. Because we are already operating on coal, we do not expect to need natural gas unless coal interruptions impact our operations.

Sales

F-10

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

3. DERIVATIVE INSTRUMENTS

From time to time the Company enters into derivative transactions to hedge its exposures to interest rate and commodity price fluctuations. The Company does not enter into derivative transactions for trading purposes.

The Company provides qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses from derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements.

As of December 31, 2009, the Company had entered into interest rate swap agreements along with corn and ethanol derivative instruments. The Company records its derivative financial instruments as either assets or liabilities at fair value in the statement of financial position. Derivatives qualify for treatment as hedges when there is a high correlation between the change in fair value of the derivative instrument and the related change in value of the underlying hedged item. Based upon the exposure being hedged, the Company designates its hedging instruments as a fair value hedge, a cash flow hedge, a hedge against foreign currency exposure or leaves them undesignated. The Company formally documents, designates, and assesses the effectiveness of transactions that receive hedge accounting initially and on an on-going basis. The Company does not currently have any derivative instruments that are designated as effective hedging instruments for accounting purposes.

Commodity Contracts

As part of its hedging strategy, the Company may enter into ethanol and corn commodity-based derivatives in order to protect cash flows from fluctuations caused by volatility in commodity prices and protect gross profit margins from potentially adverse effects of market and price volatility on ethanol sales and corn purchase commitments where the prices are set at a future date. 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:	December 31, 2009						December 31, 2008
Contract Type	# of Contracts	Notional Amount (Qty)			Fair Value		# of Contracts	Notional Amount (Qty)			Fair Value
Corn futures	82	410,000	bushels	$	129,063		404	2,021,500	bushels	$	(1,051,052	)
Ethanol swap contracts	530	7,632,000	gallons		(806,490	)	―	―	gallons		―
Total fair value				$	(677,427	)				$	(1,051,052	)
Amounts are recorded separately on the balance sheet - negative numbers represent liabilties

None of the commodity contracts in place at December 31, 2009 and 2008 were designated as effective hedges for accounting purposes. As such, the change in fair value of the commodity contracts in place at December 31, 2009 and 2008 have been recorded in the results of operations and classified as stated above.

Interest Rate Contracts

The Company manages its floating rate debt using interest rate swaps. The Company has entered into fixed rate swaps to alter its exposure to the impact of changing interest rates on its results of operations and future cash outflows for interest. Fixed rate swaps are used to reduce the Company’s risk of the possibility of increased interest costs. Interest rate swap contracts are therefore used by the Company to separate interest rate risk management from the debt funding decision.

At December 31, 2009 and 2008, the Company had approximately $30.8 million and $33.8 million, respectively, of notional amount outstanding in swap agreements that exchange variable interest rates (one-month LIBOR and three-month LIBOR) for fixed interest rates over the terms of the agreements. The fair value of the interest rate swaps is included in current liabilities and totaled approximately $2.4 million and $2.9 million as of December 31, 2009 and 2008, respectively. These agreements are not designated as an effective hedge for accounting purposes and the change in fair market value and associated net settlements are recorded in interest expense. The swaps mature in April 2012.

Net settlements on the interest rate swaps are recorded in interest expense. Please see Note 5 for detail on the amount of the net settlements.

F-11

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

The following tables provide details regarding the Company’s derivative financial instruments at December 31, 2009 and 2008:

Derivatives not designated as hedging instruments for accounting purposes

Balance Sheet - as of December 31, 2009	Asset			Liability
Derivative instruments, at fair value		$	129,063		$	806,490
Interest rate swaps, at fair value			―			2,360,686
Total derivatives not desingated as hedging instruments for accounting purposes		$	129,063		$	3,167,176

Balance Sheet - as of December 31, 2008	Asset			Liability
Derivative instruments, at fair value		$	―		$	1,051,052
Interest rate swaps, at fair value			―			2,861,530
Total derivatives not desingated as hedging instruments for accounting purposes		$	―		$	3,912,582

Statement of Operations	Location of gain (loss) recognized in income	Amount of gain (loss) recognized in income during the year ended December 31, 2009			Amount of gain (loss) recognized in income during the year ended December 31, 2008
Corn derivative instruments	Cost of Goods Sold	$	(474,643	)	$	6,154,162
Ethanol derivative instruments	Revenues		(1,561,940	)		(2,326,266	)
Interest rate swaps	Interest Expense		500,843			(1,817,338	)
Total		$	(1,535,740	)	$	2,010,558

4. INVENTORY

Inventory is valued at lower of cost or market. Inventory values as of December 31, 2009 and 2008 were as follows:

As of December 31,	2009		2008
Raw materials, including corn, chemicals and supplies	$	4,921,532	$	1,636,631
Work in process		642,701		681,187
Finished goods, including ethanol and distillers grains		1,428,798		1,035,774
Total inventory	$	6,993,031	$	3,353,592

Lower of cost or market adjustments for the years ended December 31, 2009 and 2008 were as follows:

For the years ended December 31,	2009		2008
Loss on firm purchase commitments	$	169,000	$	3,470,110
Lower of cost or market adjustment for inventory on hand		1,464,500		771,200
Total lower of cost or market adjustments	$	1,633,500	$	4,241,310

The Company typically enters into forward corn purchase contracts under which it is required to take delivery at the contract price. As of December 31, 2009 and 2008 the Company had accrued losses on these firm purchase commitments of $0 and $1.4 million, respectively. The amount of the loss on firm purchase commitments is determined by applying a methodology similar to that used in the impairment valuation with respect to inventory. Given the uncertainty of future ethanol prices, these losses may not be recovered, and further losses on the outstanding purchase commitments could be recorded in future periods.

5. BANK FINANCING

Long-term debt consists of the following:

As of December 31,	2009		2008
Notes payable under loan agreement to bank, see details below	$	44,541,350	$	43,436,721
Subordinated notes payable, see details below		5,525,000		5,525,000
Capital lease obligations (Note 7)		53,675		101,480
Total Long-Term Debt		50,120,025		49,063,201
Less amounts due within one year *		6,500,000		49,063,201
Total Long-Term Debt Less Amounts Due Within One Year	$	43,620,025	$	0

* - The Company’s remaining debt was classified as current as of December 31, 2008. As of December 31, 2008, the Company was in violation of its loan covenants and was projecting that it would be in violation of those covenants throughout 2009. As of December 31, 2009, the Company reclassified its debt in accordance with the scheduled principal payments under the new amendment. The Company has negotiated a favorable amendment to its bank agreements as of March 2010, and regained compliance with its loan covenants as of December 31, 2009. In addition, it projects that it will be in compliance throughout 2010 based on market conditions in place as of March 2010 and its assumptions about future market conditions. See Note 1, going concern and management’s plans, for more information.

F-12

The estimated maturities of long-term debt and capital lease obligations are as follows:

As of December 31,	2009
2010	$	6,500,000
2011		10,940,721
2012		32,653,188
2013		24,750
2014		1,366
Thereafter		―
Total	$	50,120,025

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

	•		Providing the Bank with current and accurate financial statements;

	•		Maintaining certain financial ratios, minimum net worth, and working capital;

	•		Maintaining adequate insurance;

	•		Not making, or allowing to be made, any significant change in our business or tax structure; and

	•		Limiting our ability to make distributions to members.

The construction loan agreement also contains a number of events of default (including violation of our loan covenants) which, if any of them were to occur, would give the Bank certain rights, including but not limited to:

	•		declaring all the debt owed to the Bank immediately due and payable; and

	•		taking possession of all of our assets, including any contract rights.

Because our long-term debt agreements are secured by substantially all of the Company’s assets, the Bank could then sell all of our assets or business and apply any proceeds to repay their loans. We would continue to be liable to repay any loan amounts still outstanding.

Credit Agreement

In December 2005, the Company entered into a Credit Agreement with a bank providing for a total credit facility of approximately $59,712,000 for the purpose of funding the construction of the Plant. The construction loan agreement provides for the Company to maintain certain financial ratios and meet certain non-financial covenants. The loan agreement is secured by substantially all of the assets of the Company and includes the terms as described below.

During 2009, the Company entered into the Sixth Amendment to its Loan Agreements (“Sixth Amendment”) which allowed it to defer two principal payments due during 2009 (April 16 and July 16). The Sixth Amendment also contained provisions instituting an interest rate floor of 6% along with a new interest rate spread of 400 basis points over certain LIBOR rates. The Company also entered into the Seventh Amendment to its Loan Agreements (“Seventh Amendment”) in March of 2010 (effective as of December 31, 2009). The Seventh Amendment changed certain definitions and covenant ratios within the financial covenants that allowed the Company to meet those covenants as of December 31, 2009 as well as waived all prior covenant violations. The Seventh Amendment also calls for an additional principal payment that approximates an increase in our interest rate spread to 500 basis points over certain LIBOR rates.

F-13

Interest expense for the years ended December 31, 2009 and 2008 consists of the following:

Term Notes - Construction Loan

Interest expense for the year ended December 31,	2009			2008		2007
Interest expense on long-term debt	$	2,930,910		$	3,545,910	$	5,160,282
Amortization/write-off of deferred financing costs		567,386			201,020		214,169
Change in fair value of interest rate swaps		(500,843	)		1,817,338		933,256
Net settlements on interest rate swaps		991,463			449,031		(39,000	)
Total interest expense	$	3,988,916		$	6,013,299	$	6,268,707

Construction Loan

		Outstanding Balance (Millions)			Interest Rate
Term Note		December 31, 2009		December 31, 2008	December 31, 2009		December 31, 2008			Range of Estimated Quarterly Principal Payment Amounts		Estimated Final Payment (millions)	Notes
Fixed Rate Note	$	23.60	$	24.70	6.00	%	5.79	%	$	540,000 - $650,000	$	18.30	1, 2, 4
Variable Rate Note		2.10		3.00	6.00	%	6.04	%	$	450,000 - $460,000		1.20	1, 2, 3, 5
Long-Term Revolving Note		10.00		6.40	6.00	%	5.74	%	$	277,000 - $535,000		7.70	1, 2, 6, 7
2007 Fixed Rate Note		8.80		9.20	6.00	%	6.19	%	$	200,000 - $239,000		6.10	1, 2, 5

Notes

1 -	The scheduled maturity date is April 2012

2 -	Range of estimated quarterly principal payments is based on principal balances and interest rates as of December 31, 2009

3 -

4 -	Interest rate based on 5.0% over three-month LIBOR with a 6% minimum, reset quarterly

5 -	Interest rate based on 5.0% over three-month LIBOR with a 6% minimum, reset quarterly

6 -	Interest rate based on 5.0% over one-month LIBOR with a 6% minimum, reset monthly

7 -	Principal payments would be made on the Long-Term Revolving Note once the Variable Rate Note is paid in full.

Revolving Line of Credit

During July 2008, the Company renewed its $3,500,000 line of credit agreement for a one year period, subject to certain borrowing base limitations. The line of credit was not renewed in July 2009. The Company has no outstanding borrowings at December 31, 2009, 2008 and 2007.

Interest Rate Swap Agreements

In December 2005, the Company entered into an interest rate swap transaction that effectively fixed the interest rate at 8.08% on the outstanding principal of the Fixed Rate Note. In December 2007, the Company entered into a second interest rate swap transaction that effectively fixed the interest rate at 7.695% on the outstanding principal of the December 2007 Fixed Rate Note.

The interest rate swaps were not designated as either a cash flow or fair value hedge. Fair value adjustments and net settlements are shown in interest expense.

Letters of Credit

During 2009, the Company issued $750,000 in letters of credit from the Bank in conjunction with the issuance of two bonds it needs for operations. There is no expiration date on the letters of credit and the Company does not anticipate the Bank having to advance any funds under these letters of credit. The letters of credit are subject to a 4% quarterly commitment fee. The $137,000 letter of credit that was outstanding at December 31, 2008 has been allowed to expire.

Subordinated Debt

As part of the construction loan agreement, the Company entered into three separate subordinated debt agreements totaling approximately $5,525,000 and received funds from these debt agreements during 2006. Interest is charged at a rate of 2.0% over the Variable Rate Note interest rate which totaled 8.0% and 8.04% at December 31, 2009 and 2008, respectively. Interest is due and payable subject to approval by the Bank. Interest is compounding with any unpaid interest converted to principal. Amounts will be due and payable in full in March 2011 subject to approval by the Bank. The balance outstanding on these loans was $5,525,000 as of December 31, 2009 and 2008, respectively

F-14

Effective January 1, 2008, the Company adopted accounting standards related to the measurement of fair value which outline a framework for measuring fair value, and details the required disclosures about fair value measurements.

6. FAIR VALUE

The standards permit the Company to irrevocably choose to measure certain financial instruments and other items at fair value. Except for those assets and liabilities which are required to be recorded at fair value the Company elected not to record any other assets or liabilities at fair value.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in the principal or most advantageous market. The Company uses a fair value hierarchy that has three levels of inputs, both observable and unobservable, with use of the lowest possible level of input to determine fair value. Level 1 inputs include quoted market prices in an active market or the price of an identical asset or liability. Level 2 inputs are market data, other than Level 1, that are observable either directly or indirectly. Level 2 inputs include quoted market prices for similar assets or liabilities, quoted market prices in an inactive market, and other observable information that can be corroborated by market data. Level 3 inputs are unobservable and corroborated by little or no market data. The Company uses valuation techniques in a consistent manner from year-to-year.

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2009 and 2008, respectively. Money market funds shown below are included in cash and equivalents on the balance sheet.

					Fair Value Measurement Using
	Carrying Amount as of December 31, 2009		Fair Value as of December 31, 2009		Level 1		Level 2		Level 3
Assets
Money market funds	$	5,010,325	$	5,010,325	$	5,010,325	$	―	$	―
Derivative instruments		129,063		129,063		129,063		―		―
Total	$	5,139,388	$	5,139,388	$	5,139,388	$	―	$	―
Liabilities
Interest rate swaps	$	2,360,686	$	2,360,686	$	―	$	2,360,686	$	―
Derivative instruments		806,490		806,490		806,490		―		―
Total	$	3,167,176	$	3,167,176	$	806,490	$	2,360,686	$	―

					Fair Value Measurement Using
	Carrying Amount as of December 31, 2008		Fair Value as of December 31, 2008		Level 1		Level 2		Level 3
Assets
Money market funds	$	4,366,121	$	4,366,121	$	4,366,121	$	―	$	―
Derivative instruments		―		―		―		―		―
Total	$	4,366,121	$	4,366,121	$	4,366,121	$	―	$	―
Liabilities
Interest rate swaps	$	2,861,530	$	2,861,530	$	―	$	2,861,530	$	―
Derivative instruments		1,051,052		1,051,052		1,051,052		―		―
Total	$	3,912,582	$	3,912,582	$	1,051,052	$	2,861,530	$	―

The fair value of the money market funds and corn and ethanol derivative instruments are based on quoted market prices in an active market. The fair value of the interest rate swap instruments are determined by using widely accepted valuation techniques including discounting cash flow analysis on the expected cash flows of each instrument. The analysis of the interest rate swap reflects the contractual terms of the derivatives, including the period to maturity and uses observable market-based inputs and uses the market standard methodology of netting the discounted future fixed cash receipts and the discounted expected variable cash payments. The variable cash payments are based on an expectation of future interest rates derived from observable market interest rate curves.

F-15

Financial Instruments Not Measured at Fair Value

The estimated fair value of the Company’s long-term debt, including the short-term portion, at December 31, 2009 approximated the carrying value of approximately $50 million. The Company had negotiated an amendment to its loan agreements during 2009 that set an interest rate floor of 6% which was the interest rate in effect at December 31, 2009 and was thought to approximate the market interest rate for this debt. The estimated fair value of the Company’s long-term debt, including the short-term portion, at December 31, 2008 approximated its carrying value of $48.8 million. Fair value was estimated using estimated market interest rates as of December 31, 2008. 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 May 2014. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under an operating lease includes a locomotive and rail cars. Rent expense for operating leases was $506,000, $356,000 and $27,000 for the years ending December 31, 2009, 2008 and 2007, respectively. Equipment under capital leases consists of office equipment and plant equipment.

Equipment under capital leases is as follows at:

As of December 31,	2009		2008
Equipment	$	219,476	$	216,745
Accumulated amortization		63,248		45,996
Net equipment under capital lease	$	156,228	$	170,749

The Company had the following minimum commitments, which at inception had non-cancelable terms of more than one year:

As of December 31, 2009	Operating Leases		Capital Leases
2010	$	489,660	$	45,518
2011		470,305		3,354
2012		416,400		3,354
2013		34,700		3,354
2014		―		1,398
Total minimum lease commitments	$	1,411,065		56,978
Less amount representing interest				3,303
Present value of minimum lease commitments included in preceding long-term liabilities			$	53,675

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. During 2009, 5,000 units vested, and were issued, under an employee equity based compensation agreement. These units were issued from treasury units repurchased during 2007. Treasury units purchased are accounted for using the cost method. The equity-based compensation plan is described in more detail in Note 9. As of December 31, 2009 and 2008 there 40,193,973 and 40,188,973 units issued and outstanding, respectively.

9. EQUITY-BASED COMPENSATION

2006 Equity-Based Incentive Plan

During 2006, the Company implemented an equity-based incentive plan (the “Plan”) which provided for the issuance of restricted Units to the Company’s key management personnel, for the purpose of compensating services rendered. As of June 30, 2009, the personnel covered by the Plan had either left employment or given notice that they were going to leave employment. Leaving employment caused the employees to forfeit the award and prior recognized equity-based compensation expense related to these grants were reversed through compensation expense during the three months ended June 30, 2009. During June 2009, 5,000 units were issued under the terms of the Plan.

During 2007, the Company exercised an option to repurchase 200,000 Units in association with this Plan. 180,000 Units are still held in treasury and will not be issued under the Plan. While the Company does not have any other equity-based compensation plans currently in place, these Units could be used for that purpose in the future. Equity-based compensation expense was approximately $(-53,334) and $22,000 for the years ended December 31 2009 and 2008, respectively. As of December 31, 2009, the total equity-based compensation expense related to nonvested awards not yet recognized was $0.

F-16

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

10. 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 and in the process of submitting the final report to the Industrial Commission at which time repayment of the grant will commence. 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 repay the grant at a rate of approximately $35,000 per year. This repayment could begin in 2010.

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 $37,000 and $73,000 fiscal years ended December 31, 2009 and 2008, respectively.

11. COMMITMENTS AND CONTINGENCIES

Design Build Contract

The Company signed a Design-Build Agreement with Fagen, Inc. (“Fagen”) in September 2005 to design and build the ethanol plant at a total contract price of approximately $77 million. The total cost of the project, including the construction of the ethanol plant and start-up expenses was approximately $99 million at December 31, 2007. The Company has remaining payments under this Design-Build Agreement of approximately $3.9 million. This payment has been withheld pending satisfactory resolution of a punch list of items including a major issue with the coal combustor experienced during start up. The Plant was originally designed to be able to run on lignite coal and meet the emissions requirements in the Company’s permits.. During the first four months of operation, however, the Plant experienced numerous shut downs related to running on lignite coal and could not meet emissions requirements. In April 2007, the Company switched to using powder river basin coal as its fuel source and has not experienced a single shut down related to coal quality however it has still not been able to meet all of its emissions requirements running on PRB coal which is a cleaner fuel source than lignite. An amount approximately equal to the final payment of $3.9 million has been set aside in a separate money market account. Any amounts remaining in this account after satisfactory resolution of this issue could be used to pay down the Company’s long-term debt, make necessary upgrades to its plant or be used for operations pending bank approval.

Consulting Contracts

In December 2003, the Company entered into a Development Services Agreement (the “DSA”) and a Management Agreement (the “MA”) with Greenway Consulting. Under the terms of the DSA, Greenway Consulting provided project development, construction management and initial plant operations through start up. The DSA also called for Greenway Consulting to be reimbursed for salary and benefit expenses of the General Manager and Plant Manager retroactive to the date six months prior to successful commissioning of the plant. The Company has paid Greenway Consulting $2,075,000 for services rendered under the DSA and reimbursed Greenway Consulting $135,000 for salary and benefit expenses. The Company still owes $152,500 to Greenway for services rendered under the DSA. Payment is being withheld pending satisfactory resolution to a punch list of items to be completed by Fagen including problems related to the coal combustor. The DSA expired upon successful commissioning of the plant which occurred on January 1, 2007 at which time the MA went into effect.

During 2009, the Company amended and restated the terms of the MA . Under the new terms of the MA, Red Trail assumes responsibility for day to day operations of the plant, and the Company’s plant manager and CEO are now direct employees of Red Trail. Greenway still provides management consulting services for the Company and, for these services, receives $171,600 per year plus 4% of the Company’s annual pre-tax net income. The other terms of the contract are materially unchanged – including the expiration date of the contract which is December 31, 2011. The Company had started withholding payment from Greenway under the terms of the original MA on January 1, 2009 pending resolution of certain contractual items. Those items have been resolved with Greenway agreeing to forgo payment of the monthly management fee for the first six months of 2009. For the years ended December 31, 2009 and 2008, the Company had expensed approximately $175,000 and $534,000, respectively for management services under the MA and has also expensed approximately $296,000 and $288,000, respectively, for reimbursement of salary and benefits.

In February 2006, the Company entered into a Risk Management Agreement for grain procurement, pricing, hedging and assistance in risk management as it pertains to ethanol and co-products with John Stewart & Associates (“JSA”). JSA will provide services in connection with grain hedging, pricing and purchasing. The Company will pay $1,200 per month for these services beginning no sooner than ninety days preceding plant startup. In addition, JSA will serve as clearing broker for the Company and charge a fee of $15.00 per contract plus clearing and exchange fees. As of December 31, 2009, there were no amounts outstanding.

Utility Agreements

The Company entered into a contract with Roughrider Electric Cooperative, Inc. dated August 2005, for the provision of electric power and energy to the Company’s plant site. The agreement is effective for five years from August 2005, and thereafter for additional three year terms until terminated by either party giving to the other six months’ notice in writing. The rate the Company will pay for electricity during 2010 is approximately $.05 per kilowatt hour.

F-17

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

In March 2006, the Company entered into a ten year contract with Southwest Water Authority to purchase raw water. The contract, which was amended in 2007, includes a renewal option for successive periods not to exceed ten years. The actual rate for raw water was $2.54 per one thousand gallons for the year ended December 31, 2009. The base rate may be adjusted annually by the State Water Commission.

In June 2006, the Company entered into an agreement with Montana-Dakota Utilities Co. (“MDU”) for the construction and installation of a natural gas line. The agreement required the Company to pay $3,500 prior to the commencement of the installation and to maintain an irrevocable letter of credit in the amount of $137,385 for a period of five years as a preliminary cost participation requirement. During 2009, this letter of credit was allowed to expire and the Company paid approximately $23,000 as its share of the cost participation requirement based on the volume of natural gas used by the Company.

Marketing Agreements

The Company entered into a marketing agreement on March 10, 2008 with CHS for the purpose of marketing and selling its DDGS. The marketing agreement has a term of six months which is automatically renewed at the end of the term. The agreement can be terminated by either party upon written notice to the other party at least thirty days prior to the end of the term of the agreement. Prior to March 2008, the Company had a marketing agreement with Commodity Specialists Company (“CSC”) which assigned all rights, title and interest in the agreement to CHS. The terms of the new agreement are not materially different from the prior agreement. Under the terms of the agreement, the Company pays CHS a fee for marketing its DDGS. The fee is 2% of the selling price of the DDGS subject to a minimum of $1.50 per ton and a maximum of $2.15 per ton. Through the marketing of CHS and its relationships with local farmers, the Company is not dependent upon one or a limited number of customers for its DDGS sales.

The Company entered into a new marketing agreement on January 1, 2008 with RPMG for the purposes of marketing and distributing all of the ethanol produced at the Plant (the “New Agreement”). Prior to January 1, 2008 the Company had a marketing agreement in place with Renewable Products Marketing Group LLC. Effective October 1, 2007, that contract was assigned to RPMG. The terms of the New Agreement are not materially different than the prior agreement except as discussed below in relation to the fees paid to RPMG. Effective as of January 1, 2008, the Company also purchased an ownership interest in RPMG. Currently, the Company owns 8.33% of the outstanding capital stock of RPMG and anticipates that its ownership interest will be reduced if other ethanol plants that utilize RPMG’s marketing services become owners of RPMG. The Company’s ownership interest in RPMG entitles it to a seat on its board of directors which is filled by its Chief Executive Officer (“CEO”). The New Agreement will be in effect as long as the Company continues to be a member in RPMG. From January – August, 2009, the Company paid RPMG $.01 per gallon for each gallon sold by RPMG. Approximately 60% of this marketing fee was allocated to the Company’s equity purchase which was completed in August. After the equity purchase was completed, the marketing fee decreased to approximately $.004 per gallon.

Coal Purchase Contract

The Company entered into a contract in March 2004 with General Industries, Inc. d/b/a Center Coal Company (“Center Coal”) for the purchase of lignite coal. The term of the contract was for ten years from the commencement date agreed upon by the parties. During the startup period of January – April 2007, the Plant experienced a number of shut-downs as a result of issues related to lignite coal quality and delivery, as specified in the coal purchase agreement, along with the performance of the Plant’s coal combustor while running on lignite coal. As a result of these issues, the Company terminated its lignite coal purchase and delivery contract with Center Coal and switched to PRB coal as an alternative to lignite coal. Since making the change, the Plant has not experienced a single shut-down due to coal quality. The Company entered into a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2009 which has now been extended through 2011. The Company is required to purchase between 90,000 and 115,000 tons of coal per year under this agreement.

Coal Management Contract

During 2008, the Company entered in to a contract with M-BAR-D LLC (“MBD”) for the unloading of coal at the Company’s coal unloading facility along with transport of the coal from the stockpile to the storage silos at the Plant. The contract runs for 2.5 years and is automatically renewed for two year terms unless terminated in accordance with the terms of the contract. Under the terms of the agreement, the Company pays MBD $2.65 per ton for unloading the coal and $1.30 per ton for transporting the coal subject to a 3% per year increase.

Chemical Consignment Purchase Contracts

During November 2006, the Company entered into two consignment purchases for bulk chemicals purchased through Genecor International Inc and Univar USA. Genecor will provide the following enzymes: Alpha-Amylase, Glucoamylease and Protease. The Univar agreement states that it will provide the following bulk chemicals: Caustic Soda, Sulfuric Acid, Anhydrous Ammonia and Sodium Bicarbonate. All Univar chemicals are purchased at market price for a five year term. The Genecor agreement was renewed by the Company on July 1, 2009 for a one year term.

Natural Gasoline Contract

The Company has entered into various contracts with suppliers for the purchase of natural gasoline. The term of the most recent contract is May 2009 – March 2010. The price per gallon is based off the average Conway natural gas price plus $0.26. The Company is in the process of working to secure its supply of denaturant for the rest of 2010.

F-18

Red Trail Energy, LLC

Notes to Financial Statements

December 31, 2009, 2008 and 2007

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 December 31, 2009, the Company had various fixed and basis contracts for approximately 1.1 million bushels of corn. Of the 1.1 million bushels under contract, essentially all had a fixed price as of December 31, 2009. During 2009, the Company implemented stricter limits on the number of bushels of corn/how far in advance it would enter into fixed price contracts. Using the stated contract price for the fixed contracts and using market prices, as of December 31, 2009, to price the basis contracts the Company had commitments of approximately $4.1 million related to all 1.1 million bushels under contract.

12. DEFINED BENEFIT CONTRIBUTION PLAN

The Company established a simple IRA retirement plan for its employees during 2006. The Company matches employee contributions to the plan up to 3% of employee’s gross income. The amount contributed by the Company is vested 100% as soon as the contribution is made on behalf of the employee. The Company contributed approximately $48,000 and $56,000 for fiscal years ended December 31, 2009 and 2008, respectively.

13. 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 DDGs and sale of ethanol. The related parties include unit holders, members of the board of governors of the Company, Greenway and RPMG. The Company also has a note payable to Greenway, and pays Greenway for plant management and other consulting fees (recorded in general and administrative expense). The Chief Manager of Greenway is a member of the Company and was, for the period June 2009 – December 31, 2009, the Company’s CEO. Significant related party activity affecting consolidated financial statements are as follows:

As of December 31,	2009		2008
Balance Sheet
Accounts receivable	$	2,155,238	$	2,198,277
Accounts payable		1,164,218		788,149
Notes payable		1,525,000		1,525,000
Statement of Operations
Revenues	$	82,162,189	$	117,379,764
Cost of goods sold		2,854,692		2,712,392
General and administrative expenses		470,906		1,087,552

Inventory Purchases	$	6,996,695	$	9,669,953

14. INCOME TAXES

The difference between financial statement basis and tax basis of assets are as follows:

As of December 31	2009			2008
Financial Statement Basis of Assets	$	97,677,401		$	95,802,453
Organization and start-up costs		4,614,644			5,141,445
Inventory and compensation		65,058			34,458
Net book value of property, plant and equipment		(27,822,932	)		(19,293,573	)
Book to tax derivative difference		158,436			―
Income Tax Basis of Assets	$	74,692,607		$	81,684,783

Financial Statement Basis of Liabilities	$	63,802,037		$	62,243,448
Loss on firm purchase commitment		―			1,426,800
Interest rate swap		(2,360,686	)		(2,861,529	)
Book to tax derivative difference		(806,490	)		2,371,800
Income Tax Basis of Liabilities	$	60,634,861		$	63,180,519

F-19