RED TRAIL ENERGY, LLC (Form: 10-Q, Received: 08/13/2010 16:12:27)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2010

¨	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _____________ to ______________

Commission file number 000-53039

RED TRAIL ENERGY, LLC

(Name of registrant as specified in its charter)

NORTH DAKOTA	76-0742311
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

3682 Highway 8 South, P.O. Box 11, Richardton, North Dakota	58652
(Address of principal executive offices)	(Zip Code)

(701) 974-3308

(Registrant’s telephone number)

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

x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No

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

Large accelerated filer	¨		Accelerated filer	¨
Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: As of August 13, 2010 there were 40,193,973 Class A Membership Units.

INDEX

		Page

PART I — FINANCIAL INFORMATION		3
Item 1. – Condensed Financial Statements		3
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		25
Item 4. Controls and Procedures		27

PART II — OTHER INFORMATION		27
Item 1. Legal Proceedings		27
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3. Defaults Upon Senior Securities		28
Item 4. Removed and Reserved		28
Item 5. Other Information		28
Item 6. Exhibits		29

SIGNATURES		29

PART I — FINANCIAL INFORMATION

Item 1. – Condensed Financial Statements

RED TRAIL ENERGY, LLC

CONDENSED BALANCE SHEETS

	June 30, 2010
	(Unaudited)		December 31, 2009
ASSETS
Current Assets
Cash and equivalents	$	5,456,716	$	13,214,091
Restricted cash		844,942		2,217,013
Accounts receivable		2,672,952		2,635,775
Derivative instruments, at fair value		―		129,063
Inventory		5,931,783		6,993,031
Prepaid expenses		169,398		195,639
Total current assets		15,075,791		25,384,612

Property, Plant and Equipment
Land		351,280		351,280
Land improvements		3,970,500		3,970,500
Buildings		5,312,995		5,312,995
Plant and equipment		79,441,785		79,199,850
Construction in progress		94,358		―
		89,170,918		88,834,625

Less accumulated depreciation		20,322,359		17,419,043
Net property, plant and equipment		68,848,559		71,415,582

Other Assets
Investment in RPMG		605,000		605,000
Patronage equity		309,990		192,207
Deposits		46,133		80,000
Total other assets		961,123		877,207
Total Assets	$	84,885,473	$	97,677,401

LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
Accounts payable	$	6,755,687	$	7,605,302
Accrued expenses		3,130,600		2,634,534
Derivative instruments, at fair value		90,225		806,490
Accrued loss on firm purchase commitments		60,000		―
Current maturities of long-term debt		8,830,434		6,500,000
Current portion of interest rate swaps, at fair value		888,343		785,591
Total current liabilities		19,755,289		18,331,917

Other Liabilities
Contracts payable		275,000		275,000

Long-Term Debt
Notes payable		27,498,384		43,620,025
Long-term portion of interest rate swaps, at fair value		1,270,532		1,575,095
Total long-term debt		28,768,916		45,195,120

Commitments and Contingencies

Members' Equity		36,086,268		33,875,364
Total Liabilities and Members' Equity	$	84,885,473	$	97,677,401

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

RED TRAIL ENERGY, LLC

CONDENSED STATEMENTS OF OPERATIONS

	Quarter Ended June 30, 2010 (Unaudited)			Quarter Ended June 30, 2009 (Unaudited)			Six Months Ended June 30, 2010 (Unaudited)		Six Months Ended June 30, 2009 (Unaudited)
Revenues
Ethanol, net of derivative fair value changes	$	18,822,186		$	19,462,830		$	42,606,351	$	36,366,832
Distillers grains		3,695,872			4,170,001			8,798,598		8,161,612
Total Revenue		22,518,058			23,632,831			51,404,949		44,528,444

Cost of Goods Sold
Cost of goods sold, net of changes in fair value of derivative instruments		20,528,249			21,659,717			44,154,801		40,051,075
(Gain)/loss on firm purchase commitments		(42,000	)		421,000			60,000		695,000
Lower of cost or market adjustment for inventory on hand		―			476,000			―		1,243,000
Depreciation		1,452,675			1,470,664			2,903,117		2,940,883
Total Cost of Goods Sold		21,938,924			24,027,381			47,117,918		44,929,958

Gross Margin (Deficit)		579,134			(394,550	)		4,287,031		(401,514	)

General and Administrative		586,172			701,337			1,226,327		1,482,347

Operating Income (Loss)		(7,038	)		(1,095,887	)		3,060,704		(1,883,861	)

Interest Expense		773,439			566,216			1,862,357		1,871,437

Other income, net		6,890			402,450			1,012,557		444,671

Net Income (Loss)	$	(773,587	)	$	(1,259,653	)	$	2,210,904	$	(3,310,627	)

Wtd Avg Units Outstanding - Basic		40,193,973			40,189,028			40,193,973		40,189,001

Net Income (Loss) Per Unit - Basic	$	(0.02	)	$	(0.03	)	$	0.06	$	(0.08	)

Wtd Avg Units Outstanding - Diluted		40,193,973			40,189,028			40,193,973		40,189,001

Net Income (Loss) Per Unit - Diluted	$	(0.02	)	$	(0.03	)	$	0.06	$	(0.08	)

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

RED TRAIL ENERGY, LLC

CONDENSED STATEMENTS OF CASH FLOWS

	Six months ended June 30, 2010 (Unaudited)			Six months ended June 30, 2009 (Unaudited)
Cash Flows from Operating Activities
Net income (loss)	$	2,210,904		$	(3,310,627	)
Adjustment to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation		2,903,316			2,969,586
Amortization and write-off of debt financing costs		―			567,385
Change in fair value of derivative instruments		(588,305	)		447,739
Change in fair value of interest rate swaps		506,846			(682,827	)
Equity-based compensation		―			3,334
Equity-based compensation non-cash write-off		―			(52,635	)
Noncash patronage equity		(117,783	)		(75,911	)
Unrealized gain (loss) on firm purchase commitments		60,000			(731,800	)
Changes in assets and liabilities
Restricted cash-margin account		1,373,174			―
Accounts receivable		(37,177	)		(2,359,302	)
Inventory		1,061,248			(1,063,706	)
Prepaid expenses		26,241			4,255,655
Other assets		33,867			―
Accounts payable		(849,615	)		1,742,108
Accrued expenses		496,066			393,262
Cash settlements on interest rate swaps		(708,657	)		333,301
Net cash provided by operating activities		6,370,125			2,435,562
Cash Flows from Investing Activities
Investment in RPMG		―			(127,971	)
Refund of sales tax on fixed assets		―			753,386
Capital expenditures		(336,293	)		(12,750	)
Net cash provided by (used in) investing activities		(336,293	)		612,665
Cash Flows from Financing Activities
Debt repayments		(13,791,207	)		(1,270,078	)
Restricted cash - collateral		―			(750,000	)
Treasury units issued		―			5,000
Proceeds from long-term debt		―			3,559,874
Net cash provided by (used in) financing activities		(13,791,207	)		1,544,796

Net Increase (Decrease) in Cash and Equivalents		(7,757,375	)		4,593,023
Cash and Equivalents - Beginning of Period		13,214,091			4,433,839
Cash and Equivalents - End of Period	$	5,456,716		$	9,026,862

Supplemental Disclosure of Cash Flow Information
Interest paid	$	2,235,525		$	1,434,732

SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

Write-off of debt issuance costs	$	―		$	517,823
Investment in RPMG included in accounts payable	$	―		$	127,971

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

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

The accompanying condensed unaudited financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted as permitted by such rules and regulations. These financial statements and related notes should be read in conjunction with the financial statements and notes thereto included in the Company’s audited financial statements for the year ended December 31, 2009, contained in the Company’s Annual Report on Form 10-K.

In the opinion of management, the interim condensed financial statements reflect all adjustments considered necessary for fair presentation. The adjustments made to these statements consist only of normal recurring adjustments. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Red Trail Energy, LLC, a North Dakota limited liability company (the “Company”), owns and operates a 50 million gallon annual name-plate production ethanol plant near Richardton, North Dakota (the “Plant”).

Accounting Estimates

Management uses estimates and assumptions in preparing these financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported revenues and expenses. Significant items subject to such estimates and assumptions include the useful lives of property, plant and equipment, valuation of derivatives, inventory, 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 six months ended June 30, 2009 have been changed to conform to the classifications used in 2010. These reclassifications had no effect on members’ equity, net income (loss) or operating cash flows as previously reported.

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 June 30, 2010 and December 31, 2009 and the fair value approximated the carrying value (see Note 4 for additional information).

On January 1, 2008, the Company adopted guidance for accounting for fair value measurements of financial assets and financial liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the financial statements on a recurring basis. On January 1, 2009, the Company adopted guidance for fair value measurement related to nonfinancial items that are recognized and disclosed at fair value in the financial statements on a nonrecurring basis. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to measurements involving significant unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are as follows:

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

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly,

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

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

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

Net Income (Loss) Per Unit

Net income (loss) per unit is calculated on a basic and fully diluted basis using the weighted average units outstanding during the period. There were no member unit equivalents outstanding during the periods presented; accordingly, the Company’s basic and diluted net income (loss) per unit are the same.

2. DERIVATIVE INSTRUMENTS

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 in order to protect gross profit margins from potentially adverse effects of market and price volatility on ethanol sales and corn purchase commitments where the prices are set at a future date. 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:	June 30, 2010								December 31, 2009
Contract Type	# of Contracts		Notional Amount (Qty)			Fair Value			# of Contracts		Notional Amount (Qty)			Fair Value
Corn futures		215		1,075,000	bushels	$	(90,225	)		82		410,000	bushels	$	129,063
Ethanol swap contracts		0		0	gallons		0			530		7,632,000	gallons		(806,490	)
Total fair value						$	(90,225	)						$	(677,427	)

Amounts are recorded separately on the balance sheet - negative numbers represent liabilties

None of the commodity contracts in place at June 30, 2010 were designated as effective hedges for accounting purposes. As such, the change in fair value of the commodity contracts in place at June 30, 2010 has been recorded in the results of operations and classified as stated above.

Interest Rate Contracts

The Company had approximately $29.3 million and $30.8 million of notional amount outstanding in swap agreements, as of June 30, 2010 and December 31, 2009, respectively that exchange variable interest rates (one-month LIBOR and three-month LIBOR) for fixed interest rates over the terms of the agreements. At June 30, 2010 and December 31, 2009, the fair value of the interest rate swaps totaled approximately $2.2 million and $2.4 million, respectively, and is recorded as a liability on the balance sheets. 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.

The Company recorded net settlements of approximately $709,000 and $333,000 for the six months ended June 30, 2010 and 2009, respectively. See Note 4 for a description of these agreements.

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

The following tables provide details regarding the Company’s derivative financial instruments at June 30, 2010 and December 31, 2009:

Derivatives not designated as hedging instruments under ASC 815

Balance Sheet - as of June 30, 2010	Asset		Liability
Corn derivative instruments, at fair value	$	―	$	90,225
Interest rate swaps, at fair value		―		2,158,875
Total derivatives not designated as hedging instruments for accounting purposes	$	―	$	2,249,100

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 designated as hedging instruments for accounting purposes	$	129,063	$	3,167,176

Statement of Operations Income/(expense)	Location of gain (loss) in fair value recognized in income	Amount of gain (loss) recognized in income during three months ended June 30, 2010			Amount of gain (loss) recognized in income during three months ended June 30, 2009			Amount of gain (loss) recognized in income during six months ended June 30, 2010			Amount of gain (loss) recognized in income during six months ended June 30, 2009
Corn derivative instruments	Cost of Goods Sold	$	(296,759	)	$	(235,925	)	$	(155,927	)	$	(733,776	)
Ethanol derivative instruments	Revenue		513,127			―			2,000,956			―
Interest rate swaps	Interest Expense		163,991			(495,115	)		201,811			(349,525	)
Total		$	380,359		$	(731,040	)	$	2,046,840		$	(1,083,301	)

3. INVENTORY

Inventory is valued at lower of cost or market. Inventory values as of June 30, 2010 and December 31, 2009 were as follows:

As of	June 30, 2010		December 31, 2009
Raw materials, including corn, chemicals and supplies	$	4,860,050	$	4,921,532
Work in process		500,088		642,701
Finished goods, including ethanol and distillers grains		571,645		1,428,798
Total inventory	$	5,931,783	$	6,993,031

Lower of cost or market adjustments for the three and six months ended June 30, 2010 and 2009 were as follows:

	For the three months ended June 30, 2010			For the three months ended June 30, 2009		For the six Months ended June 30, 2010		For the six months ended June 30, 2009
Loss on firm purchase commitments	$	(42,000	)	$	421,000	$	60,000	$	695,000
Lower of cost or market adjustment for inventory on hand		-			476,000		-		1,243,000
Total lower of cost or market adjustments	$	(42,000	)	$	897,000	$	60,000	$	1,938,000

The Company has entered into forward corn purchase contracts under which it is required to take delivery at the contract price. At the time the contracts were created, the price of the contract price approximated market price. Subsequent changes in market conditions could cause the contract prices to become higher or lower than market prices. As of June 30, 2010, the average price of corn purchased under fixed price contracts, that had not yet been delivered, was slightly below market price. Based on this information, the Company accrued an estimated loss of firm purchase commitments of $60,000 for the six months ended June 30, 2010. The Company also recorded a loss on firm purchase commitments of approximately $695,000 for the six month period ended June 30, 2009. The loss is recorded in “Loss on firm purchase commitments” on the statement of operations. The amount of the loss was determined by applying a methodology similar to that used in the impairment valuation with respect to inventory. Given the uncertainty of future ethanol prices, this loss may or may not be recovered, and further losses on the outstanding purchase commitments could be recorded in future periods.

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

The Company recorded inventory valuation impairments of $0 and $476,000 for the six months ended June 30, 2010 and 2009, respectively. The impairments were attributable primarily to decreases in market prices of corn and ethanol. The inventory valuation impairment was recorded in “Lower of cost or market adjustment for inventory on hand” on the statement of operations.

4. BANK FINANCING

Long-term debt consists of the following:

As of	June 30, 2010		December 31, 2009
Notes payable under loan agreement to bank	$	30,780,269	$	44,541,350
Subordinated notes payable		5,525,000		5,525,000
Capital lease obligations (Note 6)		23,549		53,675
Total Long-Term Debt		36,328,818		50,120,025
Less amounts due within one year		8,830,434		6,500,000
Total Long-Term Debt Less Amounts Due Within One Year	$	27,498,384	$	43,620,025

Market value of interest rate swaps		2,158,875		2,360,686
Less amounts due within one year		888,343		785,591
Total Interest Rate Swaps Less Amounts Due Within One Year	$	1,270,532	$	1,575,095

Scheduled maturities for the twelve months ended June 30
	Interest rate swaps		Long-term debt		Totals

2011+	$	888,343	$	8,830,434	$	9,718,777
2012		1,270,532		27,492,487		28,763,019
2013		―		2,953		2,953
2014		―		2,944		2,944
2015		―		―		―
Thereafter		―		―		―
Total	$	2,158,875	$	36,328,818	$	38,487,693

+ - Scheduled maturities for the twelve months ended June 30, 2010 include the full outstanding balance of our subordinated debt which has a maturity date of March 2011. However, the subordination agreement requires the Bank to provide us written consent to make any principal payments to the subordinated debt holders and we have not received such consent.

As of June 30, 2010, the Company was in compliance with all of its debt covenants.

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 recorded in interest expense.

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

Interest Expense	For the six months ended June 30, 2010			For the six months ended June 30, 2009
Interest expense on long-term debt	$	1,355,511		$	1,320,276
Amortization/write-off of deferred financing costs		―			567,386
Change in fair value of interest rate swaps		(201,811	)		(349,526	)
Net settlements on interest rate swaps		708,657			333,301
Total interest expense	$	1,862,357		$	1,871,437

5. FAIR VALUE MEASUREMENTS

The following table provides information on those assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2010 and December 31, 2009, respectively. Money market funds shown below are included in cash and equivalents on the balance sheet.

					Fair Value Measurement Using
	Carrying Amount as of June 30, 2010		Fair Value as of June 30, 2010		Level 1		Level 2		Level 3
Assets
Money market funds	$	844,942	$	844,942	$	844,942	$	―	$	―
Derivative instruments		―		―		―		―		―
Total	$	844,942	$	844,942	$	844,942	$	―	$	―
Liabilities
Interest rate swaps	$	2,158,875	$	2,158,875	$	―	$	2,158,875	$	―
Derivative instruments		90,225		―		90,225		―		―
Total	$	2,249,100	$	2,158,875	$	90,225	$	2,158,875	$	―

					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	$	―

The fair value of the money market funds and corn and ethanol derivative instruments is 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 discounted cash flow analysis on the expected cash flows of each instrument. The analysis of the interest rate swaps reflect 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.

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

Financial Instruments Not Measured at Fair Value

The estimated fair value of the Company’s long-term debt, including the short-term portion, at June 30, 2010, approximated the carrying value of approximately $36.3 million. The Company 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 June 30, 2010 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, 2009 approximated its carrying value of $50 million. Fair value was estimated using estimated market interest rates as of December 31, 2009. The fair values and carrying values consider the terms of the related debt and exclude the impacts of debt discounts and derivative/hedging activity.

6. LEASES

The Company leases equipment under operating and capital leases through 2015. The Company is generally responsible for maintenance, taxes, and utilities for leased equipment. Equipment under operating lease includes a locomotive and rail cars. Rent expense for operating leases was approximately $130,000 and $260,000 for the three and six months ended June 30, 2010, respectively and $134,000 and $236,000 for the three and six months ended June 30, 2009, respectively. Equipment under capital leases consists of office equipment and plant equipment.

Equipment under capital leases is as follows at:

As of	June 30, 2010		December 31, 2009
Equipment	$	219,476	$	219,476
Accumulated amortization		74,870		63,248
Net equipment under capital lease	$	144,606	$	156,228

At June 30, 2010, the Company had the following minimum commitments, which at inception had non-cancelable terms of more than one year. Amounts shown below are for the 12 months period ending June 30:

	Operating Leases		Capital Leases
2011	$	520,860	$	15,945
2012		464,875		3,354
2013		274,100		3,354
2014		31,200		3,075
2015		31,200		―
Thereafter		―		―
Total minimum lease commitments	$	1,322,235		25,728
Less amount representing interest				2,179
Present value of minimum lease commitments included in the preceding current liabilities			$	23,549

7. COMMITMENTS AND CONTINGENCIES

Design-Build Agreement

The Company signed a design-build agreement (the “Design-Build Agreement”) with Fagen, Inc. (“Fagen”) in September 2005 to design and build the Plant at a total contract price of approximately $77 million. The Company has remaining payments under the 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. During the first four months of operation, however, the Plant experienced numerous shut downs related to running on lignite coal. In April 2007, the Company switched to using Powder River Basin (“PRB”) coal as its fuel source and has not experienced a single shut down related to coal quality. The Company continues to work with Fagen to find a solution to these issues. An amount approximately equal to the final payment was used to pay down the Company’s Long-Term Revolving Note. The funds may be released upon resolution of this issue.

RED TRAIL ENERGY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

FOR THE PERIODS ENDED JUNE 30, 2010 AND DECEMBER 31, 2009

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 June 30, 2010 the Company had various fixed price contracts for the purchase of approximately 1,146,000 bushels of corn. Using the stated contract price for the fixed price contracts, the Company had commitments of approximately $4.0 million related to the 1,146,000 bushels under contract.

8. RELATED-PARTY TRANSACTIONS

The Company has balances and transactions in the normal course of business with various related parties for the purchase of corn, sale of distillers grains and sale of ethanol. The related parties include Unit holders, members of the board of governors of the Company, Greenway Consulting, LLC (“Greenway”) and RPMG, Inc. (“RPMG”). The Company also has a note payable to Greenway and pays Greenway for consulting fees (recorded in general and administrative expense). Significant related party activity affecting the financial statements are as follows:

	June 30, 2010		December 31, 2009
Balance Sheet
Accounts receivable	$	2,111,792	$	2,155,238
Accounts payable		1,039,228		1,164,218
Notes payable		1,525,000		1,525,000

	For the three months ended June 30, 2010		For the three months ended June 30, 2009		For the six months ended June 30, 2010		For the six months ended June 30, 2009
Statement of Operations
Revenues	$	18,584,502	$	20,215,469	$	41,548,875	$	37,699,964
Cost of goods sold		754,815		656,496		1,619,652		1,353,808
General and administrative		64,716		176,968		114,614		283,683

Inventory Purchases	$	1,005,698	$	1,179,356	$	2,331,243	$	2,692,493

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

We prepared the following discussion and analysis to help you better understand our financial condition, changes in our financial condition, and results of operations for the three and six month periods ended June 30, 2010, compared to the same period of the prior fiscal year. This discussion should be read in conjunction with the consolidated financial statements and the Management’s Discussion and Analysis section for the fiscal year ended December 31, 2009, included in the Company’s Annual Report on Form 10-K.

Cautionary Statements Regarding Forward-Looking Statements

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

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

Availability and costs of products and raw materials, particularly corn and coal;

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

Ethanol supply exceeding demand and corresponding ethanol price reductions impacting our ability to operate profitably and maintain a positive spread between the selling price of our products and our raw material costs;

Our ability to generate and maintain sufficient liquidity to fund our operations, meet debt service requirements and necessary capital expenditures;

Our ability to continue to meet our loan covenants;

Limitations and restrictions contained in the instruments and agreements governing our indebtedness;

Results of our hedging transactions and other risk management strategies;

Changes in plant production capacity, variations in actual ethanol and distillers grains production from expectations or technical difficulties in operating the plant;

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

Changes in interest rates and the availability of credit to support capital improvements, development, expansion and operations;

Our ability to market and our reliance on third parties to market our products;

Changes in or elimination of governmental laws, tariffs, trade or other controls or enforcement practices that currently benefit the ethanol industry including:

national, state or local energy policy – examples include legislation already passed such as the California low-carbon fuel standard as well as potential legislation in the form of carbon cap and trade;

federal and state ethanol tax incentives;

legislation mandating the use of ethanol or other oxygenate additives;

state and federal regulation restricting or banning the use of MTBE;

environmental laws and regulations that apply to our plant operations and their enforcement; or

reduction or elimination of tariffs on foreign ethanol.

The development of infrastructure related to the sale and distribution of ethanol including:

expansion of rail capacity,

possible future use of ethanol dedicated pipelines for transportation,

increases in truck fleets capable of transporting ethanol within localized markets,

additional storage facilities for ethanol, expansion of refining and blending facilities to handle ethanol,

growth in service stations equipped to handle ethanol fuels, and

growth in the fleet of flexible fuel vehicles capable of using higher blends of ethanol fuel;

Increased competition in the ethanol and oil industries;

Fluctuations in U.S. oil consumption and petroleum prices;

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

Ongoing disputes with our design-build contractor;

Our liability resulting from litigation;

Our ability to retain key employees and maintain labor relations;

Changes and advances in ethanol production technology; and

Competition from alternative fuels and alternative fuel additives.

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

Available Information

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

Overview

Red Trail Energy, LLC, a North Dakota limited liability company (the “Company,” “Red Trail,” or “we,” “our,” or “us”), owns and operates a 50 million gallon annual name-plate production ethanol plant near Richardton, North Dakota (the “Plant”).

Our revenues are derived from the sale and distribution of our ethanol and distillers grains primarily in the continental United States. Our ethanol plant currently operates at approximately 110 percent of its nameplate capacity. Corn is our largest cost component and our profitability is highly dependent on the spread between the price of corn and the price of ethanol.

On April 8, 2010, the Company announced its intent to engage in a reclassification and reorganization of the Company’s membership units. The proposed transaction will provide for the reclassification of the Company’s membership units into three separate and distinct classes.

If the proposed reclassification is approved by the Company’s members, we expect that each member of record holding 50,000 or more units will receive one Class A unit for each common equity unit held by such unit holder prior to the reclassification; each member of record holding 10,001 to 49,999 units will receive one Class B unit for each common equity unit held by such unit holder immediately prior to the reclassification; and each member of record holding 10,000 or fewer units will receive one Class C unit for each common equity unit held by such unit holder immediately prior to the reclassification.

If the Company’s members approve the proposed amendments to the Company’s operating agreement and member control agreement and the reclassification is implemented, the Company anticipates having fewer than 300 unit holders of record of its common equity units and fewer than 500 unit holders of record of each of the additional classes, which would enable the Company to voluntarily terminate the registration of its units under the Securities and Exchange Act of 1934.

There have been a number of recent developments in legislation that impacts the ethanol industry. One such development concerns the federal Renewable Fuels Standard (RFS). The ethanol industry is benefited by the RFS which requires that a certain amount of renewable fuels must be used in the United States each year. In February 2010, the EPA issued new regulations governing the RFS. These new regulations have been called RFS2. The most controversial part of RFS2 involves what is commonly referred to as the lifecycle analysis of greenhouse gas emissions. Specifically, the EPA adopted rules to determine which renewable fuels provided sufficient reductions in greenhouse gases, compared to conventional gasoline. Any fuels that fail to meet this standard cannot be used by fuel blenders to satisfy their obligations under the RFS program. The RFS2 as adopted by the EPA provides that corn-based ethanol from modern ethanol production processes does meet the definition of a renewable fuel under the RFS program.

In addition to RFS2 which included greenhouse gas reduction requirements, in 2009, California passed a Low Carbon Fuels Standard (LCFS). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which is measured using a lifecycle analysis, similar to RFS2. Management believes that this lifecycle analysis is based on unsound scientific principles that unfairly harms corn based ethanol. Management believes that these new regulations will preclude corn based ethanol from being used in California. California represents a significant ethanol demand market. If we are unable to supply ethanol to California, it could significantly reduce demand for the ethanol we produce. Several lawsuits have been filed by ethanol industry groups challenging the California LCFS.

Ethanol production in the United States is benefited by various tax incentives. The most significant of these tax incentives is the federal Volumetric Ethanol Excise Tax Credit (VEETC). VEETC provides a volumetric ethanol excise tax credit of 4.5 cents per gallon of ethanol blended with gasoline at a rate of 10%. VEETC is scheduled to expire on December 31, 2010. If this tax credit is not renewed, it likely would have a negative impact on the price of ethanol and demand for ethanol in the marketplace and may harm our financial condition.

In addition to the tax incentives, United States ethanol production is also benefited by a 54 cent per gallon tariff imposed on ethanol imported into the United States. However, the 54 cent per gallon tariff is set to expire at the end of the 2010 calendar year. Elimination of the tariff that protects the United States ethanol industry could lead to the importation of ethanol produced in other countries, especially in areas of the United States that are easily accessible by international shipping ports. Ethanol imported from other countries may be a less expensive alternative to domestically produced ethanol and may affect our ability to sell our ethanol profitably.

We expect to fund our operations during the next 12 months using cash flow from our continuing operations and our current credit facilities.

Results of Operations for the Three Months Ended June 30, 2010 and 2009

The following table shows the results of our operations and the percentages of revenues, cost of goods sold, general and administrative expenses and other items to total sales and revenues in our statements of operations for the three months ended June 30, 2010 and 2009, respectively.

	Three Months Ended June 30, 2010 (Unaudited)						Three Months Ended June 30, 2009 (Unaudited)
Statements of Operations Data	Amount			% of Revenue			Amount			% of Revenue
Revenues	$	22,518,058			100.0	%	$	23,632,831			100.00	%
Cost of Goods Sold		21,938,924			97.43	%		24,027,381			101.67	%
Gross Margin (Deficit)		579,134			2.57	%		(394,550	)		(1.67	)%
General and Administrative Expenses		586,172			2.60	%		701,337			2.97	%
Operating Loss		(7,038	)		(0.03	)%		(1,095,887	)		(4.64	)%
Interest Expense		773,439			3.43	%		566,216			2.40	%
Other Income		6,890			0.03	%		402,450			1.70	%
Net Loss	$	(773,587	)		(3.44	)%	$	(1,259,653	)		(5.33	)%

Revenues

The following table shows the sources of our revenue for the three months ended June 30, 2010 and June 30, 2009.

	Three Months Ended June 30, 2010					Three Months Ended June 30, 2009
Revenue Source	Amount		% of Revenues			Amount		% of Revenues
Ethanol Sales	$	18,822,186		83.6	%	$	19,462,830		82.4	%
Dried Distillers Grains Sales		3,139,859		13.9	%		2,934,077		12.4	%
Modified Distillers Grains Sales		556,013		2.5	%		1,235,924		5.2	%
Total Revenues	$	22,518,058		100.00	%	$	23,632,831		100.00	%

The following table shows additional data regarding production and price levels for our primary inputs and products for the three months ended June 30, 2010 and June 30, 2009.

	Three Months ended June 30, 2010		Three Months ended June 30, 2009

Production:
Ethanol sold (gallons)		12,717,000		12,689,000
Dried distillers grains sold (tons)		32,970		24,055
Modified distillers grains sold (tons)		11,274		22,088

Revenues:
Ethanol price/gallon (net of hedging)	$	1.48	$	1.53
Distillers grains avg price/ton	$	95.23	$	121.97
Modified distillers grains avg price/ton	$	49.23	$	55.88

Primary Input:
Corn ground (bushels)		4,660,800		4,423,712

Costs of Primary Input:
Corn avg price/bushel (net of hedging)	$	3.41	$	3.98

Other Costs (per gallon of ethanol sold):
Chemical and additive costs	$	0.079	$	0.081
Denaturant cost	$	0.048	$	0.034
Electricity cost	$	0.048	$	0.038
Direct labor cost	$	0.039	$	0.035

Ethanol production and sales held relatively steady during the three month period ended June 30, 2010 as compared to the same period in 2009. We sold 12,717,000 gallons of ethanol during the three month period ended June 30, 2010 compared to 12,689,000, for the same three month period ending in 2009. The average price we received for our ethanol at was $1.48 and $1.53 for the three month period ending June 30, 2010 and 2009, respectively.

We experienced an increase in the amount of dried distillers grains sold in the three month period ended June 30, 2010 as compared to the same period in 2009. We sold 32,970 tons of dried distillers grains during the three month period ended June 30, 2010 compared to 24,055 tons of dried distillers grains during the three month period ended June 30, 2009. The average price per ton of dried distillers grains was $95.23 and $121.97 for the three month period ending June 30, 2010 and 2009, respectively.

Our modified distillers grains sales were down significantly for the three month period ended June 30, 2010 as compared to the same period in 2009. We sold 11,274 tons of modified distillers grains during the three month period ended June 30, 2010 compared to 22,088 tons of modified distillers grains during the three month period ended June 30, 2009. The average price per ton of modified distillers grains was $49.23 and $55.88 for the three month period ending June 30, 2010 and 2009, respectively. This shift from modified distillers grains to dried distillers grains is being driven by additional demand for dried distillers grains by the export market.

We are currently operating at approximately 110 percent of nameplate capacity. In the event that we decrease our production of ethanol, our production of distillers grains would also decrease. Such a decrease in our volume of production of ethanol and distillers grains would result in lower revenues. However, if we decreased production, we would experience a corresponding decrease in the quantity of corn and coal used by the plant, thereby lowering our costs of good sold. Therefore, the effect of a decrease in our product volume would be largely dependent on the market prices of the products we produce and the inputs we use to produce our products at the time of such a production decrease. We anticipate operating at less than full capacity only if industry margins become unfavorable or we experience technical difficulties in operating the plant.

For the three months ended June 30, 2010, we received approximately 84% of our revenue from the sale of ethanol and approximately 16% of our revenue from the sale of distillers grains. Our revenue from ethanol increased slightly during the three months ended June 30, 2010 compared to the same period in 2009, as a result of a slight increase in the volume of ethanol sold and a decrease in our distillers grains revenue. During the three months ended June 30, 2010, we experienced a decrease in the price we received for our ethanol. Ethanol prices peaked late in 2009 and trended weaker though the end of June 2010. Since that time, ethanol prices have recovered and are back to January 2010 price levels. Management attributes this decreasing trend in ethanol prices with increased production of ethanol and steady demand. Increased gasoline and ethanol prices during the last calendar quarter of 2009 and the first quarter of 2010 allowed the ethanol industry to realize more favorable margins. Management believes that the increased margins led some idled ethanol plants to again commence production. Unless this increased supply is equally met with increased demand for ethanol, management believes ethanol prices will be pressured downward.

Management believes that demand for ethanol is being affected by what is known as the blend wall. The blend wall is a theoretical limit where more ethanol cannot be blended into the national gasoline pool. Currently, ethanol is blended with conventional gasoline for use in standard (non-flex fuel) vehicles to create a blend which is 10% ethanol and 90% gasoline. Estimates indicate that approximately 135 billion gallons of gasoline are sold in the United States each year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.5 billion gallons per year. This theoretical limit acts as a cap on ethanol demand which can negatively impact ethanol prices. If ethanol production continues to expand without a corresponding increase in ethanol demand, management anticipates further decreases in ethanol prices.

The trend in the price of ethanol is uncertain unless the EPA approves an increase in the amount of ethanol that can be blended with gasoline for use in standard (non-flex fuel) vehicles. The EPA is considering allowing a blend of 15% ethanol and 85% gasoline (called E15) for use in standard vehicles. The EPA has delayed making a decision on E15 until sometime in 2010. If the EPA allows a 15% ethanol blend, it may result in increased ethanol demand which could positively impact ethanol prices. However, the EPA may restrict the type of vehicles that can use E15 which may lead to gasoline retailers refusing to carry E15. Automobile manufacturers and environmental groups are lobbying against higher percentage ethanol blends.

During the three months ended June 30, 2010, distillers grains prices trended downward. Management attributes this decreasing price trend to an excess supply of distillers grains and to concerns about the quality of distillers grains. After the end of the three month period ended June 30, 2010, distillers grains prices increased in conjunction with corn prices. Management anticipates that distillers grains prices will continue to track the price of corn which has been extremely volatile due to uncertainty over the condition of the corn crop and price volatility in the wheat and soybean markets.

Cost of Goods Sold

Our cost of goods sold from the production of ethanol and distillers grains is primarily made up of corn and energy expenses. The price we paid for our main input, corn, was lower during the first quarter of 2010 compared to the first quarter of 2009. Our overall cost of goods sold decreased as a percentage of our revenues to 97.4% for the three months ended June 30, 2010 compared to 101.7% for the same period in 2009. The decrease in our cost of goods sold was primarily due to our lower corn costs.

Our cost of corn is also affected by gains and losses on the corn derivative instruments we use to manage our exposure to risk in the corn market. For the three months ended June 30, 2010, we recognized a loss on our corn derivatives of approximately $297,000 compared to a loss of approximately $236,000 for the three months ended June 30, 2009.

Competition for corn in our area has tightened basis levels. Although we believe there is corn available nationally from a supply and demand standpoint, there is uncertainty over the quantity and quality of local corn for the plant. The cost of corn is the highest input to the plant and these uncertainties could dramatically affect our expected input costs. During the three month period ended June 30, 2010, corn prices were relatively steady but increased after the end of the quarter. We expect that corn prices will continue to be volatile for the rest of our fiscal year, depending on weather conditions and other demand factors.

The per unit cost of our other costs of goods sold were all somewhat higher compared to last year although we did experience a decrease in our chemical and additive costs.

We purchase the coal needed to power our ethanol plant from a supplier under a long-term contract. This arrangement helps us to mitigate price volatility in the coal market. Our coal costs remained steady during the first quarter of 2010 compared to the first quarter of 2009. Our coal contract is up for renewal in December 2011.

General and Administrative

General and administrative costs for the three months ended June 30, 2010 were approximately $586,000 or 2.6% of our revenues compared to approximately $701,000 or 3.0% of revenues for the same period in 2009. The decrease is primarily related to a decrease in legal fees.

Operating Income and Loss

Our loss from operations for the three months ended June 30, 2010 was approximately $7,000 compared to an operating loss of approximately $1,096,000 for the same period in 2009. This reduction in our operating losses is primarily due to an improvement in the relationship between the selling price of our products and our input costs for the current year.

Interest Expense

Our interest expense for the three months ended June 30, 2010 was approximately $773,000 compared to approximately $566,000 for the three months ended June 30, 2009. This increase in primarily due to fluctuations in the market value of our interest rate swaps and principal outstanding. Net settlements on the fair value of our interest rate swaps are recorded in interest expense on a monthly basis.

Other Income

Our other income for the three months ended June 30, 2010 was 0.03% of our revenues compared to 1.7% of revenues for the same period in 2009. Our other income for the three month period ended June 30, 2010 consisted primarily of interest income, gain/loss on sale of assets and grant income. During the three month period ended June 30, 2009 we also received other income from interest earned on a sales tax refund received related to plant construction.

Results of Operations for the Six Months Ended June 30, 2010 and 2009

The following table shows the results of our operations and the approximate percentage of revenues, costs of sales, operating expenses and other items to total revenues in our unaudited statements of operations for the six months ended June 30, 2010 and 2009:

	Six Months Ended June 30, 2010 (Unaudited)					Six Months Ended June 30, 2009 (Unaudited)
Statement of Operations Data	Amount		Percent			Amount			Percent
Revenues	$	51,404,949		100.0	%	$	44,528,444			100.00	%
Cost of Goods Sold		47,117,918		91.66	%		44,929,958			100.90	%
Gross Profit (Loss)		4,287,031		8.34	%		(401,514	)		(0.90	)%
General and Administrative Expenses		1,226,327		2.39	%		1,482,347			3.33	%
Operating Income (Loss)		3,060,704		5.95	%		(1,883,861	)		(4.23	)%
Interest Expense		1,862,357		3.62	%		1,871,437			4.20	%
Other Income		1,012,557		1.97	%		444,671			1.00	%
Net Income (Loss)	$	2,210,904		4.30	%	$	(3,310,627	)		(7.43	)%

Revenues

Our revenues from operations come from two primary sources: sales of ethanol and sales of distillers grains. The following table shows the sources of our revenue for the six months ended June 30, 2010 and June 30, 2009.

	Six Months Ended June 30, 2010					Six Months Ended June 30, 2009
Revenue Source	Amount		% of Revenues			Amount		% of Revenues
Ethanol Sales	$	42,606,351		82.9	%	$	36,366,832		81.7	%
Dried Distillers Grains Sales		7,075,730		13.8	%		5,150,927		11.6	%
Modified Distillers Grains Sales		1,722,868		3.3	%		3,010,685		6.7	%
Total Revenues	$	51,404,949		100.00	%	$	44,528,444		100.00	%

The following table shows additional data regarding production and price levels for our primary inputs and products for the six months ended June 30, 2010 and 2009:

	Six Months ended June 30, 2010		Six Months ended June 30, 2009

Production:
Ethanol sold (thousands of gallons)		26,967		24,481
Dried distillers grains sold (tons)		67,486		39,508
Modified distillers grains sold (tons)		31,489		56,688

Revenues:
Ethanol average price/gallon (net of hedging)	$	1.58	$	1.49
Dried distillers grains avg price/ton	$	102.16	$	130.38
Modified distillers grains avg price/ton	$	54.56	$	53.02

Primary Input:
Corn ground (bushels)		9,800,060		8,752,833

Costs of Primary Input:
Corn avg price/bushel (net of hedging)	$	3.48	$	3.98

Other Costs (per gallon of ethanol sold):
Chemical and additive costs	$	0.079	$	0.084
Denaturant cost	$	0.046	$	0.031
Electricity cost	$	0.046	$	0.043
Direct Labor cost	$	0.036	$	0.038

In the six month period ended June 30, 2010, ethanol sales comprised approximately 83% of our revenues and distillers grains sales comprised approximately 17% of our revenues. For the six month period ended June 30, 2009, ethanol sales comprised approximately 82% of our revenues and distillers grains sales comprised approximately 18% of our revenue. Our revenues were higher for our first half of fiscal year 2010 compared to the same period of 2009 primarily as a result of our increase in ethanol production and an increase in the sales price of our ethanol.

The average ethanol sales price we received for the six month period ended June 30, 2010 was approximately 6% higher than our average ethanol sales price for the comparable 2009 period. Management anticipates that ethanol prices will continue to be subject to the uncertainties surrounding several pieces of legislation as well as the prices of oil and gasoline.

The price we received for our dried distillers grains decreased by approximately 20% during the six month period ended June 30, 2010 compared to the same period of 2009. Management attributes this decrease in the price of our dried distillers grains to an increase in the supply of dried distillers grains in our local market area. The price of dried distillers grains changes in proportion to the price of corn, which has decreased in the six month period ended June 30, 2010. Accordingly, we anticipate that the market price of distillers grains will continue to be volatile as a result of changes in the price of corn and competing animal feed substitutes such as soybean meal.

Cost of Good Sold

Our costs of goods sold as a percentage of revenues were approximately 92% for the six month period ended June 30, 2010 compared to approximately 101% for the same period of 2009. Our cost of goods sold increased by approximately 3.8% in the six months ended June 30, 2010, compared to the six months ended June 30, 2009, and our revenue for the same period increased by approximately 15%. This increase in the cost of goods sold is primarily a result of an increase in the volume of corn processed at our facility. The increase in our revenues is due primarily to an increase in the volume of ethanol sold along with an increase in the price we received for our ethanol.

General and Administrative Expenses

Our general and administrative expenses as a percentage of revenues were lower for the six month period ended June 30, 2010 than they were for the same period ended June 30, 2009. These percentages were approximately 2.4% and approximately 3.3% for the six months ended June 30, 2010 and 2009, respectively. This decrease in general and administrative expenses is primarily due to increased operating efficiencies and our concerted effort to lower general and administrative expenses. We expect that going forward our general and administrative expenses will remain relatively steady unless the proposed reclassification and reorganization of the Company’s membership units, as discussed previously is approved. If proposed reclassification is approved, there should be significant general and administrative expense savings.

Operating Income (Loss)

Our income from operations for the six months ended June 30, 2010 was approximately 5.9% of our revenues compared to loss of approximately 4.2% of our revenues for the six months ended June 30, 2009. This increase in our profitability is primarily due to the increase in the price we received for our ethanol for the six months ended June 30, 2010 compared to the six months ended June 30, 2009. During the same period we experienced a $0.50 per bushel decrease in our cost of corn. Both of these factors moved in our favor at the time we increased production at our facility.

Interest Expense

Our interest expense for the six months ended June 30, 2010 was approximately $1,860,000 compared to approximately $1,870,000 for the six months ended June 30, 2009. The outstanding balance on our long-term debt obligations decreased by approximately $14,000,000 during the first six months of 2010. However, this reduction in long-term debt was partially offset by the performance of our interest rate swap transactions.

Other Income

Other income for the six months ended June 30, 2010, was approximately 2.0% of our revenue and totaled approximately $1,013,000. Other income for the six months ended June 30, 2009 totaled approximately $445,000 and was approximately 1.0% of our revenues. The increase in other income is attributable to our receipt of approximately $983,000 from a business interruption insurance claim related to an unplanned outage at our plant during October 2009.

Changes in Financial Condition for the Six Months Ended June 30, 2010

The following table highlights the changes in our financial condition:

	June 30, 2010		December 31, 2009
Current Assets	$	15,075,791	$	25,384,612
Current Liabilities	$	19,755,289	$	18,331,917
Members' Equity	$	36,086,268	$	33,875,364

We experienced a decrease in our current assets at June 30, 2010 compared to our fiscal year ended December 31, 2009. We had approximately $7,750,000 less cash on hand at June 30, 2010 compared to December 31, 2009, and approximately $1,372,000 less in restricted cash. Our accounts receivable remained steady over the same period and our inventory was approximately $1,000,000 less at June 30, 2010 than December 31, 2010.

We experienced a slight increase in our total current liabilities on June 30, 2010 compared to December 31, 2009 due primarily to an increase in current maturities of long-term debt.

Our long-term liabilities as of June 30, 2010 are approximately $16,400,000 less than our long-term liabilities as of December 31, 2009, primarily as a result of principal payments made on our long-term debt and the movement of some long-term debt to current maturities of long-term debt. At June 30, 2010, we had approximately $29,044,000 outstanding in the form of long-term loans, compared to approximately $45,470,000 at December 31, 2009.

We experienced an increase in members' equity at June 30, 2010 compared to our fiscal year ended December 31, 2009. This primarily is a result of our net income so far this fiscal year in the amount of approximately $2,211,000.

Liquidity and Capital Resources

Based on financial forecasts performed by our management, we anticipate that we will have sufficient cash from our current credit facilities and cash from our operations to continue to operate the ethanol plant for the next 12 months. We do not anticipate seeking additional equity or debt financing during our 2010 fiscal year. However, should we experience unfavorable operating conditions in the future, we may have to secure additional debt or equity sources for working capital or other purposes.

Statements of Cash Flows	For the six months ended June 30, 2010			For the six months ended June 30, 2009
Cash flows provided by operating activities	$	6,370,125		$	2,435,562
Cash flows provided by (used in) investing activities	$	(336,293	)	$	612,665
Cash flows provided by (used in) financing activities	$	(13,791,207	)	$	1,544,796

Operating activities

We experienced a significant increase in our net cash provided by operations for the six month period ended June 30, 2010 as compared to the same period in 2009. Cash provided by operating activities was approximately $6,370,000 for the six months ended June 30, 2010 as compared to approximately $2,436,000 provided by operating activities for the six months ended June 30, 2009. Our net income from operations for the six months ended June 30, 2010 was approximately $2,211,000 as compared to a net loss of approximately $3,311,000 for the same period in 2009.

Investing activities

We had minimal investing activities for the periods ended June 30, 2010 and 2009, respectively.

Financing activities

We had a significant increase in cash used for financing activities for the six month period ended June 30, 2010 as compared to the same period in 2009. Cash used for financing activities was approximately $13,791,000 for the nine months ended June 30, 2010. All of this cash was used to pay down our long-term debt. For the six month period ended June 30, 2009, we had net borrowing activity of approximately $1,545,000 as we borrowed an additional $3,560,000 on our long-term debt instruments which was offset by a regularly scheduled debt payment of approximately $1,270,000 and the issuance of letters of credit in the amount of $750,000 to support grain warehouse bonds and distilled spirits bonds.

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

Capital Expenditures

The Company currently has three capital projects in progress that it anticipates will cost a total of approximately $302,000. We anticipate completion of these projects to occur in the third quarter of 2010. The Company is also evaluating certain other capital projects related to reducing the carbon intensity of its fuel in anticipation of trying to meet the requirements of the California low-carbon fuel standard. The Company is in the early stages of reviewing potential projects and does not currently have any accurate cost estimates. It is possible that such projects will be undertaken during 2010. We anticipate being able to fund our current on-going capital projects from our operating cash flows.

Capital Resources

Short-Term Debt Sources

The Company does not currently have any short-term credit facilities.

Long-Term Debt Sources

Our primary debt instruments are with First National Bank of Omaha (the “Bank”) and have a scheduled maturity date of April 2012. These debt instruments include fixed and variable rate notes. The following table summarizes our long-term debt instruments with the Bank.

	Outstanding Balance (Millions)				Interest Rate						Range of Estimated
Term Note	June 30, 2010		December 31, 2009		June 30, 2010			December 31, 2009			Quarterly Principal Payment Amounts		Notes
Fixed Rate Note	$	22.44	$	23.60		6.00	%		6.00	%		$560,000 - $630,000	1, 2, 4
2007 Fixed Rate Note		8.34		8.80		6.00	%		6.00	%		$200,000 - $235,000	1, 2, 5
Variable Rate Note		0		2.10		6.00	%		6.00	%		$1,600,000	1, 2, 3, 5
Long-Term Revolving Note		0		10.00		6.00	%		6.00	%		$550,000 - $610,000	1, 2, 6, 7, 8

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 June 30, 2010.

3 - Quarterly payments of $634,700 are applied first to interest on the Long-Term Revolving Note, next to accrued interest on the Variable Rate Note and finally to principal on the Variable Rate Note. The Variable Rate Note was paid off in April 2010 as the Excess Cash Flow payment was applied to the Variable Rate 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. Any principal applied to the Long-Term Revolving Note reduces the amount available under the revolver.

8 - Funds withheld from the plant's design builder (approx $4,100,000) which were previously set aside in a money market account were applied to the Long-Term Revolving Note in March 2010 pursuant to the terms of the 7th Amendment to our loan agreement with Bank. Accordingly, the payment amounts above take into account the application of those funds which may ultimately be paid to the design builder depending upon the terms of any resolution of the dispute.

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.

Subordinated Debt

As part of our construction loan agreement, we entered into three separate subordinated debt agreements totaling $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 (a total of 8% and 6.4825% at June 30, 2010 and 2009, respectively) and has a scheduled maturity of March 2011. The outstanding balance of the subordinated debt has been included in our current debt maturities. However, the subordination agreement requires the Bank to provide consent to make principal payments to the subordinated debt holders but we have not received such consent. Interest is compounding with any unpaid interest converted to principal. The balance outstanding on these loans was $5,525,000 as of June 30, 2010 and December 31, 2009.

Letters of Credit

We issued two letters of credit during the second quarter of 2009 in conjunction with the issuance of certain grain warehouse and distilled spirits bonds. The letters of credit were issued in the amount of $500,000 and $250,000, respectively.

Restrictive Covenants

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;

•

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 debt instruments with Banks also contain 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.

As of June 30, 2010 we are in compliance with our loan covenants.

Our net worth covenant is particularly sensitive to our earnings. We estimate that we need to record earnings of greater than $230,000 for the period July 2010 to December 2010 in order to maintain compliance with this covenant at December 31, 2010.

Management Reorganization Plan

On June 29, 2010, the Company’s board of governors approved a management reorganization plan that became effective on July 8, 2010. Pursuant to this management reorganization plan Gerald Bachmeier was appointed to the position of Chief Executive Officer for the Company.

In conjunction with the implementation of the Company’s management reorganization plan, the Company and Mr. Bachmeier entered into an employment agreement effective on July 8, 2010. The term of Mr. Bachmeier’s employment agreement is five and one-half years and is subject to customary termination provisions. Mr. Bachmeier’s base salary on an annualized basis for the period from July 8, 2010 through December 31, 2010 is $135,000. The employment agreement also provides for a year-end bonus based on the Company’s net income.

Mr. Bachmeier previously served as interim Chief Executive Officer for the Company from June 15, 2009 through December 31, 2009. Mr. Bachmeier serves on the Board of Directors for the Renewable Fuels Association and the Minnesota Coalition for Ethanol and has served on the Board of Directors for Renewable Products Marking Group. Mr. Bachmeier has been involved in the ethanol industry for the past 20 years.

Industry Support

There has been no change in the repayment status of our grant from the North Dakota State Industrial Commission (totaling $275,000) during the second quarter of 2010.

North Dakota Ethanol Incentive Program

Under this program, each fiscal quarter, 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. The amount is capped at $1,600,000 per plant per year up to a lifetime maximum of $10,000,000 per plant. We did not receive any funds from this program during the six months ended June 30, 2010 and 2009, respectively. We cannot predict whether we will receive funds from this program during the remainder of 2010.

Critical Accounting Estimates

Our most critical accounting policies, which are those that require significant judgment, include policies related to the carrying amount of property, plant and equipment; valuation of derivatives, inventory and purchase commitments of inventory; and analysis of intangibles impairment. An in-depth description of these can be found in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. For valuation allowances related to firm purchase commitments of inventory, please refer to the disclosures in Note 2 and Note 3 of the Notes to the unaudited condensed financial statements in this Quarterly Report. Management has not changed the method of calculating and using estimates and assumptions in preparing our condensed financial statements in accordance with generally accepted accounting principles. There have been no changes in the policies for our accounting estimates for the quarter ended June 30, 2010.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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. 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 fixed the interest rate at 8.08% on approximately $27,600,000 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 $10,000,000 of our outstanding long-term debt. The interest rate swaps are not designated as either a cash flow or fair value hedge. Market 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 June 30, 2010, would change the fair value of our interest rate swaps by approximately $560,000.

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. 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.

As of June 30, 2010 we had approximately 1,146,000 bushels of corn under fixed price contracts. These contracts were priced slightly above current market prices so we accrued a loss on firm purchase commitments of approximately $60,000 related to these contracts. We would expect a sustained $0.10 change in the price of corn to have an approximate $115,000 impact on our net income.

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 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.

Liability Risk

We participate in a captive reinsurance company (the “Captive”). The Captive reinsures losses related to worker’s compensation, commercial property and general liability. Premiums are accrued by a charge to income for the period to which the premium relates and is remitted by our insurer to the captive reinsurer. The Captive reinsures catastrophic losses in excess of a predetermined amount. Our premiums are structured such that we have made a prepaid collateral deposit estimated for losses related to the above coverage. The Captive insurer has estimated and collected an amount in excess of the estimated losses but less than the catastrophic loss limit insured by the Captive. We cannot be assessed in excess of the amount in the collateral fund.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures as of June 30, 2010, have concluded that our disclosure controls and procedures are effective in ensuring that material information required to be disclosed is included in the reports that we file with the SEC.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the fiscal quarter ended June 30, 2010, 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.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The Company signed a design-build agreement (the “Design-Build Agreement”) with Fagen, Inc. (“Fagen”) in September 2005 to design and build the plant at a total contract price of approximately $77,000,000. The Company has remaining payments under the Design-Build Agreement of approximately $3,900,000. This payment has been withheld pending satisfactory resolution of certain punch list items, including an issue with the coal combustor experienced during start up. The plant was originally designed to be able to run on lignite coal. During the first four months of operation, however, the plant experienced numerous shut downs related to running on lignite coal. In April 2007, the Company switched to using Powder River Basin (“PRB”) coal as its fuel source and has not experienced a single shut down related to coal quality. The Company and Fagen are currently engaged in mediation to resolve the issues related to the plant’s coal combustor.

Item 1A. Risk Factors

In addition to the other information set forth in this report, including the important information under the heading “Disclosure Regarding Forward-Looking Statements,” you should carefully consider the “Risk Factors” discussed in our Annual Report on Form 10-K for the year ended December 31, 2009. “Risk Factors” are conditions that may cause investment in our Company to be speculative or risky. In light of developments during the first quarter of fiscal 2010, we have decided to update our Risk Factors as set forth below. Other than these updates, we are not currently aware of factors other than those set forth in our Annual Report on Form 10-K that would have a foreseeable effect on the level of risk associated with investment in our Company; however, additional risks and uncertainties not currently known to us or that we currently deem to be immaterial might materially adversely affect our actual business, financial condition and/or operating results.

The California Low Carbon Fuel Standard may decrease demand for corn based ethanol which could negatively impact our profitability. Recently, California passed a Low Carbon Fuels Standard (LCFS). The California LCFS requires that renewable fuels used in California must accomplish certain reductions in greenhouse gases which are measured using a lifecycle analysis. Management believes that these new regulations could preclude corn based ethanol produced in the Midwest from being used in California. California represents a significant ethanol demand market. If we are unable to supply ethanol to California, it could significantly reduce demand for the ethanol we produce. Any decrease in ethanol demand could negatively impact ethanol prices which could reduce our revenues and negatively impact our ability to profitably operate the ethanol plant.

If the Federal Volumetric Ethanol Excise Tax Credit (“VEETC”) expires on December 31, 2010, it could negatively impact our profitability . The ethanol industry is benefited by VEETC which is a federal excise tax credit of 4.5 cents per gallon of ethanol blended with gasoline at a rate of at least 10%. This excise tax credit is set to expire on December 31, 2010. We believe that VEETC positively impacts the price of ethanol. On December 31, 2009, the portion of VEETC that benefits the biodiesel industry was allowed to expire. This resulted in the biodiesel industry ceasing to produce biodiesel because the price of biodiesel without the tax credit was uncompetitive with the cost of petroleum based diesel. If the portion of VEETC that benefits ethanol is allowed to expire, it could negatively impact the price we receive for our ethanol and could negatively impact our profitability.

If the secondary tariff on imported ethanol is allowed to expire in January 2011, we could see an increase in ethanol produced in foreign countries being marked in the Untied States which could negatively impact our profitability. The secondary tariff on imported ethanol is a 54 cent per gallon tariff on ethanol imports from certain foreign countries. The secondary tariff on imported ethanol is scheduled to expire in January 2011. If this tariff is allowed to expire, an influx of imported ethanol on the domestic ethanol market could have a significant negative impact on ethanol prices and our profitability.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4 Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits. The following exhibits are included herein:

Exhibit No.		Description
10.1		Employment Agreement between Red Trail Energy, LLC and Gerald Bachmeier dated July 8, 2010.

31.1		Certificate Pursuant to 17 CFR 240.15d-14(a).

31.2		Certificate Pursuant to 17 CFR 240.15d-14(a).

32.1		Certificate Pursuant to 18 U.S.C. § 1350.

32.2		Certificate Pursuant to 18 U.S.C. § 1350.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		RED TRAIL ENERGY, LLC

Date:	August 13, 2010	/s/ Gerald Bachmeier
		Gerald Bachmeier
		Chief Executive Officer

Date:	August 13, 2010	/s/ Kent Anderson
		Kent Anderson
		Chief Financial Officer

	17.	Miscellaneous.

	(a)	The terms and conditions of this Agreement shall inure to the benefit of and be binding upon the parties hereto and the respective legal representatives, successors, and assigned of both of the parties hereto.

	(b)	This Agreement is made pursuant to and shall be construed under the laws of the State of North Dakota.

	(c)	This Agreement shall be executed in two (2) counterparts, but each of these counterparts shall, for all purposes, be deemed to be an original, but both counterparts shall together constitute one and the same instrument.

EMPLOYEE:	EMPLOYER:

	RED TRAIL ENERGY, LLC

/s/ Gerald Bachmeier	By:	/s/ Mike Appert	(signature)
Gerald Bachmeier, Employee		Mike Appert	(printed)
	Its:	Chairman	(title)