Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - SOUTHWEST IOWA RENEWABLE ENERGY, LLCFinancial_Report.xls
EX-32.1 - EXHIBIT - SOUTHWEST IOWA RENEWABLE ENERGY, LLCsire-2013331x10qex321.htm
EX-31.1 - EXHIBIT - SOUTHWEST IOWA RENEWABLE ENERGY, LLCsire-2013331x10qex311.htm
EX-31.2 - EXHIBIT - SOUTHWEST IOWA RENEWABLE ENERGY, LLCsire-2013331x10qex312.htm
EX-32.2 - EXHIBIT - SOUTHWEST IOWA RENEWABLE ENERGY, LLCsire-2013331x10qex322.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark one)
ý
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 
 
 
 
For the quarterly period ended March 31, 2013

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

For the transition period from _________ to __________

Commission file number 000-53041

SOUTHWEST IOWA RENEWABLE ENERGY, LLC
(Exact name of registrant as specified in its charter)
 
 
Iowa
20-2735046
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
10868 189th Street, Council Bluffs, Iowa
51503
(Address of principal executive offices)
(Zip Code)
 
 
Registrant’s telephone number (712) 366-0392
 
 
Securities registered under Section 12(b) of the Exchange Act:
None.
 
 
Title of each class
Name of each exchange on which registered
 
 
Securities registered under Section 12(g) of the Exchange Act:
Series A Membership Units
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o     No x
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o     No x
 
Indicate by check mark whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x     No o
 
Indicate by check mark whether the registrant has submitted electronically on its corporate Website, 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 x     No o






Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  o       Accelerated filer o       Non-accelerated filer o       Smaller reporting company x
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No x
As of March 31, 2013, the aggregate market value of the Membership Units held by non-affiliates (computed by reference to the most recent offering price of such Membership Units) was $52,134,000.

As of March 31, 2013, the Company had 8,805 Series A, 3,334 Series B and 1,000 Series C Membership Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE—None




TABLE OF CONTENTS
 




PART I – FINANCIAL STATEMENTS
 
Item 1. Financial Statements

1



SOUTHWEST IOWA RENEWABLE ENERGY, LLC
Balance Sheets
(Dollars in thousands)
ASSETS
March 31, 2013
 
September 30, 2012
 
(Unaudited)
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
11,930

 
$
6,285

Restricted cash
303

 
302

Accounts receivable
271

 
268

Accounts receivable, related party
11,295

 
12,088

Derivative financial instruments
956

 
976

Inventory
15,519

 
12,427

Derivative financial instruments, related party

 
4,013

Prepaid expenses and other
817

 
394

Total current assets
41,091

 
36,753

 
 
 
 
Property, Plant and Equipment
 
 
 
Land
2,064

 
2,064

Plant, building and equipment
204,598

 
204,597

Office and other equipment
751

 
751

 
207,413

 
207,412

Accumulated depreciation
(59,298
)
 
(53,679
)
Net property and equipment
148,115

 
153,733

 
 
 
 
Other Assets
 
 
 
Financing costs, net of amortization of $3,472 and  $3,202, respectively
731

 
1,001

Other assets
896

 
896

 
1,627

 
1,897

Total Assets
$
190,833

 
$
192,383

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

2



SOUTHWEST IOWA RENEWABLE ENERGY, LLC
Balance Sheets
(Dollars in thousands)
LIABILITIES AND MEMBERS' EQUITY
March 31, 2013
 
September 30, 2012
 
(Unaudited)
 
 
Current Liabilities
 
 
 
Accounts payable
$
1,015

 
$
1,366

Accounts payable, related parties
6,046

 
3,937

Derivative financial instruments, related party
978

 

Accrued expenses
2,738

 
2,837

Accrued expenses, related parties
1,347

 
1,657

Current maturities of notes payable
30,448

 
20,001

Total current liabilities
42,572

 
29,798

 
 
 
 
Long Term Liabilities
 
 
 
Notes payable, less current maturities
111,856

 
115,023

Other long-term  liabilities
450

 
500

Total long term liabilities
112,306

 
115,523

 
 
 
 
 

 

 
 
 
 
Members' Equity
 
 
 
Members' capital
 
 
 
13,139 Units issued and outstanding
76,474

 
76,474

Accumulated (deficit)
(40,519
)
 
(29,412
)
Total members' equity
35,955

 
47,062

 
 
 
 
Total Liabilities and Members' Equity
$
190,833

 
$
192,383

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

3



SOUTHWEST IOWA RENEWABLE ENERGY, LLC
Statements of Operations
(Dollars in thousands)
(Unaudited)
 
Three Months Ended
 
Three Months Ended
 
Six Months Ended
 
Six Months Ended
 
March 31, 2013
 
March 31, 2012
 
March 31, 2013
 
March 31, 2012
 
 
 
 
 
 
 
 
Revenues
$
79,197

 
$
89,880

 
$
153,524

 
$
185,077

Cost of Goods Sold
 
 
 
 
 
 
 
Cost of goods sold-non hedging
76,839

 
90,795

 
155,126

 
176,612

Realized & unrealized hedging (gains) losses
1,486

 
(346
)
 
2,779

 
(3,737
)
 
78,325

 
90,449

 
157,905

 
172,875

 
 
 
 
 
 
 
 
Gross Margin (Loss)
872

 
(569
)
 
(4,381
)
 
12,202

 
 
 
 
 
 
 
 
General and administrative expenses
931

 
1,017

 
1,988

 
2,330

 
 
 
 
 
 
 
 
Operating Income (Loss)
(59
)
 
(1,586
)
 
(6,369
)
 
9,872

 
 
 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
 
 
Interest and other income
36

 
58

 
56

 
70

Interest expense
(2,401
)
 
(2,459
)
 
(4,794
)
 
(4,933
)
 
(2,365
)
 
(2,401
)
 
(4,738
)
 
(4,863
)
 
 
 
 
 
 
 
 
Net Income (Loss)
$
(2,424
)
 
$
(3,987
)
 
$
(11,107
)
 
$
5,009

 
 
 
 
 
 
 
 
Weighted Average Units Outstanding
13,139

 
13,139

 
13,139

 
13,139

Net Income (loss) per unit, basic & diluted
(184.49
)
 
(303.42
)
 
(845.35
)
 
381.20

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

4



SOUTHWEST IOWA RENEWABLE ENERGY, LLC
Condensed Statements of Cash Flows
(Dollars in thousands)
(Unaudited)
 
Six Months Ended
 
Six Months Ended
 
March 31, 2013
 
March 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
(11,107
)
 
$
5,009

Adjustments to reconcile to net cash provided by operating activities:
 
 
 
Depreciation
5,698

 
5,707

Amortization
270

 
226

Accrued interest added to long term debt
1,941

 
1,717

Gain on disposal of property
18

 
11

(Increase) decrease in current assets:
 
 
 
Accounts receivable
790

 
5,345

Inventories
(3,092
)
 
(296
)
Prepaid expenses and other
(423
)
 
(586
)
Derivative financial instruments, related party
4,991

 
(1,667
)
Derivative financial instruments
20

 
(2,313
)
Decrease in other long-term liabilities
(50
)
 
(50
)
Increase (decrease) in current liabilities:
 
 
 
Accounts payable
1,758

 
648

Accrued expenses
(409
)
 
(691
)
Net cash provided by operating activities
405

 
13,060

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Purchase of property and equipment
(98
)
 
(308
)
Increase in restricted cash
(1
)
 
1

Net cash (used in) investing activities
(99
)
 
(307
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Payments for financing costs

 
(110
)
Proceeds from notes payable
27,000

 
2,481

Payments on borrowings
(21,661
)
 
(16,058
)
Net cash provided by (used in) financing activities
5,339

 
(13,687
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
5,645

 
(934
)
 
 
 
 
CASH AND EQUIVALENTS
 
 
 
Beginning
6,285

 
11,007

Ending
$
11,930

 
$
10,073

 
 
 
 
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES
 
 
 
Use of deposit for financing fee
$

 
$
203

 
 
 
 
SUPPLEMENTAL CASH FLOW INFORMATION
 
 
 
Cash paid for interest
$
2,573

 
$
5,750

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

5



SOUTHWEST IOWA RENEWABLE ENERGY, LLC
Notes to Condensed Financial Statements
Note 1:  Nature of Business
Southwest Iowa Renewable Energy, LLC (the “Company”), located in Council Bluffs, Iowa, was formed in March, 2005 and began producing ethanol in February, 2009.  The Company can operate at up to 100% of its 110 million gallon nameplate capacity. The Company sells its ethanol, modified wet distillers grains with solubles, corn syrup, and corn oil in the continental United States.  The Company sells its dried distillers grains with solubles in the continental United States, Mexico, and the Pacific Rim.
 
Note 2:  Summary of Significant Accounting Policies
Basis of Presentation and Other Information
The balance sheet as of September 30, 2012 was derived from the Company’s audited balances as of that date. The accompanying financial statements as of and for the three and six month periods ended March 31, 2013 and 2012 are unaudited and reflect all adjustments (consisting only of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. These unaudited financial statements and notes should be read in conjunction with the audited financial statements and notes thereto, for the fiscal year ended September 30, 2012 contained in the Company’s Annual Report on Form 10-K. The results of operations for the interim periods presented are not necessarily indicative of the results for the entire year.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from these estimates.
Revenue Recognition
The Company sells ethanol and related products pursuant to marketing agreements.  Revenues are recognized when the marketing company (the “customer”) has taken title to the product, prices are fixed or determinable and collectability is reasonably assured. 
The Company’s products are generally shipped FOB loading point.  The Company’s ethanol sales are handled through an ethanol purchase agreement (the “Ethanol Agreement”) with Bunge North America, Inc. (“Bunge”).  Syrup, distillers grains with solubles, and modified wet distillers grains with solubles (co-products) are sold through a distillers grains agreement (the “DG Agreement”) with Bunge, based on market prices. Corn oil is sold through a corn oil agreement (the “Corn Oil Agency Agreement”) with Bunge based on market prices.   Marketing fees, agency fees, and commissions due to the marketers are paid separately from the settlement for the sale of the ethanol products and co-products and are included as a component of cost of goods sold.  Shipping and handling costs incurred by the Company for the sale of ethanol and co-products are included in cost of goods sold.
Accounts Receivable
Trade accounts receivable are recorded at original invoice amounts less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis.  Most of the trade accounts are with Bunge. Management determines the allowance for doubtful accounts by regularly evaluating customer receivables and considering customer’s financial condition, credit history and current economic conditions.  As of March 31, 2013, management had determined no allowance was necessary.  Receivables are written off when deemed uncollectible and recoveries of receivables written off are recorded when received.
Investment in Commodities Contracts, Derivative Instruments and Hedging Activities
The Company’s operations and cash flows are subject to fluctuations due to changes in commodity prices.  The Company is subject to market risk with respect to the price and availability of corn, the principal raw material used to produce ethanol and ethanol by-products.  Exposure to commodity price risk results from the Company’s dependence on corn in the ethanol production process.  In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions.  This

6



is especially true when market conditions do not allow the Company to pass along increased corn costs to customers.  The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade and global demand and supply.
To minimize the risk and the volatility of commodity prices, primarily related to corn and ethanol, the Company uses various derivative instruments, including forward corn, ethanol and distillers grains purchase and sales contracts, over-the-counter and exchange-trade futures and option contracts.  When the Company has sufficient working capital available, it will enter into derivative contracts to hedge its exposure to price risk related to forecasted corn needs and forward corn purchase contracts.  The Company uses cash, futures and options contracts to hedge changes to the commodity prices of corn and ethanol.
Management has evaluated the Company’s contracts to determine whether the contracts are derivative instruments. Certain contracts that literally meet the definition of a derivative may be exempted from derivative accounting 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.   Gains and losses on contracts designated as normal purchases or normal sales contracts are not recognized until quantities are delivered or utilized in production.
The Company applies the normal purchase and sale exemption to forward contracts relating to ethanol and distillers grains and solubles and therefore these forward contracts are not marked to market. As of March 31, 2013, the Company was committed to sell 0.731 million gallons of ethanol and 52,364 tons of distillers grains and solubles.
Forward corn purchase contracts are recognized as derivatives. Changes in fair value of forward corn contracts, which are marked to market each period, are included in costs of goods sold.  As of March 31, 2013, the Company was committed to purchasing 2.045 million bushels of corn on a forward contract basis resulting in a total commitment of $15,400,102.  These forward contracts had a fair value of $14,422,371 at March 31, 2013. There are 5.118 million bushels in basis commitments, the price of which is at market price at time of purchase.
In addition, the Company enters into short-term cash, options and futures contracts as a means of managing exposure to changes in commodity prices.  The Company enters into derivative contracts to hedge the exposure to volatile commodity price fluctuations.  The Company maintains a risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by market volatility.  The Company’s specific goal is to protect itself from large moves in commodity costs.   Although the contracts are intended to be effective economic hedges of specified risks, they are not designated as a hedge for accounting purposes and are recorded on the balance sheet at fair market value with changes in fair value recognized in current period earnings.
As part of its trading activity, the Company uses futures and option contracts offered through regulated commodity exchanges to reduce risk and risk of loss in the market value of inventories.  To reduce that risk, the Company generally takes positions using cash and futures contracts and options. The gains or losses on derivative instruments are included in revenue if the contracts relate to ethanol and cost of goods sold if the contracts relate to corn. During the six months ended March 31, 2013 and March 31, 2012, the Company recorded a combined realized and unrealized (gain) loss of $2,778,530 and ($3,737,067), respectively, as a component of cost of goods sold. During the six months ended March 31, 2013 and 2012, the Company did not record any gain (loss) on ethanol derivative contracts. The Company reports all contracts with the same counter-party on a net basis on the balance sheet due to a master netting agreement.
Derivatives not designated as hedging instruments along with cash held by brokers at March 31, 2013 and September 30, 2012 are as follows:

7



 
Balance Sheet Classification
 
March 31, 2013
 
September 30, 2012
Futures and option contracts
 
 
 
 
 
In gain position
 
 
$
682,175

 
$
806,710

In loss position 
 
 
(63,263
)
 
(1,668,970
)
Cash held by broker
 
 
337,382

 
1,838,048

 
Current asset
 
956,294

 
975,788

 
 
 
 
 
 
Forward contracts, corn, related party
Current asset
 

 
4,013,005

 
 
 

 


Forward contracts, corn, related party
Current (Liability)
 
$
(977,731
)
 
$

 
 
 
 
 
 
Net futures and options contracts
 
 
$
(21,437
)
 
$
979,801


The net realized and unrealized gains and losses on the Company’s derivative contracts for the three months ended March 31, 2013 and 2012 consist of the following:
 
Statement of Operations Classification
 
March 31, 2013
 
March 31, 2012
Net realized and unrealized (gains) losses related to:
 
 
 
 
 
Purchase contracts (corn):
 
 
 
 
 
Forward contracts
Cost of Goods Sold
 
$
2,109,287

 
$
870,324

Futures and option contracts
Cost of Goods Sold
 
$
(624,023
)
 
(1,216,751
)

The net realized and unrealized gains and losses on the Company’s derivative contracts for the six months ended March 31, 2013 and 2012 consist of the following:
 
Statement of Operations Classification
 
March 31, 2013
 
March 31, 2012
Net realized and unrealized (gains) losses related to:
 
 
 
 
 
Purchase contracts (corn):
 
 
 
 
 
Forward contracts
Cost of Goods Sold
 
$
4,709,032

 
$
(1,372,202
)
Futures and option contracts
Cost of Goods Sold
 
$
(1,930,502
)
 
$
(2,364,865
)
 
Inventory
Inventory is stated at the lower of cost or market value using the average cost method.  Market value is based on current replacement values, except that it does not exceed net realizable values and it is not less than the net realizable values reduced by an allowance for normal profit margin.
Property and Equipment
Property and equipment are stated at cost.  Depreciation is computed using the straight-line method over the following estimated useful lives:

8



 
Buildings   
40 Years
 
 
 
 
 
 
Process Equipment 
10 - 20 Years
 
 
 
 
 
 
Office Equipment   
3-7 Years
 
 
Maintenance and repairs are charged to expense as incurred; major improvements and betterments are capitalized.  
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable.   An impairment loss would be recognized when estimated undiscounted future cash flows from operations are less than the carrying value of the asset group.  An impairment loss would be measured by the amount by which the carrying value of the asset exceeds the fair value of the asset.  In accordance with Company policies, management has evaluated the plant for possible impairment based on projected future cash flows from operations. In accordance with Company policies, management found no event to have occurred that would trigger an evaluation of the plant for possible impairment on future cash flows from operations  as of March 31, 2013
Net income (loss) per unit
Net income (loss) per unit has been computed on the basis of the weighted average number of units outstanding during each period presented.
Fair value of financial instruments
The carrying amounts of cash and cash equivalents, restricted cash, derivative financial instruments, accounts receivable, accounts payable and accrued expenses approximate fair value due to the short term nature of these instruments. The fair value of financial instruments are valued under Level 2 inputs except for derivative financial instruments which are valued as disclosed in Note 6. The Company believes it is not practical to estimate the fair value of debt due to the lack of comparable available credit facilities.

Note 3:  Inventory
Inventory is comprised of the following at:
 
March 31, 2013
 
September 30, 2012
 
(000's)
 
(000's)
Raw Materials - corn
$
4,536

 
$
2,731

Supplies and Chemicals
2,698

 
2,661

Work in Process
3,201

 
3,225

Finished Goods
5,084

 
3,810

Total
$
15,519

 
$
12,427

 
 
Note 4:   Members’ Equity
At March 31, 2013 outstanding member units were:
A Units
8,805

B Units
3,334

C Units
1,000

 
 
The Series A, B and C unit holders all vote on certain matters with equal rights.  The Series C unit holders as a group have the right to elect one member of the Board of Directors (the “Board”).  The Series B unit holders as a group have the right

9



to elect the number of Board members which bears the same proportion to the total number of Directors in relation to Series B outstanding units to total outstanding units. Based on this calculation, the Series B unit holders currently have the right to elect two Board members.  Series A unit holders as a group have the right to elect the remaining number of Directors not elected by the Series C and B unit holders.

Note 5:   Revolving Loan/Credit Agreements
AgStar
The Company entered into a Credit Agreement, as amended (the “Credit Agreement”) with AgStar Financial Services, PCA (“AgStar”) and a group of lenders (together with AgStar, the “Lenders”) for $126,000,000 senior secured debt, consisting of a $101,000,000 term loan, a term revolver of $10,000,000 and a revolving working capital term facility of $15,000,000. On March 29, 2013, the Company and AgStar entered into an amendment to the Credit Agreement to extent the term of the revolving working capital term facility through October 31, 2013 and eliminate the tangible net worth covenant; however the available credit under such revolving facility was reduced to $13,214,000. Borrowings under the loan initially accrue interest at a variable interest rate based on LIBOR plus 4.45% for each advance under the Credit Agreement.   On September 1, 2011, the Company elected to convert 50% of the term note into a fixed rate loan at the lender’s bonds rate plus 4.45%, with a 6% floor (the rate was a fixed 6% at March 31, 2013).  The portion of the term loan not fixed and the term revolving line of credit accrue interest equal to LIBOR plus 4.45%, with a 6% floor.
The Credit Agreement requires compliance with certain financial and non-financial covenants.  As of March 31, 2013, the Company was in compliance with all required covenants. Borrowings under the Credit Agreement are collateralized by substantially all of the Company’s assets.  The term credit facility of $101,000,000 requires monthly principal payments.  The loan is amortized over 114 months and matures five years after the conversion date, on August 1, 2014.  Any borrowings are subject to borrowing base restrictions as well as certain prepayment penalties.  The $10,000,000 term revolver is interest only until maturity on August 1, 2014.
Under the terms of the Credit Agreement, as amended on March 29, 2013, the Company may draw a maximum $13,214,300 or 75 percent of eligible accounts receivable and eligible inventory on the revolving working capital term facility.  As part of the revolving line of credit, the Company may request letters of credit to be issued up to a maximum of $5,000,000 in the aggregate.    There were no outstanding letters of credit as of March 31, 2013. The revolving working capital term facility matures on October 31, 2013. There is $3,214,000 available under this loan as of March 31, 2013.
As of March 31, 2013 and September 30, 2012, the outstanding balance under the Credit Agreement was $83,979,706 and $84,866,648, respectively.  In addition to all the other payments due under the Credit Agreement, the Company must pay an annual amount equal to 65% of the Company’s Excess Cash Flow (as defined in the Credit Agreement), up to a total of $6,000,000 per year, and $24,000,000 over the term of the Credit Agreement.  No Excess Cash Flow payment is due at March 31, 2013.
The Company is in compliance with all financial covenants under the Credit Agreement as of March 31, 2013. However, in the event that the market continues to experience significant price volatility and negative crush margins near the current levels or in excess of current levels, it may be difficult to comply with the financial covenants. The banks’ response to non-compliance is unknown at this time. The Company may be required to explore alternative methods to meet our short-term liquidity needs including temporary shutdowns of operations, temporary reductions in production levels, or negotiating short-term concessions from lenders.  
Bunge
Bunge N.A. Holdings, Inc. (“Holdings”), an affiliate of Bunge, extended credit to the Company under a subordinated convertible term note, originally dated August 26, 2009 which was assigned by Holdings to Bunge effective September 28, 2012 (the “Bunge Note”). The Bunge Note is due on August 31, 2014 and repayment is subordinated to the Credit Agreement. The Bunge Note is convertible into Series U Units, at the option of Bunge, at the price of $3,000 per Unit.  Interest accrues at the rate of 7.5% over six-month LIBOR.  Principal and interest may be paid only after payment in full under the Credit Agreement.  The balance, as of March 31, 2013 and September 30, 2012, was $35,349,149 and$33,922,334, respectively, under the Bunge Note.  There was $461,607 and $473,162 of accrued interest (included in accrued expenses, related parties) due to Bunge as of March 31, 2013 and September 30, 2012, respectively. Interest on the note accrues monthly and is added to the note principal on February 1st and August 1st each year.
The Company entered into a revolving note with Holdings dated August 26, 2009, providing for a maximum of $10,000,000 in revolving credit (the “Bunge Revolving Note”) which was assigned to Bunge effective September 28, 2012. Bunge

10



has a commitment, subject to certain conditions, to advance up to $3,750,000 at the Company’s request under the Bunge Revolving Note; amounts in excess of $3,750,000 may be advanced by Bunge in its discretion.  Interest accrues at the rate of 7.5% over six-month LIBOR.  While repayment of the Bunge Revolving Note is subordinated to the Credit Agreement, the Company may make payments on the Bunge Revolving Note so long as it is in compliance with its borrowing base covenant and there is not a payment default under the Credit Agreement. The balance under the Bunge Revolving Note, as of March 31, 2013 and September 30, 2012, was $10,000,000 and $3,750,000, respectively.
ICM    
On June 17, 2010, ICM, Inc. (“ICM”) entered into a subordinated convertible term note to the Company (the “ICM Term Note”) in the amount of $9,970,000, which is convertible at the option of ICM into Series C Units at a conversion price of $3,000 per unit.  As of March 31, 2013 and September 30, 2012, the accrued interest due (included in accrued expense, related party) to ICM was $159,097 and $163,068, respectively. Interest on the note accrues monthly and is added to the note principal on February 1st and August 1st  each year.
Notes payable consists of the following:
 
March 31, 2013

 
September 30, 2012

$300,000 Note payable to IDED, a non-interest bearing obligation with monthly payments of $2,500 due through the maturity date of March 26, 2016 on the non-forgivable portion.
$
235,000

 
$
250,000

Convertible Notes payable to unit holders, bearing interest at LIBOR plus 7.50 to 10.5% (7.97% at March 31, 2013); maturity on August 31, 2014.
553,805

 
531,508

Note payable to affiliate Bunge, N.A., bearing interest at LIBOR plus 7.50 to 10.5% (7.97% at March 31, 2013); maturity on August 31, 2014.
35,349,149

 
33,922,334

Note payable to affiliate ICM, bearing interest at LIBOR plus 7.50 to 10.5% (7.97% at March 31, 2013); maturity on August 31, 2014.
12,183,404

 
11,691,666

Term facility payable to AgStar bearing interest at LIBOR plus 4.45% with a 6.00% floor (6.00% at March 31, 2013); maturity on August 1, 2014.
31,025,053

 
33,745,859

Term facility payable to AgStar bearing interest at a fixed 6%; maturity on August 1, 2014.
32,954,653

 
35,245,790

Term revolver payable to AgStar bearing interest at LIBOR plus 4.45% with a 6.00% floor (6.00% at March 31, 2013); maturity on August 1, 2014.
10,000,000

 
10,000,000

$15 million revolving working capital term facility payable to AgStar bearing interest at LIBOR plus 4.45% with a 6.00% floor (6.00% at March 31, 2013), matured March 29, 2013.

 
5,875,000

$13.214 million revolving working capital term facility payable to AgStar bearing interest at LIBOR plus 4.45% with a 6.00% floor (6.00% at March 31, 2013), maturing October 31, 2013.
10,000,000

 

Capital leases payable to AgStar bearing interest at 3.088% maturing May 15, 2013.
3,088

 
12,256

Revolving line of credit payable to Bunge, bearing interest at LIBOR plus 7.50 to 10.5% with a floor of 3.00% (7.70% at March 31, 2013).
10,000,000

 
3,750,000

 
142,304,152

 
135,024,413

Less Current Maturities
(30,448,079
)
 
(20,001,369
)
Total Long Term Debt
111,856,073

 
115,023,044

 
 
 
 

The approximate aggregate maturities of notes payable as of March 31 are as follows:

11



2014
30,448,079

 
 
2015
111,681,073

 
 
2016
175,000

 
 
Total
142,304,152

 
Note 6:  Fair Value Measurement
Fair value is 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 determining fair value, the Company used various methods including market, income and cost approaches.  Based on these approaches, the Company often utilized certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable inputs.  The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  Based on the observable inputs used in the valuation techniques, the Company is required to provide the following information according to the fair value hierarchy.
The fair value hierarchy ranks the quality and reliability of the information used to determine fair values.  Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:
Level 1 -
Valuations for assets and liabilities traded in active markets from readily available pricing sources for market transactions involving identical assets or liabilities.
Level 2 -
Valuations for assets and liabilities traded in less active dealer or broker markets.  Valuations are obtained from third-party pricing services for identical or similar assets or liabilities.
Level 3 -
Valuations incorporate certain assumptions and projections in determining the fair value assigned to such assets or liabilities.
A description of the valuation methodologies used for instruments measured at fair value, including the general classifications of such instruments pursuant to the valuation hierarchy, is set below.
Derivative financial statements .  Commodity futures and exchange traded options are reported at fair value utilizing Level 1 inputs. For these contracts, the Company obtains fair value measurements from an independent pricing service.  The fair value measurements consider observable data that may include dealer quotes and live trading levels from the Chicago Mercantile Exchange (“CME”) market.  Ethanol contracts are reported at fair value utilizing Level 2 inputs from third-party pricing services.  Forward purchase contracts are reported at fair value utilizing Level 2 inputs.   For these contracts, the Company obtains fair value measurements from local grain terminal values.  The fair value measurements consider observable data that may include live trading bids from local elevators and processing plants which are based off the CME market.
The following table summarizes financial liabilities measured at fair value on a recurring basis as of March 31, 2013 and September 30, 2012, categorized by the level of the valuation inputs within the fair value hierarchy:

12



 
March 31, 2013
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
Derivative financial instruments
$
682,175

 
$

 
$

 
 
 
 
 
 
Liabilities:
 
 
 
 
 
Derivative financial instruments
63,263

 
977,731

 

 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2012
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
Derivative financial instruments
$
806,710

 
$
4,013,005

 
$

 
 
 
 
 
 
Liabilities:
 
 
 
 
 
Derivative financial instruments
1,668,970

 

 

 

 

13



Note 7:   Related Party Transactions and Major Customer
Bunge
On November 1, 2006, in consideration of its agreement to invest $20,004,000 in the Company, Bunge purchased the only Series B Units under an arrangement whereby the Company would (i) enter into various agreements with Bunge or its affiliates (discussed below) for management, marketing and other services, and (ii) have the right to elect a number of Series B Directors which are proportionate to the number of Series B Units owned by Bunge, as compared to all Units.  Under the Company’s Third Amended and Restated Operating Agreement (the “Operating Agreement”), the Company may not, without Bunge’s approval (i) issue additional Series B Units, (ii) create any additional Series of Units with rights which are superior to the Series B Units, (iii) modify the Operating Agreement to adversely impact the rights of Series B Unit holders, (iv) change its status from one which is managed by managers, or vise versa, (v) repurchase or redeem any Series B Units, (vi) take any action which would cause a bankruptcy, or (vii) approve a transfer of Units allowing the transferee to hold more than 17% of the Company’s Units or to a transferee which is a direct competitor of Bunge.
Under the Ethanol Agreement, the Company sells Bunge all of the ethanol produced at its facility, and Bunge purchases the same.  The Company pays Bunge a per-gallon fee for ethanol sold by Bunge, subject to a minimum annual fee of $750,000 and adjusted according to specified indexes after three years.  The Ethanol Agreement runs through August 31, 2014 and will automatically renew for successive three-year terms thereafter unless one party provides the other with notice of their election to terminate 180 days prior to the end of the term.  The Company has incurred expenses of $320,195 and  $380,406 during the three months ended March 31, 2013 and 2012, respectively, and $622,513 and $993,279 during the six months ended March 31, 2013 and 2012, respectively. under the Ethanol Agreement. Under a Risk Management Services Agreement effective January 1, 2009, Bunge agreed to provide the Company with assistance in managing its commodity price risks for a quarterly fee of $75,000.  The Risk Management Services Agreement has an initial term of three years and automatically renews for successive three year terms, unless one party provides the other notice of their election to terminate 180 days prior to the end of the term.  Expenses under the Risk Management Services Agreement for the three months ended March 31, 2013 and 2012 were $75,000 and for the six months ended March 31, 2013 and 2012 were $150,000.
On June 26, 2009, the Company executed a Railcar Agreement with Bunge for the lease of 325 ethanol cars and 300 hopper cars which are used for the delivery and marketing of ethanol and distillers grains.  Under the Railcar Agreement, the Company leases railcars for terms lasting 120 months and continuing on a month to month basis thereafter.  The Railcar Agreement will terminate upon the expiration of all railcar leases.  Expenses under this agreement for the three months ended March 31, 2013 and 2012 were $1,083,201 and $1,215,534, respectively. For the six months ended March 31, 2013 and 2012, expenses were $2,196,499 and $2,431,724, respectively. The Company has a sublease agreement for 100 hopper cars that are leased back to Bunge that expires on September 14, 2013.  As the sublease rate is less than the original lease rate, a loss was recorded at inception of the sublease and is being accreted to rent expense over the life of the sublease.
The Company entered into a Distillers Grain Purchase Agreement dated October 13, 2006, as amended (“DG Agreement”) with Bunge, under which Bunge is obligated to purchase from the Company and the Company is obligated to sell to Bunge all distillers grains produced at the Facility.  If the Company finds another purchaser for distillers grains offering a better price for the same grade, quality, quantity, and delivery period, it can ask Bunge to either market directly to the other purchaser or market to another purchaser on the same terms and pricing. The initial ten year term of the DG Agreement began February 1, 2009.  The DG Agreement automatically renews for additional three year terms unless one party provides the other party with notice of election to not renew 180 days or more prior to expiration.
Under the DG Agreement, Bunge pays the Company a purchase price equal to the sales price minus the marketing fee and transportation costs.  The sales price is the price received by Bunge in a contract consistent with the DG Marketing Policy or the spot price agreed to between Bunge and the Company.  Bunge receives a marketing fee consisting of a percentage of the net sales price, subject to a minimum yearly payment of $150,000.  Net sales price is the sales price less the transportation costs and rail lease charges.  The transportation costs are all freight charges, fuel surcharges, and other accessorial charges applicable to delivery of distillers grains.  Rail lease charges are the monthly lease payment for rail cars along with all administrative and tax filing fees for such leased rail cars.   Expenses under this agreement for the three months ended March 31, 2013 and 2012 were $577,402 and $550,085, respectively. Expenses for the six months ended March 31, 2013 and 2012 were $1,095,071 and $1,033,597, respectively.
On August 26, 2009, in connection with the original issuance of the Bunge Note to the Company also executed a Bunge Agreement—Equity Matters (the “Equity Agreement”), which was subsequently amended on June 17, 2010 and then assigned by Holdings to Bunge effective September 28, 2012. The Bunge Equity Agreement provides that (i) Bunge has preemptive rights to purchase new securities in the Company, and (ii) the Company is required to redeem any Series U Units held by Bunge with 76% of the proceeds received by the Company from the issuance of equity or debt securities.

14



The Company is a party to a Grain Feedstock Supply Agreement (the “Supply Agreement”) with Bunge.   Under the Supply Agreement, Bunge provides the Company with all of the corn it needs to operate our ethanol plant, and the Company has agreed to only purchase corn from Bunge.  Bunge provides grain originators who work at the Facility for purposes of fulfilling its obligations under the Supply Agreement.  The Company pays Bunge a per-bushel fee for corn under the Supply Agreement, subject to a minimum annual fee of $675,000 and adjustments according to specified indexes after three years.  The term of the Supply Agreement is 10 years, subject to earlier termination upon specified events. Expenses under this agreement for the three months ended March 31, 2013 and 2012 were $275,306 and $344,216, respectively. For the six months ended March 31, 2013 and 2012, expenses were $531,759 and $681,735, respectively. 
On November 12, 2010, the Company entered into a Corn Oil Agency Agreement with Bunge to market its corn oil (the “Corn Oil Agency Agreement”).  The Corn Oil Agency Agreement has an initial term of three years and will automatically renew for successive three-year terms unless one party provides the other notice of their election to terminate 180 days prior to the end of the term.  Expenses under this agreement for the three months ended March 31, 2013 and 2012 were $34,728 and $51,496, respectively. For the six months ended March 31, 2013 and 2012, expenses were $78,799 and $93,573, respectively. 
 
The Company and Bunge have also entered into certain term and revolving credit facilities. See Note 5 Revolving Loan/Credit Agreements for the terms of these financing arrangements.
ICM
On November 1, 2006, in consideration of its agreement to invest $6,000,000 in the Company, ICM became the sole Series C Member.  As part of ICM’s agreement to invest in Series C Units, the Operating Agreement provides that the Company will not, without ICM’s approval (i) issue additional Series C Units, (ii) create any additional Series of Units with rights senior to the Series C Units, (iii) modify the Operating Agreement to adversely impact the rights of Series C Unit holders, or (iv) repurchase or redeem any Series C Units.  Additionally, ICM, as the sole Series C Unit owner, is afforded the right to elect one Series C Director to the Board so long as ICM remains a Series C Member.
To induce ICM to agree to the ICM Term Note, the Company entered into an equity agreement with ICM (the “ICM Equity Agreement”) on June 17, 2010, whereby ICM (i) retains preemptive rights to purchase new securities in the Company, and (ii) receives 24% of the proceeds received by the Company from the issuance of equity or debt securities.
On July 13, 2010, the Company entered into a Joint Defense Agreement (the “Joint Defense Agreement”) with ICM, which contemplates that the Company may purchase from ICM one or more Tricanter centrifuges (the “Centrifuges“).  Because such equipment has been the subject of certain legal actions regarding potential patent infringement, the Joint Defense Agreement provides that: (i) that the parties may, but are not obligated to, share information and materials that are relevant to the common prosecution and/or defense of any such patent litigation regarding the Centrifuges (the “Joint Defense Materials”), (ii) that any such shared Joint Defense Materials will be and remain confidential, privileged and protected (unless such Joint Defense Materials cease to be privileged, protected or confidential through no violation of the Joint Defense Agreement), (iii) upon receipt of a request or demand for disclosure of Joint Defense Material to a third party, the party receiving such request or demand will consult with the party that provided the Joint Defense Materials and if the party that supplied the Joint Defense Materials does not consent to such disclosure then the other party will seek to protect any disclosure of such materials, (iv) that neither party will disclose Joint Defense Materials to a third party without a court order or the consent of the party who initially supplied the Joint Defense Materials, (v) that access to Joint Defense Materials will be restricted to each party’s outside attorneys, in-house counsel, and retained consultants, (vi) that Joint Defense Materials will be stored in secured areas and will be used only to assist in prosecution and defense of the patent litigation and (vii) if there is a dispute between us and ICM, then each party waives its right to claim that the other party’s legal counsel should be disqualified by reason of this the Joint Defense Agreement or receipt of Joint Defense Materials.  The Joint Defense Agreement will terminate the earlier to occur of (x) upon final resolution of all patent litigation and (y) a party providing ten (10) days advance written notice to the other party of its intent to withdraw from the Joint Defense Agreement.  No payments have been made by either party under the Joint Defense Agreement.
On August 25, 2010, the Company entered into a Tricanter Purchase and Installation Agreement (the “Tricanter Agreement”) with ICM, pursuant to which ICM sold the Company a tricanter oil separation system (the “Tricanter Equipment”). In addition, ICM installed the equipment at the Company’s ethanol plant in Council Bluffs, Iowa. As of March 31, 2013, the Company had paid $2,796,142 under the Tricanter Agreement with no amounts remaining due.
The Company and ICM have also entered into convertible term note.  See Note 5 Revolving Loan/Credit Agreements for the terms of this financing arrangement.
 

15



Note 8: Major Customers
The Company is party to the Ethanol, Supply, and Corn Oil Agency Agreements with Bunge for the exclusive marketing, selling, and distributing of all the ethanol, distillers grains, syrup, and corn oil produced by the Company. Revenues with this customer were $77,521,086 and $87,517,448 for the three months ended March 31, 2013 and 2012, respectively. Revenues with this customer were $149,731,474 and $180,402,009 for the six months ended March 31, 2013 and 2012, respectively.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
General
The following discussion and analysis provides information which management believes is relevant to an assessment and understanding of our consolidated financial condition and results of operations. This discussion should be read in conjunction with the consolidated financial statements included herewith and notes to the consolidated financial statements and our annual report on Form 10-K for the year September 30, 2012 including the consolidated financial statements, accompanying notes and the risk factors contained herein.

16



Forward Looking Statements
This Quarterly Report on Form 10-Q of Southwest Iowa Renewable Energy, LLC (the “Company,” “we,” or “us”)contains historical information, as well as forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance, or our expected future operations and actions.  In some cases, you can identify forward-looking statements by terminology such as “may,” “will”, “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “future,” “intend,” “could,” “hope,”  “predict,” “target,” “potential,” or “continue” or the negative of these terms or other similar expressions.  These forward-looking statements are only our predictions based on current information and involve numerous assumptions, risks and uncertainties.  Our actual results or actions may differ materially from these forward-looking statements for many reasons, including the reasons described in this report.  While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:
Changes in the availability and price of corn, natural gas, and steam;
Our inability to comply with our credit agreements required to continue our operations;
Negative impacts that our hedging activities may have on our operations;
Decreases in the market prices of ethanol and distillers grains;
Ethanol supply exceeding demand; and corresponding ethanol price reductions;
Changes in the environmental regulations that apply to our plant operations;
Changes in plant production capacity or technical difficulties in operating the plant;
Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agriculture, oil or automobile industries;
Changes in federal and/or state laws (including the elimination of any federal and/or state ethanol tax incentives);
Changes and advances in ethanol production technology;
Additional ethanol plants built in close proximity to our ethanol facility in  southwest Iowa;
Competition from alternative fuel additives;
Changes in interest rates and lending conditions of our loan covenants;
Our ability to retain key employees and maintain labor relations; and
Volatile commodity and financial markets;
Continued price volatility in the price of corn;.
Decreased ethanol prices resulting from  the oversupply of ethanol; and
Expiration of the blenders’ credit and the secondary tariff on imported ethanol. 

These forward-looking statements are based on management’s estimates, projections and assumptions as of the date hereof and include the assumptions that underlie such statements. 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 reports.   Any expectations based on these forward-looking statements are subject to risks and uncertainties and other important factors, including those discussed below and in the section titled “Risk Factors” In our Form 10-K for the fiscal year ended September 30, 2012 and in our other prior Securities and Exchange Commission filings. These and many other factors could affect our future financial condition and operating results and could cause actual results to differ materially from expectations based on forward-looking statements made in this document or elsewhere by the Company or on its behalf.  We undertake no obligation to revise or update any forward-looking statements.  The forward-looking statements contained in this report are included in the safe harbor protection provided by Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended.

17



Overview, Status and Recent Developments
The Company is an Iowa limited liability company, located in Council Bluffs, Iowa, formed in March, 2005 to construct and operate a 110 million gallon capacity ethanol plant.  We began producing ethanol in February, 2009 and sell our ethanol, modified wet distillers grains with solubles, corn oil and corn syrup in the continental United States.  We sell our dried distillers grains with solubles in the continental United States, Mexico, and the Pacific Rim.

One of the by-products of ethanol production is CO2. Effective April 2, 2013, the Company and an unaffiliated party, EPCO Carbon Dioxide Products, Inc., an Illinois corporation ("EPCO”), entered into a Carbon Dioxide Purchase and Sale Agreement (the “EPCO Agreement”) pursuant to which the Company has agreed to supply, and EPCO has agreed to purchase, a portion of raw CO2 gas produced by the Company’s ethanol plant which meets certain specifications. EPCO will lease a portion of the Company’s property under a separate written lease, on which EPCO will construct a carbon dioxide liquefaction plant (the “EPCO Plant”). EPCO will use the EPCO Plant for the sole purpose of producing, marketing and selling food grade CO2 from the raw CO2 that EPCO purchases from the Company. Upon completion of the EPCO Plant and production thereunder the Company anticipates it will report sales of CO2.

Industry Factors Affecting our Results of Operations

During the three months ended March 31, 2013, the ethanol industry continued to experience compressed ethanol margins as a result of a combination of factors, including the following:

Corn prices increased substantially during the year ended September 30, 2012 ("Fiscal 2012") and traded at all-time highs during the fourth quarter of Fiscal 2012. Prices receded slightly in the first calendar year quarter but still remain high. For the three months ended March 31, 2013 compared to the three months ended March 31, 2012, the price per bushel paid was $7.36 and $6.46, respectively.  
The U.S. Department of Agriculture forecasts a decrease in ethanol production as a result of lower ethanol demand. According to Energy Information Administration ("EIA"), industry average weekly production decreased 8.4% for the twelve months ended April 12, 2013 compared to the similar time period last year. Average production for the twelve weeks ended April 12, 2013 was 808 thousand barrels per day compared to 818 thousand barrels per day for the previous twelve weeks from October 25, 2012 to January 11, 2013, a 1.8% decrease.
Reduced demand for motor fuels in the U.S. resulting from higher gasoline prices and more fuel efficient vehicles.
Increased imports of ethanol from foreign producers, principally Brazil which represented 70%, for the twelve months ended January 31, 2013, shipments received in U.S. ports, according to the Renewable Fuels Association.
 
The combination of these factors continued to cause ethanol margins to be compressed in the three months ended March 31, 2013 compared to the levels during the three months ended March 31, 2012. In response to the compressed margin environment, according to the EIA, as an industry, ethanol producers reduced production rates from 82,355 thousand barrels for the thirteen weeks ended April 13, 2012 to 73,645 thousand barrels for the thirteen weeks ended April 12, 2013, representing a 10.6% decrease.  Although it appears that the margin environment in the third quarter of the year ended September 30, 2013 ("Fiscal 2013") might improve, it is likely that the margin environment will continue to be affected by these factors as well throughout Fiscal 2013.  We believe that U.S. ethanol production levels will continue to adjust to ethanol and corn supply and demand factors. However, extended periods of depressed ethanol margins have adversely affected our operating results in the six months ended March 31, 2013. Overall, the 2012 drought created a shortage in the corn supply and caused many ethanol producers to either stop or decrease ethanol production. This shortage will continue until the new 2013 crop is harvested. Corn supply in 2013 will depend on no lingering effects of the 2012 drought, impact of moisture on the ability of corn producers to plant, and the number of corn acres planted.
Because of the many environmental factors, principal that affected our results of operations, production was decreased substantially in the first quarter of Fiscal 2013 and only slightly increased back toward capacity in the second quarter of Fiscal 2013. As a result of management's decision to mitigate the environmental factors' impact on operations, the loss for the three months ended March 31, 2013 was $2.4 million compared to a larger loss of $4.0 million for the three months ended March 31, 2012.
    

Results of Operations

18



The following table shows our results of operations, stated as a percentage of revenue for the three months ended March 31, 2013 and 2012.
 
For the three months ended
 
For the three months ended
 
March 31, 2013
 
March 31, 2012
 
Amounts
 
% of Revenues
 
Gallons Average Price
 
Amounts
 
% of Revenues
 
 
Gallons Average Price
 
in 000's
 
 
 
 
 
in 000's
 
 
 
 
 
Income Statement Data
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
79,197

 
100.0
 %
 
$
3.21

 
89,880

 
100.0
 %
 
 
$
2.75

Cost of Good Sold
 
 
 
 
 
 
 
 
 
 
 
 
Material Costs
64,745

 
81.8
 %
 
2.63

 
74,561

 
83.0
 %
 
 
2.29

Variable Production Exp
7,853

 
9.9
 %
 
0.32

 
9,820

 
10.9
 %
 
 
0.29

Fixed Production Exp
5,727

 
7.2
 %
 
0.23

 
6,068

 
6.8
 %
 
 
0.19

Gross Margin (loss)
872

 
1.1
 %
 
0.03

 
(569
)
 
(0.7
)%
 
 
(0.02
)
General and Administrative Expenses
931

 
1.2
 %
 
0.04

 
1,017

 
1.1
 %
 
 
0.03

Other Expenses
2,365

 
3.0
 %
 
0.10

 
2,401

 
2.7
 %
 
 
0.07

Net (Loss)
(2,424
)
 
(3.1
)%
 
$
(0.11
)
 
(3,987
)
 
(4.5
)%
 
 
$
(0.12
)

The following table shows our results of operations, stated as a percentage of revenue for the six months ended March 31, 2013 and 2012.
 
For the six months ended
 
For the six months ended
 
March 31, 2013
 
March 31, 2012
 
Amounts
 
% of Revenues
 
Gallons Average Price
 
Amounts
 
% of Revenues
 
Gallons Average Price
 
in 000's
 
 
 
 
 
in 000's
 
 
 
 
Income Statement Data
 
 
 
 
 
 
 
 
 
 
 
Revenues
153,524

 
100.0
 %
 
$
3.12

 
185,077

 
100.0
%
 
$
2.91

Cost of Good Sold
 
 
 
 
 
 
 
 
 
 
 
Material Costs
130,654

 
85.1
 %
 
2.65

 
141,207

 
76.3
%
 
2.23

Variable Production Exp
16,028

 
10.4
 %
 
0.33

 
19,925

 
10.8
%
 
0.31

Fixed Production Exp
11,223

 
7.3
 %
 
0.23

 
11,743

 
6.3
%
 
0.18

Gross Margin (loss)
(4,381
)
 
(2.8
)%
 
(0.09
)
 
12,202

 
6.6
%
 
0.19

General and Administrative Expenses
1,988

 
1.3
 %
 
0.04

 
2,330

 
1.3
%
 
0.04

Other Expenses
4,738

 
3.1
 %
 
0.10

 
4,863

 
2.6
%
 
0.08

Net Income (Loss)
(11,107
)
 
(7.2
)%
 
$
(0.23
)
 
5,009

 
2.7
%
 
$
0.07


 
 
Revenues
 
Our revenue from operations is derived from three primary sources: sales of ethanol, distillers grains, and corn oil.  The following chart displays statistical information regarding our revenues. We experienced a similar crush margin compression as the whole industry in the first quarter. In response to this crush margin compression, production was decreased in the first and second fiscal quarters. Crush margins started to decompress during the second quarter and as a result, production was increased

19



back toward normal levels. The revenue decrease from the three months ended March 31, 2012 to the three months ended March 31, 2013 was due to an approximately 8.1 million gallon decrease in ethanol sold. This was partially offset by an increase in the average price per gallon of ethanol by approximately $0.23 per gallon. The combined dried distillers grains with solubles, wet distillers grain with solubles and corn syrup average price increased from approximately $160 to $188 per ton which partially offset a 10,163 decrease in tons produced between the two quarters.   Corn oil revenue was about 2.5% of our total revenue for both the six months ended March 31, 2013 and 2012, respectively. For the six months ending March 31, 2013 compared to the six months ending March 31, 2012, revenues decreased as a result of production being decreased. Ethanol sold decreased about 14,381,000 gallons. Dry Distillers Grains, Wet Distillers Grain, and Corn Syrup sales decreased by about 30,532 tons.
 
 
For the three months ended
 
For the three months ended
 
March 31, 2013
 
March 31, 2012
 
Gallons/Tons Sold
 
% of Revenues
 
Gallons/Tons Average Price
 
Gallons/Tons Sold
 
% of Revenues
 
Gallons/Tons Average Price
Statistical Revenue Information
 
 
 
 
 
 
 
 
 
 
 
Denatured Ethanol
24,653,572

 
72.96
%
 
$
2.34

 
32,742,534

 
76.95
%
 
$
2.11

Dry Distiller's Grains
56,437

 
18.73
%
 
$
262.87

 
79,454

 
17.23
%
 
$
194.89

Wet Distiller's Grains
37,642

 
5.10
%
 
$
107.24

 
28,208

 
2.75
%
 
$
85.72

Syrup
10,253

 
0.97
%
 
$
74.71

 
6,833

 
0.44
%
 
$
58.32

Corn Oil
2,464

 
2.24
%
 
$
720.46

 
3,433

 
2.63
%
 
$
688.18



 
For the six months ended
 
For the six months ended
 
March 31, 2013
 
March 31, 2012
 
Gallons/Tons Sold
 
% of Revenues
 
Gallons/Tons Average Price
 
Gallons/Tons Sold
 
% of Revenues
 
Gallons/Tons Average Price
Statistical Revenue Information
 
 
 
 
 
 
 
 
 
 
 
Denatured Ethanol
49,234,021

 
73.44
%
 
$
2.29

 
63,615,819

 
78.76
%
 
$
2.29

Dry Distiller's Grains
106,479

 
18.13
%
 
$
261.37

 
149,830

 
15.88
%
 
$
196.18

Wet Distiller's Grains
67,382

 
5.05
%
 
$
115.08

 
51,540

 
2.37
%
 
$
85.16

Syrup
15,465

 
0.80
%
 
$
79.32

 
18,488

 
0.46
%
 
$
45.70

Corn Oil
5,413

 
2.58
%
 
$
732.01

 
6,238

 
2.53
%
 
$
749.38



Cost of Goods Sold
 
Our cost of goods sold as a percentage of our revenues was 99% and 101% for the three months ended March 31, 2013 and 2012, respectively.  For the six months ended March 31, 2013 and 2012, our cost of goods sold as a percent of revenue was about 103% and 93%, respectively. Our two primary costs of producing ethanol and distillers grains are corn and energy, with natural gas as our primary energy source and to a lesser extent, steam during the three months ended March 31, 2013.  Unlike most ethanol producers in the United States which use natural gas as their primary energy source, our primary energy source has traditionally been steam but we can change between steam and natural gas.  Given the lower prices for natural gas,  we operated largely on natural gas during the three months ended March 31, 2013 and during Fiscal 2012. However, under the Fifth Amendment to our Steam Service Contract dated March 13, 2013, we amended our existing steam contract to commit to using steam for substantially all of our needs when it is available, at a discount to the price of natural gas.  If the natural gas price is higher than the contracted steam price, which is based on an energy index which includes coal costs and other factors, we will pay the contacted steam price. 

20



Cost of goods sold also includes net (gains) or losses from derivatives and hedging relating to corn.  We ground 8.9 and 17.5 million bushels of corn at an average price of $7.34 and $7.38 per bushel during the three and six months ended March 31, 2013, respectively. That compares to 11.4 and 22.4 million bushels at an average corn price of $6.46 and $6.26 per bushel during the three and six months ended March 31, 2012, respectively.  Our average steam and natural gas energy cost was $4.22 and $4.27 per MMBTU for the three and six months ended March 31, 2013, respectively, compared to a $3.86 and $4.24 per MMBTU for the three and six months ended March 31, 2012, respectively
Realized and unrealized loses related to our derivatives and hedging related to corn resulted in an increase of approximately$1,485,000 and $2,779,000 in our cost of goods sold for the three and six months ended March 31, 2013, respectively, compared to a decrease of $346,000 and $3,737,000 in our cost of goods sold for the three and six months ended March 31, 2012, respectively.  We recognize the gains or losses that result from the changes in the value of our derivative instruments related to corn in cost of goods sold as the changes occur.  As corn prices fluctuate, the value of our derivative instruments are impacted, which affects our financial performance.  We anticipate continued volatility in our cost of goods sold due to the timing of the changes in value of the derivative instruments relative to the cost and use of the commodity being hedged. 
Variable production expenses showed a decrease when comparing the three and six months ended March 31, 2013 and 2012 due to the production decrease.  Fixed production expenses showed a slight decrease also when comparing the three and six months ended March 31, 2013 and 2012.
General & Administrative Expense
 
Our general and administrative expenses as a percentage of revenues were 1.2% and 1.1% for both of the three months ended March 31, 2013 and 2012 and was 1.3% for both the six month ended March 31, 2013 and 2012.  Operating expenses include salaries and benefits of administrative employees, professional fees and other general administrative costs.  Our general and administrative expenses for the six months ended March 31, 2013 were approximately $1,988,000, compared to approximately $2,330,000 for the six month ended March 31, 2012.  The decrease in general and administrative expenses from the six months ended March 31, 2012 to March 31, 2013 is due to a decrease in insurance and a reduction in administrative payroll.  We expect our operating expenses to remain flat to slightly decreasing during the remainder of Fiscal 2013.
Other (Expense)
 
Our other expenses, primarily interest, for the three and six months ended both March 31, 2013 were approximately 3.0% and 3.1% of revenue compared to 2.7% and 2.6% of revenue for the three and six months ended March 31, 2012, respectively.   This increase in the six month comparison was a result of revenues decreasing. Expenses actually decreased slightly from about $4,863,000 for the six months ended March 31, 2012 to $4,738,000 for the six months ended March 31, 2013.  

Selected Financial Data.
Adjusted EBITDA is defined as net income (loss) plus interest expense net of interest income, plus income tax expense (benefit) and plus depreciation and amortization, or EBITDA, as adjusted for unrealized hedging losses (gains).  Adjusted EBITDA is not required by or presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”), and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP, or as an alternative to cash flow from operating activities or as a measure of our liquidity.
    
We present Adjusted EBITDA because we consider it to be an important supplemental measure of our operating performance and it is considered by our management and Board of Directors as an important operating metric in their assessment of our performance.
We believe Adjusted EBITDA allows us to better compare our current operating results with corresponding historical periods and with the operational performance of other companies in our industry because it does not give effect to potential differences caused by variations in capital structures (affecting relative interest expense, including the impact of write-offs of deferred financing costs when companies refinance their indebtedness), the amortization of intangibles (affecting relative amortization expense), unrealized hedging losses (gains) and other items that are unrelated to underlying operating performance.  We also present Adjusted EBITDA because we believe it is frequently used by securities analysts and investors as a measure of performance.   There are a number of material limitations to the use of Adjusted EBITDA as an analytical tool, including the following:


21



Adjusted EBITDA does not reflect our interest expense or the cash requirements to pay our interest.  Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate profits and cash flows.  Therefore, any measure that excludes interest expense may have material limitations.
Although depreciation and amortization are non-cash expenses in the period recorded, the assets being depreciated and amortized may have to be replaced in the future, and Adjusted EBITDA does not reflect the cash requirements for such replacement.   Because we use capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits.  Therefore, any measure that excludes depreciation and amortization expense may have material limitations.
 
We compensate for these limitations by relying primarily on our GAAP financial measures and by using Adjusted EBITDA only as supplemental information.  We believe that consideration of Adjusted EBITDA, together with a careful review of our GAAP financial measures, is the most informed method of analyzing our operations.  Because Adjusted EBITDA is not a measurement determined in accordance with GAAP and is susceptible to varying calculations, Adjusted EBITDA, as presented, may not be comparable to other similarly titled measures of other companies.  The following table provides a reconciliation of Adjusted EBITDA to net income (loss):
Adjusted EBITDA to net income (loss) for the three months ended March 31, 2013 and March 31, 2012 
 
 
For the three months
 
For the three months
 
March 31, 2013
 
March 31, 2012
 
Amounts
 
Amounts
 
in 000's
 
in 000's
EBITDA
 
 
 
Net (Loss)
(2,424
)
 
(3,987
)
Interest Expense, interest income, and other income
2,229

 
2,280

Depreciation & Amortization
2,984

 
2,975

EBITDA
2,789

 
1,268

 
 
 
 
Unrealized Hedging (gain) loss
1,383

 
(301
)
 
 
 
 
Adjusted EBITDA
4,172

 
967

 
 
 
 
Adjusted EBITDA per unit
317.52

 
73.60

Adjusted EBITDA to net income (loss) for the six months ended March 31, 2013 and March 31, 2012 
 
 
For the six months
 
For the six months
 
March 31, 2013
 
March 31, 2012
 
Amounts
 
Amounts
 
in 000's
 
in 000's
EBITDA
 
 
 
Net Income (Loss)
(11,107
)
 
5,009

Interest Expense, interest income, and other income
4,468

 
4,637

Depreciation & Amortization
5,968

 
5,933

EBITDA (Loss)
(671
)
 
15,579

 
 
 
 
Unrealized Hedging (gain) loss
3,450

 
(4,704
)
 
 
 
 
Adjusted EBITDA (Loss)
2,779

 
10,875

 
 
 
 
Adjusted EBITDA  (Loss) per unit
211.51

 
827.69


22





23



Liquidity and Capital Resources
We are party to Credit Agreement, as amended with AgStar Financial Services, PCA (“AgStar”) and a group of lenders (together with AgStar) in the original maximum principal amount of $126,000,000 senior secured debt, consisting of a $101,000,000 term loan, a $10,000,000 term revolving loan and a $13,214,300 working capital revolving line of credit. The parties amended the Credit Agreement on March 29, 2013 and the amendment reduced the available credit under the revolving working capital term facility from $15,000,000 to $13,214,000. As of March 29, 2013, we had an outstanding balance of $83,979,706 under our Credit Agreement.  Under the terms of our Credit Agreement, we must pay an annual amount equal to 65% of our Excess Cash Flow (as defined in the Credit Agreement), up to a total of $6,000,000 per year, and $24,000,000 over the term of the Credit Agreement.  Any borrowings are subject to borrowing base restrictions as well as certain prepayment penalties. Under our Credit Agreement, the borrowing base is defined as, “at any time, the lesser of: (i) $13,214,300, or (ii) the sum of:  (A) seventy-five percent (75%) of our eligible accounts receivable, plus (B) seventy-five percent (75%) of our eligible inventory.  In addition to compliance with the borrowing base, we are subject to various affirmative and negative covenants under the Credit Agreement.  We were in compliance with all financial covenants under our Credit Agreement as of March 31, 2013. However, in the event that the market continues to experience significant price volatility and negative crush margins near the current levels or in excess of current levels, it may be difficult to comply with our financial covenants. The banks’ response to non-compliance is unknown at this point. We may be required to explore alternative methods to meet our short-term liquidity needs including temporary shutdowns of operations, temporary reductions in our production levels, or negotiating short-term concessions from our lenders.   
Under our $13,214,000 revolving line of credit with the Lenders (the “Revolving LOC”), we had $10,000,000 outstanding as of March 31, 2013 and $5,875,000 outstanding as of September 30, 2012 under the $15,000,000 revolving line of credit, with an additional $3,214,000 and $9,125,000 available at March 31, 2013 and September 30, 2012, respectively.
We entered into a revolving note with Bunge N.A. Holdings, Inc. (“Holdings”) dated August 26, 2009 (which Holdings assigned to Bunge effective September 28, 2012 (the “Bunge Revolving Note”), providing for the extension of a maximum of $10,000,000 in revolving credit.  Bunge has a commitment, subject to certain conditions, to advance up to $3,750,000 at our request under the Bunge Revolving Note; amounts in excess of $3,750,000 may be advanced by Bunge in its discretion.  Interest accrues at the rate of 7.5% over six-month LIBOR.  While repayment of the Bunge Revolving Note is subordinated to the Credit Agreement, we may make payments on the Bunge Revolving Note so long as we are in compliance with our borrowing base covenant and there is not a payment default under the Credit Agreement. As of March 31, 2013 and September 30, 2012, the balance outstanding was $10,000,000 and $3,750,000, respectively, under the Bunge Revolving Note.   Under the Bunge Revolving Note, we made certain standard representations and warranties.
As a result of our Credit Agreement, Revolving LOC, convertible debt and the Bunge Revolving Note, we have a significant amount of debt, and our existing debt financing agreements contain, and our future debt financing agreements may contain, restrictive covenants that limit distributions and impose restrictions on the operation of our business.   The use of debt financing makes it more difficult for us to operate because we must make principal and interest payments on the indebtedness and abide by covenants contained in our debt financing agreements. The level of our debt has important implications on our liquidity and capital resources, including, among other things: (i) limiting our ability to obtain additional debt or equity financing; (ii) making us vulnerable to increases in prevailing interest rates; (iii) placing us at a competitive disadvantage because we may be substantially more leveraged than some of our competitors; (iv) subjecting all or substantially all of our assets to liens, which means that there may be no assets left for members in the event of a liquidation; and (v) limiting our ability to make business and operational decisions regarding our business, including, among other things, limiting our ability to pay dividends to our unit holders, make capital improvements, sell or purchase assets or engage in transactions we deem to be appropriate and in our best interest.
While the prices of our primary input (corn) and our principal products (ethanol and distillers grains) are expected to continue to be volatile in the second quarter of Fiscal 2013, given the relative prices of these commodities and the operation of our risk management program in the quarter, we believe operating margins will improve from the first quarter but still be weak in the second quarter of Fiscal 2013.  We expect that in the last two quarters of Fiscal 2013 our margins will improve due to an increase in yield per gallon, and improved crush margins.

Primary Working Capital Needs
Cash provided by operations for the six months ended March 31, 2013 and March 31, 2012, respectively, was $405,000 and $13,060,000, respectively.  This change is a result of increased corn and ethanol prices and decreased production.  For the six months ended March 31, 2013 and March 31, 2012, net cash provided by (used in) investing activities was  ($99,000) and  ($307,000), respectively, primarily for fixed asset additions.  For the six months ended March 31, 2013 and March 31, 2012, net cash provided by (used in) financing activities was $5,339,000 and ($13,687,000), respectively.  During the six months

24



ended March 31, 2013, pursuant to contractual terms, we made principal payments on our term debt in the amount of $5,011,933 which was offset by additional borrowing of our lines of credit.
During the third quarter of Fiscal 2013, we estimate that we will require approximately $72,300,000 for our primary input of corn and $3,009,000 for our energy sources of steam and natural gas.  We currently have approximately $3,214,000 available under our current revolving lines of credit to hedge commodity price fluctuations.  We cannot estimate the availability of funds for hedging in the future.
We believe that our existing sources of liquidity, including cash on hand, available revolving credit and cash provided by operating activities, will satisfy our projected liquidity requirements, which primarily consists of working capital requirements, for the next twelve months.   However, in the event that the market continues to experience significant price volatility and negative crush margins at the current levels or in excess of current levels, we may be required to explore alternative methods to meet our short-term liquidity needs including temporary shutdowns of operations, temporary reductions in our production levels, or negotiating short-term concessions from our lenders.   
 
Trends and Uncertainties Impacting Ethanol and Our Future Operations
 
Commodity Price Risk 

Our operations are highly dependent on commodity prices, especially prices for corn, ethanol and distillers grains. As a result of price volatility for these commodities, our operating results may fluctuate substantially. The price and availability of corn are subject to significant fluctuations depending upon a number of factors that affect commodity prices in general, including crop conditions, weather, governmental programs and foreign purchases. We may experience increasing costs for corn and natural gas and decreasing prices for ethanol and distillers grains which could significantly impact our operating results. Because the market price of ethanol is not directly related to corn prices, ethanol producers are generally not able to compensate for increases in the cost of corn feedstock through adjustments in prices charged for ethanol.  We continue to monitor corn and ethanol prices and their effect on our longer-term profitability.
In the past, ethanol prices have tended to track with the wholesale price of gasoline. Ethanol prices can vary from state to state at any given time.  As of April 22, 2013 according to the Chicago Board of Trade (“CBOT”), the average U.S. ethanol price was $2.46 per gallon.  For the same time period, the average U.S. wholesale gasoline price was $2.76 per gallon or approximately $0.30 per gallon above ethanol prices.  
According to the EIA, as an industry, ethanol producers started to increase their average weekly production levels from 807 thousand barrels per day as of December 28, 2012 to 859 thousand barrels per day as of March 31, 2013 representing a 6% increase. Despite this increase, there is no guarantee that ethanol producers will continue to increase production, in fact, ethanol producers may actually reduce production until ethanol supply and demand returns to normal market levels.  Reduced production resulting from temporary plant shutdowns and decreased production levels may cause ethanol prices to increase and provide better margins in Fiscal 2013.
The price of corn was volatile during calendar year 2012; reaching all-time highs in excess of $8.00 per bushel. Corn prices have slightly receded in response to the moisture conditions in the Midwestern region of the U.S. It is also estimated that a record number of acres will be planted with corn this year. Both conditions are contributing to the decreases in the price of corn. As of April 22, 2013, the Chicago Mercantile Exchange (“CME”) near-month corn price for May, 2013 was $6.46; for July 2013 it was at $6.23 and for September 2013 it was $5.55. However, the price of corn may increase as a result of market factors, Increasing corn prices will negatively affect our costs of production.
However, higher corn prices may, depending on the prices of alternative crops, encourage farmers to plant more acres of corn in the coming years and possibly divert land in the Conservation Reserve Program to corn production. We believe an increase in land devoted to corn production could reduce the price of corn to some extent in the future.
As of April 22, 2013, the USDA has held steady on its forecast of the amount of corn to be used for ethanol production during the current marketing year (2012/2013) to a total of 4.5 billion bushels. The forecast is approximately 500 million bushels less than used last year (2011/2012).  In the April 22, 2013 update, the USDA increased the projection of U.S. corn exports for the current marketing year by .74 billion bushels from estimates three months ago.
We enter into various derivative contracts with the primary objective of managing our exposure to adverse price movements in the commodities used for, and produced in, our business operations and, to the extent we have working capital available, we engage in hedging transactions which involve risks that could harm our business. We measure and review our net commodity

25



positions on a daily basis.  Our daily net agricultural commodity position consists of inventory, forward purchase and sale contracts, over-the-counter and exchange traded derivative instruments.  The effectiveness of our hedging strategies is dependent upon the cost of commodities and our ability to sell sufficient products to use all of the commodities for which we have futures contracts.  Although we actively manage our risk and adjust hedging strategies as appropriate, there is no assurance that our hedging activities will successfully reduce the risk caused by market volatility which may leave us vulnerable to high commodity prices. Alternatively, we may choose not to engage in hedging transactions in the future. As a result, our future results of operations and financial conditions may also be adversely affected during periods in which corn prices changes.
In addition, as described above, hedging transactions expose us to the risk of counterparty non-performance where the counterparty to the hedging contract defaults on its contract or, in the case of over-the-counter or exchange-traded contracts, where there is a change in the expected differential between the price of the commodity underlying the hedging agreement and the actual prices paid or received by us for the physical commodity bought or sold.  We have, from time to time, experienced instances of counterparty non-performance.
Although we believe our hedge positions accomplish an economic hedge against our future purchases and sales, management has chosen not to use hedge accounting, which would, if qualified to do so, if qualified to do so, match the gain or loss on our hedge positions to the specific commodity purchase being hedged.  We are using fair value accounting for our hedge positions, which means as the current market price of our hedge positions changes, the realized or unrealized gains and losses are immediately recognized in the current period (commonly referred to as the “mark to market” method). The immediate recognition of hedging gains and losses under fair value accounting can cause net income to be volatile from quarter to quarter due to the timing of the change in value of the derivative instruments relative to the cost and use of the commodity being hedged.  As corn prices move in reaction to market trends and information, our income statement will be affected depending on the impact such market movements have on the value of our derivative instruments.  Depending on market movements, crop prospects and weather, our hedging strategies may cause immediate adverse effects, but are expected to produce long-term positive impact.
In the event we do not have sufficient working capital to enter into hedging strategies to manage our commodities price risk, we may be forced to purchase our corn and market our ethanol at spot prices and as a result, we could be further exposed to market volatility and risk.
Risks Related to Government Mandates and Subsidies
The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline. Federal and state governments have enacted numerous policies, incentives and subsidies to encourage the usage of domestically-produced alternative fuel solutions. The federal Renewable Fuels Standard II ("RFS2"), as part of the Energy Independence and Security Act, has been, and will likely continue to be, a driving factor in the growth of ethanol usage. In October 2011, the U.S. House of Representatives introduced the RFS Flexibility Act to reduce or eliminate the volumes of renewable fuel use required by RFS2 based upon corn stocks-to-use ratios.  The U.S. House of Representatives then introduced the Domestic Alternative Fuels Act of 2012 in January 2012 to modify RFS2 to include ethanol and other fuels produced from fossil fuels like coal and natural gas.   The 2013 RFS mandate is for 16.55 billion gallons of renewable fuels of which corn based ethanol is expected to satisfy approximately 13.8 billion gallons. As a result of the recent drought conditions, we may see additional legislation aimed at reducing or eliminating renewable fuel use required by RFS2. 
The Environmental Protection Agency (the “EPA”) has issued proposed allocations of classes of renewable fuels, many of which are not yet final. Under the provisions of the Energy Independence and Security Act, the EPA has the authority to waive the mandated RFS2 requirements in whole or in part. To grant the waiver, the EPA administrator must determine, in consultation with the Secretaries of Agriculture and Energy, that one of two conditions has been met: (1) there is inadequate domestic renewable fuel supply or (2) implementation of the requirement would severely harm the economy or environment of a state, a region, or the U.S. We believe that any reversal or waiver in federal policy on the RFS2 could have a significant impact on the ethanol industry.
In April, 2012, the EPA approved the first applications for ethanol to be used to make E15. As E15 gains acceptance in the marketplace, we anticipate the demand for ethanol to increase, however such increase is not anticipated in the immediate near future. Future demand will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline versus ethanol and the RFS2.  Any significant increase in production capacity beyond the RFS2 level might have an adverse impact on ethanol prices.  Additionally, the RFS2 mandate with respect to ethanol derived from grain could be reduced or waived entirely.  A reduction or waiver of the RFS2 mandate could adversely affect the prices of ethanol and our future performance.


26



In August 2012, governors from eight states filed formal requests with the EPA to waive the RFS2 requirements based on drought conditions. On November 16, 2012, the EPA denied the waiver request.  Although the EPA denied this waiver request, we cannot guarantee that if future waiver requests are filed that the EPA will deny such requests.  However, our operations could be adversely impacted if such a waiver is ever granted.
 
In addition, many in the ethanol industry are concerned that certain provisions of RFS2 as adopted may disproportionately benefit ethanol produced from sugarcane. This could make sugarcane based ethanol, which is primarily produced in Brazil, more competitive in the United States ethanol market. If this were to occur, it could reduce demand for the ethanol that we produce.
 
Many in the ethanol industry believe that it will be difficult to meet the RFS2 requirement in future years without an increase in the percentage of ethanol that can be blended with gasoline for use in standard (non-flex fuel) vehicles. Most ethanol that is used in the United States is sold in a blend called E10. E10 is a blend of 10% ethanol and 90% gasoline. E10 is approved for use in all standard vehicles. Estimates indicate that gasoline demand in the United States is approximately 134 billion gallons per year. Assuming that all gasoline in the United States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand for ethanol is 13.4 billion gallons per year. This is commonly referred to as the “blend wall,” which represents a theoretical limit where more ethanol cannot be blended into the national gasoline pool. This is a theoretical limit because it is believed that it would not be possible to blend ethanol into every gallon of gasoline that is being used in the United States and it discounts the possibility of additional ethanol used in higher percentage blends such as E85 used in flex fuel vehicles. The RFS2 requires that 36 billion gallons of renewable fuels must be used each year by 2022, which equates to approximately 27% renewable fuels used per gallon of gasoline sold. In order to meet the RFS2 mandate and expand demand for ethanol, management believes higher percentage blends of ethanol must be utilized in standard vehicles.
 
The EPA has approved the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2001 and later, representing nearly two-thirds of all vehicles on the road.   The first retail sales of E15 ethanol blends in the U.S. occurred in July 2012. According to the EPA, as of March 19, 2013, 76 fuel manufacturers were registered to sell E15.  Prior to the final approval of E15 for sale, the EPA granted partial waivers for certain motor vehicles, subject to certain conditions.  Sales of E15 may be limited because (i) it is not approved for use in all vehicles, (ii) the EPA requires a label that management believes may discourage consumers from using E15, and (iii) retailers may choose not to sell E15 due to concerns regarding liability. In addition, different gasoline blendstocks may be required at certain times of the year in order to use E15 due to federal regulations related to fuel evaporative emissions. This may prevent E15 from being used during certain times of the year in various states. As a result, E15 may not have an immediate impact on ethanol demand in the United States.
 
On July 1, 2011, Iowa retailers became eligible for a three cent per gallon tax credit for every gallon of E15 sold.   Any reversal of the EPA waivers may nullify the tax credit for Iowa retailers and adversely affect the demand for E15.
 
In the past, the ethanol industry was impacted by the VEETC or blenders’ credit.  The blenders’ credit expired on December 31, 2011 and was not renewed.  VEETC provided a volumetric ethanol excise tax credit to $0.45 per gallon of pure ethanol and $0.38 per gallon for E85, a blended motor fuel containing 85% ethanol and 15% gasoline.  As a result of the expiration of VEETC, we are seeing some negative impact on the price and demand for ethanol in the market due to reduced discretionary blending of ethanol.  Discretionary blending occurs when gasoline blenders use ethanol to reduce the cost of blended gasoline.  However, we do not believe that the expiration of VEETC will have a continued material effect on ethanol demand provided gasoline prices stay high and the RFS is maintained. Recently, there have been proposals in Congress to reduce or eliminate the RFS. Management does not believe that these proposals will be adopted in the near future. However, if the RFS is reduced or eliminated now that the blenders' credit was allowed to expire, the market price and demand for ethanol will likely decrease which could negatively impact our financial performance. 
Ethanol production in the U.S. was also benefited by a $0.54 per gallon tariff imposed on ethanol imported into the United States. On December 31, 2011, this tariff expired. Management believes that in the short-term, since the United States is a net exporter of ethanol, the expiration of the tariff will not have a significant impact on the United States ethanol industry. However, if other countries are able to increase their ethanol production, the expiration of the tariff may result in increased competition from foreign ethanol producers.

Impact of Hedging Transactions on Liquidity
Our operations and cash flows are highly impacted by commodity prices, including prices for corn, ethanol, distillers grains and natural gas. We attempt to reduce the market risk associated with fluctuations in commodity prices through the use of derivative instruments, including forward corn contracts and over-the-counter exchange-traded futures and option contracts. Our liquidity position may be positively or negatively affected by changes in the underlying value of our derivative instruments. When

27



the value of our open derivative positions decrease, we may be required to post margin deposits with our brokers to cover a portion of the decrease or we may require significant liquidity with little advanced notice to meet margin calls. Conversely, when the value of our open derivative positions increase, our brokers may be required to deliver margin deposits to us for a portion of the increase.  We continuously monitor and manage our derivative instruments portfolio and our exposure to margin calls and while we believe we will continue to maintain adequate liquidity to cover such margin calls from operating results and borrowings, we cannot estimate the actual availability of funds from operations or borrowings for hedging transactions in the future.
The effects, positive or negative, on liquidity resulting from our hedging activities tend to be mitigated by offsetting changes in cash prices in our core business. For example, in a period of rising corn prices, gains resulting from long grain derivative positions would generally be offset by higher cash prices paid to farmers and other suppliers in spot markets. These offsetting changes do not always occur, however, in the same amounts or in the same period, with lag times of as much as twelve months.
We expect the annual impact on our results of operations due to a $1.00 per bushel fluctuation in market prices for corn to be approximately $39,300,000, or $0.36 per gallon, assuming our plant operates at 100% name plate capacity (production of 110,000,000 gallons of ethanol annually) assuming no increase in the price of ethanol.  We expect the annual impact to our results of operations due to a $0.50 decrease in ethanol prices will result in approximately a $55,000,000 decrease in revenue.

Off-Balance Sheet Arrangements
We do not have any off balance sheet arrangements.
Item 3.   Quantitative and Qualitative Disclosures about Market Risk
Not applicable.

Item 4.   Controls and Procedures.
The Company’s management, including its President and Chief Executive Officer (our principal executive officer), Brian T. Cahill, along with its Chief Financial Officer (our principal financial officer), Brett L. Frevert, have reviewed and evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amending, the “Exchange Act”), as of March 31, 2013.  The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.   Based upon this review and evaluation, these officers believe that the Company’s disclosure controls and procedures are presently effective in ensuring that material information related to us is recorded, processed, summarized and reported within the time periods required by the forms and rules of the Securities and Exchange Commission (the “SEC”).
The Company’s  management, including the Company’s  principal executive officer and principal financial officer, have reviewed and evaluated any changes in the Company’s internal control over financial reporting that occurred as of March 31, 2013 and there has been no change that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.
The Company’s management assessed the effectiveness of the Company’s internal control over financing reporting as of March 31, 2013.  In making this assessment, the Company’s management used the criteria set forth by the Committee Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.  Based on this assessment, the Company’s management concluded that, as of March 31, 2013, the Company’s integrated controls over financial report were effective.
This annual report does not include an attestation report of the company’s registered public accounting firm pursuant to the exemption under Section 989G of the Dodd-Frank Act of 2010.

PART II – OTHER INFORMATION
 
Item 1.   Legal Proceedings.

28



None
 
Item 1A.   Risk Factors.
There have been no material changes to the risk factors disclosed in Item 1A of our Form 10-K for the fiscal year ended September 30, 2012.  Additional risks and uncertainties, including risks and uncertainties not presently known to us, or that we currently deem immaterial, could also have an adverse effect on our business, financial condition and/or results of operations. 

Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds.
None

Item 3. Defaults Upon Senior Securities.
 
None

Item 4. Mine Safety Disclosures.
 
None

Item 5. Other Information.
 
None

Item 6.   Exhibits

29



10.1*
Fifth Amendment to Steam Service Contract by and between the Company and MidAmerica Energy Company dated March 13, 2013. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on March 19, 2013).
10.2
Fifth Amendment to Amended and Restated Credit Agreement effective March 29, 2013 by and among the Company and AgStar Financial Services, PCA and other commercial, banking or financial institutions identified therein. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 4, 2013).

10.3**
Carbon Dioxide Purchase and Sale Agreement effective April 2, 2013 by and between the Company and EPCO Carbon Dioxide Products, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 11, 2013).
10.4
Non-Exclusive CO2 Facility Site Lease Agreement effective April 2, 2013 by and between the Company and EPCO Carbon Dioxide Products, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on April 11, 2013).
 
 
31.1
Rule 13a-14(a)/15d-14(a) Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by the Principal Executive Officer.
 
 
31.2
Rule 13a-14(a)/15d-14(a) Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by the Principal Financial Officer.
 
 
32.1***
Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Principal Executive Officer.
 
 
32.2***
Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Principal Financial Officer.
 
 
101.XML^
XBRL Instance Document
 
 
101.XSD^
XBRL Taxonomy Schema
 
 
101.CAL^
XBRL Taxonomy Calculation Database
 
 
101.LAB^
XBRL Taxonomy Label Linkbase
 
 
101.PRE^
XBRL Taxonomy Presentation Linkbase
 
 
*
Material has been omitted from this exhibit pursuant to a grant of confidential treatment pursuant to Rule 24b-2 promulgated under the Securities Exchange Act of 1934 and such material has been filed separately with the Securities and Exchange Commission and confidential treatment granted on April 9, 2013.
**
 Material has been omitted from this exhibit pursuant to a grant of confidential treatment pursuant to Rule 24b-2 promulgated under the Securities Exchange Act of 1934 and such material has been filed separately with the Securities and Exchange Commission and confidential treatment granted on April 22, 2013.
***
This certification is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference.
^
Furnished, not filed.

30



SIGNATURES
 
In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
SOUTHWEST IOWA RENEWABLE ENERGY, LLC
 
 
 
Date:
May 15, 2013
/s/ Brian T. Cahill
 
 
Brian T. Cahill, President and Chief Executive Officer
 
 
 
Date:
May 15, 2013
/s/ Brett L. Frevert
 
 
Brett L. Frevert, CFO and Principal Financial Officer

31