PART I
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K 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:
| Ÿ | Changes in the availability and price of corn, natural gas, and steam; |
| Ÿ | Our inability to comply with our credit agreements required to continue our operations; |
| Ÿ | Negative impacts that our hedging activities may have on our operations; |
| Ÿ | Decreases in the market prices of ethanol and distillers grains; |
| Ÿ | Ethanol supply exceeding demand; and corresponding ethanol price reductions; |
| Ÿ | Changes in the environmental regulations that apply to our plant operations; |
| Ÿ | Changes in plant production capacity or technical difficulties in operating the plant; |
| Ÿ | Changes in general economic conditions or the occurrence of certain events causing an economic impact in the agriculture, oil or automobile industries; |
| Ÿ | Changes in federal and/or state laws (including the elimination of any federal and/or state ethanol tax incentives); |
| Ÿ | Changes and advances in ethanol production technology; |
| Ÿ | Additional ethanol plants built in close proximity to our ethanol facility in southwest Iowa; |
| Ÿ | Competition from alternative fuel additives; |
| Ÿ | Changes in interest rates and lending conditions of our loan covenants; |
| Ÿ | Our ability to retain key employees and maintain labor relations; and |
| Ÿ | Volatile commodity and financial markets. |
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. 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.” Other risks and uncertainties are disclosed in our prior Securities and Exchange Commission (“SEC”) 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 Company or on its behalf. We undertake no obligation to revise or update any forward-looking statements. The forward-looking statements contained in this Form 10-K are included in the safe harbor protection provided by Section 27A of the Securities Act of 1933, as amended (the “1933 Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
AVAILABLE INFORMATION
Information about us is also available at our website at www.sireethanol.com , under “SEC Compliance,” which includes links to reports we have filed with the SEC. The contents of our website are not incorporated by reference into this Annual Report on Form 10-K.
Item 1. Business.
The Company is an Iowa limited liability company located in Council Bluffs, Iowa, and was 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 syrup, and corn oil in the continental United States. We sell our dried distillers grains with solubles in the continental United States, Mexico and the Pacific Rim. During the first quarter of our fiscal year ended September 30, 2011 (“Fiscal 2011”), we implemented a corn oil extraction system, the corn oil from which accounted for approximately 3% of our revenue stream during our fiscal year ended September 30, 2012 (“Fiscal 2012”).
Our production facility (the “Facility”) is located in Pottawattamie County in southwestern Iowa. It is near two major interstate highways, within a mile of the Missouri River and has access to five major rail carriers. This location is in close proximity to raw materials and product market access. The Facility receives corn and chemical deliveries primarily by truck but is able to utilize rail delivery if necessary. Finished products are shipped by rail and truck. The site has access to water from ground wells and from the Missouri River. Additionally, in close proximity to the Facility’s primary energy source (steam), there are two natural gas providers available, both with infrastructure immediately accessible to the Facility.
The most severe and extensive drought in over 25 years has impacted the agricultural sector, especially corn prices, and the ethanol industry. November 2012 corn estimates of 10.7 billion bushels declined 27.5% from the 14.8 billion bushels estimated in May 2012. Corn yields, estimated to be 122.3 bushels per acre, were the lowest since 1995. Overall corn supplies fell 13% from 2011/2012 to 11.8 billion bushels. Corn prices rose to a range of $6.95 - $8.25 per bushel for the marketing year 2012, up from the $6.22 average for 2011.
Financial Information
Please refer to “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about our revenue, profit and loss measurements and total assets and liabilities, and “Item 8 – Financial Statements and Supplementary Data” for our financial statements and supplementary data.
Rail Access
We own a six mile loop railroad track for rail service to our Facility. Our track comes off the Council Bluffs Energy Center line where interstate I-29 crosses and proceeds south along the east side of Pony Creek. The track terminates in a loop-track south of the Facility, which accommodates 100 car trains. We entered into an Industrial Track Agreement with CBEC Railway, Inc. (the “Track Agreement “), which governs our use of the loop railroad and requires, among other things, that we maintain the loop track.
We are a party to an Amended and Restated Railcar Lease Agreement (“Railcar Agreement”) with Bunge North America, Inc. (“Bunge”), a significant equity holder, for the sublease of 325 ethanol cars and 300 hopper cars which are used for the delivery and marketing of our ethanol and distillers grains. Under the Railcar Agreement, we sublease 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 subleases. Pursuant to the terms of a side letter to the Railcar Agreement, we may be able to sublease cars back to Bunge from time to time when the cars are not in use in our operations
Employees
We had 58 employees, 57 of which were full time, as of September 30, 2012. We are not subject to any collective bargaining agreements and we have not experienced any work stoppages. Our management considers our employee relationships to be favorable.
Principal Products
The principal products we produce are ethanol and distillers grains, and corn oil.
Ethanol
Our primary product is ethanol. Ethanol is ethyl alcohol, a fuel component made primarily from corn and various other grains, which can be used as: (i) an octane enhancer in fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based gasoline substitute. More than 99% of all ethanol produced in the United States is used in its primary form for blending with unleaded gasoline and other fuel products. The principal purchasers of ethanol are generally wholesale gasoline marketers or blenders. Ethanol is shipped by truck in the local markets, and by rail in the national market.
We produced 122.0 million and 115.7 million gallons of ethanol for the years ended September 30, 2012 and 2011, respectively, and approximately 76% and 81% of our revenue was derived from the sale of ethanol in Fiscal 2012 and 2011, respectively.
Distillers Grain
The principal co-product of the ethanol production process is distillers grains, a high protein, high-energy animal feed supplement primarily marketed to the beef and dairy industries. Distillers grains contain by-pass protein that is superior to other protein supplements such as cottonseed meal and soybean meal. By-pass proteins are more digestible to the animal, thus generating greater lactation in milk cows and greater weight gain in beef cattle. We produce two forms of distillers grains: wet distillers grains with solubles (“WDGS”) and dried distillers grains with solubles (“DDGS”). WDGS are processed corn mash that has been dried to approximately 50% to 65% moisture. WDGS have a shelf life of approximately seven days and are often sold to nearby markets. DDGS are processed corn mash that has been dried to approximately 10% to 12% moisture. It has a longer shelf life and may be sold and shipped to any market.
We sold 293,806 and 305,929 tons of DDGS in Fiscal 2012 and 2011, respectively. Approximately 21% and 17% of our revenue was derived from the sale of DDGS, WDGS, and corn syrup in Fiscal 2012 and 2011, respectively.
Corn Oil
During Fiscal 2011 we installed an ICM corn oil extraction system and began selling corn oil. This system separates corn oil from the post-fermentation syrup stream as it leaves the evaporators of the ethanol plant. The corn oil is then routed to storage tanks, and the remaining concentrated syrup is routed to the plant’s syrup tank. Corn oil can be marketed as either a feed additive or a biodiesel feedstock. We sold 13,382 and 5,858 tons of corn oil in Fiscal 2012 and 2011, respectively, representing approximately 3% and 2% of our revenue, respectively.
Principal Product Markets
As described below in “Distribution Methods,” we market and distribute all of our ethanol and distillers grains through a professional third party marketer. Our ethanol and distillers grains marketer makes all decisions with regard to where our products are marketed. Our ethanol and distillers grains are primarily sold in the domestic market; however, as United States production of ethanol and distillers grains continue to expand, we anticipate increased international sales of our products. Currently, approximately 25% of our distillers grains are exported outside of the continental United States. As distillers grains become more accepted as an animal feed substitute throughout the world, distillers grains exporting may increase. However, management anticipates that demand for distillers grains in the Asian market may show decreased demand in the future due to the current high level of prices.
Distribution Methods
In 2009, Bunge became the exclusive purchaser of our ethanol pursuant to an Ethanol Purchase Agreement dated December 15, 2008 (the “Prior Ethanol Agreement”). Bunge markets our ethanol in national, regional and local markets. Prior to the expiration of the Prior Ethanol Agreement, the company and Bunge agreed to new terms effective on January 1, 2012 (the “Ethanol Agreement”). The Ethanol Agreement now expires on August 31, 2014, and then 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. Under the Ethanol Agreement, we sell to Bunge all of the ethanol produced at the Facility, and Bunge purchases the same, up to the Facility’s nameplate capacity. We pay Bunge a per-gallon fee for ethanol bought and sold by Bunge under the Ethanol Agreement subject to a minimum annual fee of $750,000 and adjustments according to specified indexes after three years.
We entered into a Distillers Grain Purchase Agreement, as amended (“DG Agreement”) with Bunge, under which Bunge is obligated to purchase from us and we are obligated to sell to Bunge all distillers grains produced at our Facility. If we find another purchaser for distillers grains offering a better price for the same grade, quality, quantity, and delivery period, we can ask Bunge to either market directly to the other purchaser or market to another purchaser on the same terms and pricing.
The initial term of the DG Agreement runs until February 1, 2019, and will automatically renew 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 us 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 SIRE. 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.
Pursuant to a Corn Oil Agency Agreement (the “Corn Oil Agreement”), effective as of November 12, 2010, between SIRE and Bunge, we exclusively use Bunge as our agent to market corn oil produced at the Facility. For its efforts in marketing our corn oil, we pay Bunge a marketing fee based on the amount of corn oil sold. Beginning on November 12, 2013, the marketing fee will be adjusted based on the change in a specified formula.
Raw Materials
Corn Requirements
Ethanol can be produced from a number of different types of grains and waste products. However, approximately 90% of ethanol in the United States today is produced from corn. The cost of corn is affected primarily by supply and demand factors such as crop production, carryout, exports, government policies and programs, risk management and weather. With the volatility of the commodity markets, especially during the last nine months of Fiscal 2012, we cannot predict the future price of corn.
Our Facility needs approximately 39.3 million bushels of corn per year, or approximately 108,000 bushels per day, as the feedstock for its dry milling process. During Fiscal 2012 and 2011, we purchased 43.67 and 40.11 million bushels of corn, respectively, which was obtained primarily from local markets. To assist in our securing the necessary quantities of grain for our plant, we entered into a Grain Feedstock Supply Agreement (the “Supply Agreement”) with Agri-Bunge, LLC, an affiliate of Bunge, which was subsequently assigned to Bunge. Under the Supply Agreement, Bunge provides us with all of the corn we need to operate our ethanol plant, and we have 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. We pay Bunge a per-bushel fee for corn procured by Bunge for us 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 ten years, subject to earlier termination upon specified events.
Energy Requirements
The production of ethanol is a very energy intensive process which uses significant amounts of electricity and steam or natural gas as a heat source. Presently, about 26,250 BTUs of energy are required to produce a gallon of ethanol when we dry 100% of our distillers grains. It is our goal to operate the plant as efficiently as possible, reducing the amount of energy consumed per gallon of ethanol produced. Additionally, water supply and quality are important considerations.
Steam
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 depending on energy costs. Given the lower prices for natural gas, the Facility operated largely on natural gas in Fiscal 2012. We believe our ability to utilize steam makes us more competitive, as under certain energy market conditions our energy costs will be lower than natural gas fired plants. We have entered into an Executed Steam Service Contract (“Steam Contract”) with MidAmerican Energy Company (“MidAm”), under which MidAm provides us the steam required by us, up to 475,000 pounds per hour. The Steam Contract remains in effect until February 1, 2019. During Fiscal 2012 and 2011, we purchased approximately 1,179,102 and 2,340,184 MMBTUs of steam, respectively. The lower volumes purchased in Fiscal 2012 reflects our increased utilization of natural gas given the lower cost of natural gas during the period.
Natural Gas
Although steam is considered our primary energy source, natural gas accounted for around 63% of our energy usage in Fiscal 2012. We have installed two natural gas boilers for use when our steam service is temporarily unavailable or prices favor natural gas instead of steam. Natural gas is also needed for incidental purposes. The gas prices trended lower in Fiscal 2012 as a result of the drop in crude oil prices and based on anticipated increases in supply relative to demand. We do not expect natural gas prices to remain steady in the near future and anticipate the prices to trend higher into the winter months of 2012-2013 as seasonal demand for natural gas increases due to heating needs in the colder weather. We have entered into a natural gas supply agreement with Encore for our long term natural gas needs. During Fiscal 2012 and 2011, we purchased 2,023,892 and 679,760 MMBTUs of natural gas, respectively.
Electricity
Our Facility requires a large continuous supply of electrical energy. We have purchased 74,977 and 70,608 megawatts of electricity in Fiscal 2012 and 2011, respectively, from MidAm under an Electric Service Contract (“Electric Contract”). We agreed to pay MidAm (i) a service charge of $200 per meter, (ii) a demand charge of $3.38 in the summer and $2.89 in the winter (iii) a reactive demand charge of $0.49/kVAR of reactive demand in excess of 50% of billing demand, (iv) an energy charge ranging from $0.03647
to $0.01837 per kilowatt hour, depending on the amount of usage and season, (v) tax adjustments, (vi) AEP and energy efficiency cost recovery adjustments, and (vii) a CNS capital additions tracker. These rates only apply to the primary voltage electric service provided under the Electric Contract. The electric service continued at these prices until the Electric Contract expired on June 30, 2012 and subsequently we elected to be charged under one of MidAm’s electric tariffs.
Water
We require a significant supply of water. Much of the water used in an ethanol plant is recycled back into the process. There are, however, certain areas of production where fresh water is needed. Those areas include boiler makeup water and cooling tower water. Boiler makeup water is treated on-site to minimize all elements that will harm the boiler and recycled water cannot be used for this process. Cooling tower water is deemed non-contact water (it does not come in contact with the mash) and, therefore, can be regenerated back into the cooling tower process. The makeup water requirements for the cooling tower are primarily a result of evaporation. Much of the water is recycled back into the process, which minimizes the discharge. Our Facility’s fresh water requirements are approximately 1,500,000 gallons per day. Our water requirements are supplied through three ground wells, which are permitted to produce up to 2,000,000 gallons of water per day, and we can access water from the Missouri River.
Patents, Trademarks, Licenses, Franchises and Concessions
SIRE TM, our logos, trade names and service marks used in this report are our property. We were granted a perpetual license by ICM, Inc. (“ICM”) to use certain ethanol production technology necessary to operate our Facility. There is no fee or definitive term for this license.
Risk Management and Hedging Transactions
The profitability of our operations is highly dependent on the impact of market fluctuations associated with commodity prices. We use various derivative instruments as part of an overall strategy to manage market risk and to reduce the risk that our ethanol production will become unprofitable when market prices among our principal commodities do not correlate. In order to mitigate our commodity price risks, we enter into hedging transactions, including forward corn, ethanol, and distillers grain contracts, in an attempt to partially offset the effects of corn price volatility. We also enter into over-the-counter and exchange-traded futures and option contracts for corn, ethanol and distillers grains, designed to limit our exposure to increases in the price of corn and manage ethanol price fluctuations. Although we believe that our hedging strategies can reduce the risk of commodity price fluctuations, the financial statement impact of these activities depends upon, among other things, the prices involved and our ability to physically receive or deliver the commodities involved. Our hedging activities 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 and ethanol 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.
Hedging arrangements expose us to the risk of financial loss in situations where the counterparty to the hedging contract defaults or, in the case of 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. There are also situations where the hedging transactions themselves may result in losses, as when a position is purchased in a declining market or a position is sold in a rising market. Hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol and distillers grains.
We continually monitor and manage our commodity risk exposure and our hedging transactions as part of our overall risk management policy. As a result, we may vary the amount of hedging or other risk mitigation strategies we undertake, and we may choose not to engage in hedging transactions. Our ability to hedge is always subject to our liquidity and available capital.
Dependence on One or a Few Major Customers
As discussed above, we have marketing and agency agreements with Bunge, for the purpose of marketing and distributing our principal products. We rely on Bunge for the sale and distribution of all of our products and are highly dependent on Bunge for the successful marketing of our products. Currently, we do not have the ability to market our ethanol and distillers grains internally should Bunge be unable or refuse to market these products at acceptable prices. We anticipate that we would be able to secure alternate marketers should Bunge fail, however, a loss of Bunge as our marketer could significantly harm our financial performance.
Our Competition
Domestic Ethanol Competitors
The ethanol we produce is similar to ethanol produced by other plants. According to Renewable Fuels Association as of November 29, 2012, there were 211 ethanol plants in the United States with the nameplate capacity to produce 14.7 billion gallons of ethanol annually which were producing 13.3 billion gallons of ethanol annually as of November 29, 2012. An additional four plants are under construction or expanding, which could add an additional estimated 0.16 billion gallons of annual production capacity. On a national level, there are numerous other production facilities with which we are in direct competition, many of whom have greater resources and experience than we have. Some of our competitors are, among other things, capable of producing a significantly greater amount of ethanol or have multiple ethanol plants that may help them achieve certain benefits that we cannot achieve with one ethanol plant. Large producers may have an advantage over us from economies of scale and negotiating position with purchasers. Further, new products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages over us and harm our business.
Foreign Ethanol Competitors
We also face competition from foreign producers of ethanol and such competition may increase significantly in the future. Large international companies with much greater resources than ours have developed, or are developing, increased foreign ethanol production capacities. Brazil is the world’s second largest ethanol producer. Brazil makes ethanol primarily from sugarcane, a process which has historically been lower cost than producing ethanol from corn. This is due primarily to the fact that sugarcane does not need to go through the extensive cooking process to convert the feedstock to sugar. Several large companies produce ethanol in Brazil, including affiliates of Bunge which, according to the Biofuels Digest, are one of the largest ethanol producers in Brazil.
Energy Information Administration (“EIA”) data shows ethanol imports increased from 51.5 million gallons in the first nine months of 2011 to 238.7 million gallons in the first nine months of 2012. According to the EIA data, Brazil was the top source of U.S. ethanol imports, accounting for approximately 85.5% of September 2012 shipments received in U.S. ports. Under the Renewable Fuels Standard, certain parties are obligated to blend, in the aggregate, 2.0 billion gallons of advanced biofuels in 2012. During 2012, sugarcane ethanol imported from Brazil has been one of the most economical means for obligated parties to meet this standard. The Brazilian government may increase the required percentage of ethanol in vehicle fuel sold in Brazil to 25 percent (from 20 percent) as sugarcane production rises, which would likely decrease ethanol exports from Brazil into the U.S.
Ethanol produced in foreign countries, from sugarcane or other feed stocks imported into the United States, was previously subject to an import tariff of $0.54 per gallon. The import tariff expired on December 31, 2011. Depending on feed stock prices, ethanol imported from foreign countries may be less expensive than domestically-produced ethanol as evidenced by the recent increase in ethanol imports from Brazil. However, foreign demand, transportation costs and infrastructure constraints may temper the market impact on the United States.
Local Production
Because we are located on the border of Iowa and Nebraska, and because ethanol producers generally compete primarily with local and regional producers, the ethanol producers located in Iowa and Nebraska presently constitute our primary competition. According to the Iowa Renewable Fuels Association, as of December 6, 2012, Iowa had 41 ethanol refineries in production, nameplate capacity to produce 3.69 billion gallons of ethanol. According to the Nebraska Ethanol Board, there were currently 24 existing ethanol plants in Nebraska as of October, 2012 with a combined ethanol nameplate production capacity of approximately two billion gallons of ethanol a year. Historically, certain plants located in Nebraska were eligible for state incentives, which authorized certain producers to receive up to $2.8 million of tax credits per year for up to eight years. This tax credit program expired in June 2012 and therefore, any competitive advance such plants had over us based on the receipt of such tax credits have been eliminated.
Competition from Alternative Renewable Fuels
We anticipate increased competition from renewable fuels that do not use corn as the feedstock. Many of the current ethanol production incentives are designed to encourage the production of renewable fuels using raw materials other than corn. One type of ethanol production feedstock that is being explored is cellulose. Cellulose is the main component of plant cell walls and is the most common organic compound on earth. Cellulose is found in wood chips, corn stalks, rice straw, amongst other common plants. Cellulosic ethanol is ethanol produced from cellulose. Currently, cellulosic ethanol production technology is not sufficiently advanced to produce cellulosic ethanol on a commercial scale. However, due to government incentives designed to encourage innovation in the production of cellulosic ethanol, we anticipate that commercially viable cellulosic ethanol technology will be developed in the future. Several companies and researchers have commenced pilot projects to study the feasibility of commercially producing cellulosic ethanol. If this technology can be profitably employed on a commercial scale, it could potentially lead to ethanol that is less expensive to produce than corn based ethanol, especially when corn prices are high. Cellulosic ethanol may also capture more government
subsidies and assistance than corn based ethanol. This could decrease demand for our product or result in competitive disadvantages for our ethanol production process.
Because our Facility is designed as single-feedstock facilities, we have limited ability to adapt the plant to a different feedstock or process system without additional capital investment and retooling.
A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells, plug-in hybrids, electric cars or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological option to address worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets in order to decrease fuel costs, lessen dependence on crude oil and reduce harmful emissions. If the fuel cell industry continues to expand and gain broad acceptance and becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would negatively impact our profitability.
Distillers Grain Competition
Ethanol plants in the Midwest produce the majority of distillers grains and primarily compete with other ethanol producers in the production and sales of distillers grains. According to the Renewable Fuels Association's Ethanol Industry Outlook 2012 (the “RFA 2012 Outlook”), ethanol plants produced more than 30 million metric tons of distillers grains in 2010/2011 and are estimated to be more than 35 million metric tons in 2011/2012. We compete with other producers of distillers grains products both locally and nationally.
The primary customers of distillers grains are dairy and beef cattle, according to the RFA 2012 Outlook. In recent years, an increasing amount of distillers grains have been used in the swine and poultry markets. Numerous feeding trials show advantages in milk production, growth, rumen health, and palatability over other dairy cattle feeds. With the advancement of research into the feeding rations of poultry and swine, we expect these markets to expand and create additional demand for distillers grains; however, no assurance can be given that these markets will in fact expand, or if they do, that we will benefit from it.
The market for distillers grains is generally confined to locations where freight costs allow it to be competitively priced against other feed ingredients. Distillers grains compete with three other feed formulations: corn gluten feed, dry brewers grain and mill feeds. The primary value of these products as animal feed is their protein content. Dry brewers grain and distillers grains have about the same protein content, and corn gluten feed and mill feeds have slightly lower protein contents. Distillers grains contain nutrients, fat content, and fiber that we believe will differentiate our distillers grains products from other feed formulations. However, producers of other forms of animal feed may also have greater experience and resources than we do and their products may have greater acceptance among producers of beef and dairy cattle, poultry and hogs.
Principal Supply & Demand Factors
Ethanol
Ethanol prices increased during Fiscal 2012 as a direct response to increasing corn prices. Management currently expects ethanol prices will continue to be directly related to the price of corn. Management believes the industry will need to grow both product delivery infrastructure and demand for ethanol in order to increase production margins in the near and long term. According to Renewable Fuels Association, there were 211 ethanol plants in operation in the United States with the nameplate capacity to produce 14.7 billion gallons of ethanol which were producing 13.3 billion gallons annually as of November 29, 2012. Currently, four plants are under construction or expanding, which could add an additional estimated 0.16 billion gallons of annual production capacity. Although several plants decreased production or shutdown operations during Fiscal 2012 as a result of the compressed margins currently impacting the ethanol industry, if the new supply of ethanol is equally met with ethanol demand, downward pressure on ethanol prices could start.
Management believes it is important that ethanol blending capabilities of the gasoline market be expanded to increase demand for ethanol. Recently, there has been increased awareness of the need to expand ethanol distribution and blending infrastructure, which would allow the ethanol industry to supply ethanol to markets in the United States that are not currently blending ethanol.
Distillers Grains
Distillers grains compete with other protein-based animal feed products. In North America, over 80% of DDGS are used in ruminant animal diets, and are also fed to poultry and swine. Every bushel of corn used in the dry grind ethanol process yields approximately 17 pounds of DDGS, which is an excellent source of energy and protein for livestock and poultry. Introducing DDGS into a feed ration for these animals can reduce the total feed cost from 3 to 10%. The price of distillers grains may decrease when the
prices of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the commodities from which these products are derived. Downward pressure on commodity prices, such as soybeans, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers grains.
Historically, sales prices for distillers grains have been correlated with prices of corn. However, there have been occasions when the price increase for this co-product has lagged behind increases in corn prices. In addition, our distillers grains co-product competes with products made from other feedstocks, the cost of which may not have risen as corn prices have risen. Consequently, the price we may receive for distillers grains may not rise as corn prices rise, thereby lowering our cost recovery percentage relative to corn.
Due to industry increases in U.S. dry mill ethanol production, the production of distillers grains in the United States has increased dramatically, and this trend may continue. This may cause distillers grains prices to fall in the United States, unless demand increases or other market sources are found. To date, demand for distillers grains in the United States has increased roughly in proportion to supply. We believe this is because U.S. farmers use distillers grains as a feedstock, and distillers grains are slightly less expensive than corn, for which it is a substitute. However, if prices for distillers grains in the U.S. fall, it may have an adverse effect on our business.
Management expects that DDGS prices may continue to increase slightly in the next year in response to increased corn prices and a decreased supply of corn resulting from the 2012 drought conditions.
Competition for Supply of Corn
During the last quarter of Fiscal 2012, corn prices traded to all-time highs due to drought conditions in the midwestern region of the U.S. Estimates of supply and demand provided by the U.S. Department of Agriculture forecasted lower production levels and corresponding reduced demand levels as a result of higher corn prices. Consumers of corn, including ethanol producers, are competing for potentially reduced domestic supplies.
Competition for corn supply from other ethanol plants and other corn consumers exists around our Facility. According to Iowa Renewable Fuels Association, as of September 8, 2012, there were 40 operational ethanol plants in Iowa. The plants are concentrated, for the most part, in the northern and central regions of the state where a majority of the corn is produced. The existence and development of other ethanol plants, particularly those in close proximity to our plant, will increase the demand for corn that may result in even higher costs for supplies of corn
We compete with other users of corn, including ethanol producers regionally and nationally, producers of food and food ingredients for human consumption (such as high fructose corn syrup, starches, and sweeteners), producers of animal feed and industrial users. According to the United States Department of Agriculture (“USDA”), for 2010: 5.02 billion bushels of U.S. corn was used in ethanol production, with 1.4 billion bushels being used in food and other industrial uses, and 2.0 billion bushels used for export. As of November 9, 2011, the USDA increased the forecast of the amount of corn to be used for ethanol production during the current marketing year (2011-12). The 2011-12 forecast, which estimates that a total of 5.00 billion bushels of corn will be used in the production of corn ethanol, is approximately 0.20 million bushels less than used in that category last year. The USDA cites the absence of the VEETC in 2012 as well as the current economic forecast as the reason for the decrease.
Federal Ethanol Support and Governmental Regulations
RFS
The ethanol industry is dependent on several economic incentives to produce ethanol, including federal tax incentives and ethanol use mandates. One significant federal ethanol support is the Federal Renewable Fuels Standard (the “RFS”) which has been and will continue to be a driving factor in the growth of ethanol usage. The RFS is a national program that does not require that any renewable fuels be used in any particular area or state, allowing refiners to use renewable fuel blends in those areas where it is most cost-effective. The U.S. Environmental Protection Agency (the “EPA”) is responsible for revising and implementing regulations to ensure that transportation fuel sold in the United States contains a minimum volume of renewable fuel.
On February 3, 2010, the EPA implemented new regulations governing the RFS. These new regulations have been called “RFS2.” RFS2 requires 12.95 billion gallons of renewable fuel be sold or dispensed in 2010, increasing to 36 billion gallons by 2022. The 2012 mandate is for 15.2 billion gallons of renewable fuels. This mandate does not apply just to corn-based ethanol, but includes all forms of fuel created from feedstocks that qualify as “renewable biomass.” The EPA regulation also expanded the RFS program beyond gasoline to generally cover all transportation fuel. We cannot assure that this program’s mandates will continue in the future.
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. As a result of the recent drought conditions, we may see additional legislation aimed at reducing or eliminating the renewable fuel use required by RFS2.
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. In August 2012, governors from eight states filed formal requests with the EPA to waive the RFS 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.
We believe that any reversal or waiver in federal policy on the RFS could have a significant impact on the ethanol industry.
Because of a small corn crop and high corn prices, there is doubt about meeting the ever-increasing future RFS requirements especially in the short-term. There is a possibility that corn production in 2013 may not be able to rebound from the drought in 2012. This means corn producers may not be able to generate the corn supply needed to meet the ethanol industry demand beyond the minimum floor set by the RFS. We are dependent on Bunge’s ability to market the ethanol in this competitive environment.
The most controversial part of RFS2 involves what is commonly referred to as the lifecycle analysis of green house gas emissions. Specifically, the EPA adopted rules to determine which renewable fuels provided sufficient reductions in green house gases, compared to conventional gasoline, to qualify under the RFS program. RFS2 establishes a tiered approach, where regular renewable fuels are required to accomplish a 20% green house gas reduction compared to gasoline, advanced biofuels and biomass-based biodiesel must accomplish a 50% reduction in green house gases, and cellulosic biofuels must accomplish a 60% reduction in green house gases. Any fuels that fail to meet this standard cannot be used by fuel blenders to satisfy their obligations under the RFS program.. Our ethanol plant was grandfathered into the RFS due to the fact that it was constructed prior to the effective date of the lifecycle green house gas requirement and is not required to prove compliance with the lifecycle green house gas reductions.
Based on the final regulations, we believe our Facility, at its current operating capacity, was grandfathered into the RFS given it was constructed prior to the effective date of the lifecycle green house gas requirement and is not required to prove compliance with the lifecycle green house gas reductions. However, expansion of our Facility will require us to meet a threshold of a 20% reduction in greenhouse gas, or GHG emissions to produce ethanol eligible for the RFS 2 mandate. In order to expand capacity at our Facility, we may be required to obtain additional permits, install advanced technology, or reduce drying of certain amounts of distillers grains.
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.
VEETC
In the past, the ethanol industry was impacted by the Volumetric Ethanol Excise Tax Credit (“VEETC”) which is frequently referred to as the “blender’s credit.” The blenders’ credit expired on December 31, 2011 and was not renewed. VEETC provided a volumetric ethanol excise tax credit for $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, management does 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. However, if the RFS is reduced or eliminated, the market price and demand for ethanol will likely decrease which could negatively impact our financial performance.
State Initiatives
In 2006, Iowa passed legislation promoting the use of renewable fuels in Iowa. One of the most significant provisions of the Iowa renewable fuels legislation is a renewable fuels standard encouraging 10% of the gasoline sold in Iowa to consist of renewable fuels. This renewable fuels standard increases incrementally to 25% of the gasoline sold in Iowa by 2019.
E85
Demand for ethanol has been affected by moderately increased consumption of E85 fuel, a blend of 85% ethanol and 15% gasoline. E85 can be used as an aviation fuel, as reported by the National Corn Growers Association, and as a hydrogen source for
fuel cells. According to the United States Department of Energy (the “USDOE”), there are currently more than eight million flexible fuel vehicles capable of operating on E85 in the United States and automakers such as Ford and General Motors have indicated plans to produce several million more flexible fuel vehicles per year. The USDOE reports that there were 2,264 retail gasoline stations supplying E85 as of October 31, 2012. While the number of retail E85 suppliers has increased each year, this remains a relatively small percentage of the total number of U.S. retail gasoline stations, which is approximately 170,000. In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it. As public awareness of ethanol and E85 increases along with E85’s increased availability, management anticipates some growth in demand for ethanol associated with increased E85 consumption.
Changes in Corporate Average Fuel Economy (“CAFÉ”) standards have also benefited the ethanol industry by encouraging use of E85 fuel products. CAFE provides an effective 54% efficiency bonus to flexible-fuel vehicles running on E85. This variance encourages auto manufacturers to build more flexible-fuel models, particularly in trucks and sport utility vehicles that are otherwise unlikely to meet CAFE standards.
E15
E15 is a blend of gasoline and up to 15% ethanol. The EPA has completed its evaluation of the health effects tests of E15 and on February 17, 2012, they announced that fuel manufacturers are now able to register E15 with the EPA for sale. In April 2012, a group of ethanol industry members funded a national fuel survey on E15 to meet one of the final requirements of the EPA prior to introducing E15 into the marketplace. In June 2012, the EPA gave final approval for the sale and use of E15 ethanol blends in light duty vehicles made since 2001, representing nearly two-thirds of all vehicles on the road. In July 2012, the first retail sales of E15 ethanol blends in the U.S. occurred. As of June 5, 2012, 60 fuel manufacturers were registered to sell E15. Prior to the final approval of E85 for sale, the EPA granted partial waivers for certain motor vehicles, subject to certain conditions.
Effective July 1, 2011, Iowa retailers are eligible for a three cent per gallon tax credit for every gallon of E15 sold. Any reversal of the EPA waivers or approvals for the sale of E15 will likely to nullify the tax credit for Iowa retailers and adversely affect the demand for E15.
Cellulosic Ethanol
The Energy Independence and Security Act provided numerous funding opportunities in support of cellulosic ethanol. In addition, RFS2 mandates an increasing level of production of biofuels which are not derived from corn. These policies suggest an increasing policy preference away from corn ethanol and toward cellulosic ethanol. The profitability of ethanol production depends heavily on federal incentives so the loss or reduction of incentives from the federal government in favor of corn-based ethanol production may reduce our profitability.
Environmental Regulations and Permits
Ethanol production involves the emission of various airborne pollutants, including particulate matters, carbon monoxide, oxides of nitrogen, volatile organic compounds and sulfur dioxide. Ethanol production also requires the use of significant volumes of water, a portion of which is treated and discharged into the environment. We are required to maintain various environmental and operating permits. Even though we have successfully acquired the permits necessary for our operations, any retroactive change in environmental regulations, either at the federal or state level, could require us to obtain additional or new permits or spend considerable resources on complying with such regulations. In addition, if we sought to expand the Facility’s capacity in the future, we would likely be required to acquire additional regulatory permits and could also be required to install additional pollution control equipment. Our failure to obtain and maintain any environmental and/or operating permits currently required or which may be required in the future could force us to make material changes to our Facility or to shut down altogether.
The U.S. Supreme Court has classified carbon dioxide as an air pollutant under the Clean Air Act in a case seeking to require the EPA to regulate carbon dioxide in vehicle emissions. As stated above, we believe the final RFS2 regulations grandfather our plant at its current operating capacity, though expansion of our plant will need to meet a threshold of a 20% reduction in green house gas (“GHG”) emissions from a baseline measurement to produce ethanol eligible for the RFS 2 mandate. In order to expand capacity at our plant, we may be required to obtain additional permits, install advanced technology such as corn oil extraction, or reduce drying of certain amounts of distillers grains.
Separately, the California Air Resources Board has adopted a Low Carbon Fuel Standard requiring a 10% reduction in GHG emissions from transportation fuels by 2020. An Indirect Land Use Change component is included in this lifecycle GHG emissions calculation, although several lawsuits have been filed challenging this standard.
Part of our business is regulated by environmental laws and regulations governing the labeling, use, storage, discharge and disposal of hazardous materials. Other examples of government policies that can have an impact on our business include tariffs, duties, subsidies, import and export restrictions and outright embargos.
We also employ maintenance and operations personnel at each of our ethanol plants. In addition to the attention that we place on the health and safety of our employees, the operations at our Facility are governed by the regulations of the Occupational Safety and Health Administration, or OSHA.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge on our website at www.sireethanol.com as soon as reasonably practicable after we file or furnish such information electronically with the SEC. The information found on our website is not part of this or any other report we file with or furnish to the SEC.
The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
Item 1A. Risk Factors.
The following risks, together with additional risks and uncertainties not currently known to us or that we currently deem immaterial, could impair our financial condition and results of operation.
Risks Associated With Our Capital Structure
Our Units have no public trading market and are subject to significant transfer restrictions which could make it difficult to sell Units and could reduce the value of the Units.
There is not an active trading market for our limited liability company interests, or “Units,” to develop. To maintain our partnership tax status, our Units may not be publicly traded. Within applicable tax regulations, we utilize a qualified matching service (“QMS”) to provide a limited market to our Members, but we have not and will not apply for listing of the Units on any stock exchange. Finally, applicable securities laws may restrict the transfer of our Units. As a result, while a limited market for our Units may develop through the QMS, Members may not sell Units readily, and use of the QMS is subject to a variety of conditions and limitations. The transfer of our Units is also restricted by our Third Amended and Restated Operating Agreement dated July 17, 2009 (the “Operating Agreement”) unless the Board of Directors (the “Board” or “Board of Directors”) approves such a transfer. Furthermore, the Board will not approve transfer requests which would cause the Company to be characterized as a publicly traded partnership under the regulations adopted under the Internal Revenue Code of 1986, as amended (the “Code”). The value of our Units will likely be lower because they are illiquid. Members are required to bear the economic risks associated with an investment in us for an indefinite period of time.
Our failure to comply with our loan covenants could require us to abandon our business.
Our indebtedness, including the indebtedness under the Credit Agreement (the “Credit Agreement”) with AgStar Financial Services, PCA and a group of lenders (collectively the “Lenders”), a revolving note with Bunge, and convertible debt, increases the risk that we will not be able to operate profitably because we will need to make principal and interest payments on the indebtedness. Debt financing also exposes our Members to the risk that their entire investment could be lost in the event of a default on the indebtedness and a foreclosure and sale of the Facility and its assets for an amount that is less than the outstanding debt. Our ability to obtain additional debt financing, if required, will be subject to approval of our lending group, which may not be granted, the interest rates and the credit environment as well as general economic factors and other factors over which we have no control.
Our debt service requirements and restrictive loan covenants limit our ability to borrow more money, make cash distributions to our Members and engage in other activities.
Under the terms of our indebtedness (the “ Current Loans”)we have made certain customary representations and we are subject to customary affirmative and negative covenants, including restrictions on our ability to incur additional debt that is not subordinated, create additional liens, transfer or dispose of assets, make distributions, make capital expenditures, consolidate, dissolve or merge, and customary events of default (including payment defaults, covenant defaults, cross defaults, construction related defaults and bankruptcy defaults). The Current Loans also contain financial covenants including a maximum revolving credit availability based on
the borrowing base, minimum working capital amount, minimum tangible net worth, a minimum fixed charge coverage ratio, and a minimum tangible owner’s equity. Our obligations to repay principal and interest on the Current Loans make us vulnerable to economic or market downturns. If we are unable to service our debt, we may be forced to sell assets, restructure our indebtedness or seek additional equity capital, which would dilute our Members’ interests. If we default on any covenant, our current Lenders or (or any subsequent lender) could make the entire debt, once incurred, immediately due and payable. If this occurs, we might not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be on terms that are acceptable to us. These events could cause us to cease operations.
Risks Associated With Operations
We are dependent on MidAm for our steam supply and any failure by it may result in a decrease in our profits or our inability to operate.
Under the Steam Contract, MidAm provides us with steam to operate our Facility until January 1, 2019. We expect to face periodic interruptions in our steam supply under the Steam Contract. For this reason, we installed boilers at the Facility to provide a backup natural gas energy source. We also have entered into a natural gas supply agreement with Constellation Energy for our long term natural gas needs, but this does not assure availability at all times. In addition, our current environmental permits limit the annual amount of natural gas that we may use in operating our gas-fired boiler.
As with natural gas and other energy sources, our steam supply can be subject to immediate interruption by weather, strikes, transportation, and production problems that can cause supply interruptions or shortages. While we anticipate utilizing natural gas as a temporary heat source under MidAm’s plant outages, an extended interruption in the supply of both steam and natural gas backup could cause us to halt or discontinue our production of ethanol, which would damage our ability to generate revenues.
We may not be able to protect ourselves from an increase in the price of steam which may result in a decrease in profits.
We are significantly dependent on the price of steam. The Steam Contract sets the price of steam until January 1, 2012 and provides for price increases annually thereafter. The price increases are based upon market forces over which we have no control. The Steam Contract will protect us from extreme price changes for the term of the agreement, but upon the expiration of the Steam Contract, there is no assurance that we will be able to enter into a similar agreement. Although coal prices and supplies have historically been more stable than many other forms of energy, this may not be taken into consideration when we are negotiating a new steam contract. If higher steam prices are sustained for some time, such pricing may reduce our profitability due to higher operating costs.
Any site near a major waterway system presents potential for flooding risk.
While our site is located in an area designated as above the 100-year flood plain, it does exist within an area at risk of a 500-year flood. Even though our site is protected by levee systems, its existence next to a major river and major creeks present a risk that flooding could occur at some point in the future. During the last half of Fiscal 2011, the Missouri River experienced significant flooding, as a result of unprecedented amounts of rain and snow in the Missouri River basin. This produced a sustained flood lasting many weeks at a 500-year flood level (a level which has a 0.2 percent chance of occurring). While there were levee failures elsewhere, the levees held around our facility. We did experience minimal rail disruption due to flooding in the surrounding areas to the north and south of the Facility, but our operations were not significantly impacted.
We have procured flood insurance as a means of risk mitigation; however, there is a chance that such insurance will not cover certain costs in excess of our insurance associated with flood damage or loss of income during a flood period. Our current insurance may not be adequate to cover the losses that could be incurred in a flood of a 500-year magnitude.
We may experience delays or disruption in the operation of our rail line and loop track, which may lead to decreased revenues.
We have entered into the Track Agreement to service our track and railroad cars, which we will be highly dependent on. There may be times when we have to slow production at our ethanol plant due to our inability to ship all of the ethanol and distillers grains we produce. If we cannot operate our plant at full capacity, we may experience decreased revenues which may affect the profitability of the Facility.
Our operating costs could increase, thereby reducing our profits or creating losses, which would decrease the value of Units or Members’ investment return.
We could experience cost increases associated with the operation of the Facility caused by a variety of factors, many of which are beyond our control. Corn prices are volatile and labor costs could increase over time, particularly if there is a shortage of persons with the skills necessary to operate the Facility. The adequacy and cost of electricity, steam and natural gas utilities could also affect our operating costs. Changes in price, operation and availability of truck and rail transportation may affect our profitability with respect to the transportation of ethanol and distillers grains to our customers. In addition, the operation of the Facility is subject to ongoing compliance with all applicable governmental regulations, such as those governing pollution control, ethanol production, grain purchasing and other matters. If any of these regulations were to change, it could cost us significantly more to comply with them. We will be subject to all of these regulations whether or not the operation of the Facility is profitable.
Our lack of business diversification could result in the devaluation of our Units if our revenues from our primary products decrease.
Our business consists solely of ethanol, distillers grains and corn oil production and sales. If economic or political conditions adversely affect the market for ethanol, distillers grains and corn oil, we have no other lines of business or other sources of revenue if we are unable to operate our plant and manufacture these products. Our lack of diversifications means that our financial condition would be significantly harmed if we could not operate at full capacity for any extended period of time.
We have a history of losses and may not ever operate profitably.
From our inception on March 28, 2005 through September 30, 2012, we incurred an accumulated net loss of approximately $29,412,013. There is no assurance that we will be able to operate profitably.
We may have conflicting financial interests with Bunge and ICM that could cause them to put their financial interests ahead of ours.
ICM and Bunge advise our directors and have been, and are expected to be, involved in substantially all material aspects of our financing and operations. We have entered into a number of material commercial arrangements with Bunge, as described elsewhere in this report. Consequently, the terms and conditions of our agreements with ICM and Bunge have not been negotiated at arm’s length. Therefore, these arrangements may not be as favorable to us as could have been if obtained from unaffiliated third parties. In addition, because of the extensive roles that ICM and Bunge had, it may be difficult or impossible for us to enforce claims that we may have against ICM or Bunge. Such conflicts of interest may reduce our profitability and the value of the Units and could result in reduced distributions to investors.
ICM, Bunge and their respective affiliates may also have conflicts of interest because ICM, Bunge and their respective employees or agents are involved as owners, creditors and in other capacities with other ethanol plants in the United States. We cannot require ICM or Bunge to devote their full time or attention to our activities. As a result, ICM and/or Bunge may have, or come to have, a conflict of interest in allocating personnel, materials and other resources to our Facility.
Hedging transactions, which are primarily intended to stabilize our corn costs, may be ineffective and involve risks and costs that could reduce our profitability and have an adverse impact on our liquidity.
We are exposed to market risk from changes in commodity prices. Exposure to commodity price risk results principally from our dependence on corn in the ethanol production process. In an attempt to minimize the effects of the volatility of corn costs on our operating profits, we enter into forward corn, ethanol, and distillers grain contracts and engage in other hedging transactions involving over-the-counter and exchange-traded futures and option contracts for corn; provided, we have sufficient working capital to support such hedging transactions. Hedging is an attempt to protect the price at which we buy corn and the price at which we will sell our products in the future and to reduce profitability and operational risks caused by price fluctuation. The effectiveness of our hedging strategies, and the associated financial impact, depends upon, among other things, the cost of corn and our ability to sell sufficient amounts of ethanol and distillers grains to utilize all of the corn subject to our futures contracts. Our hedging activities may not successfully reduce the risk caused by price fluctuations which may leave us vulnerable to high corn prices. We have experienced hedging losses in the past and we may experience hedging losses again in the future. We may vary the amount of hedging or other price mitigation strategies we undertake, or we may choose not to engage in hedging transactions in the future and our operations and financial conditions may be adversely affected during periods in which corn prices increase.
Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of over-the-counter or exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us.
Our attempts to reduce market risk associated with fluctuations in commodity prices through the use of over-the-counter or exchange-traded futures results in additional costs, such as brokers’ commissions, and may require cash deposits with brokers or
margin calls. Utilizing cash for these costs and to cover margin calls has an impact on the cash we have available for our operations which could result in liquidity problems during times when corn prices fall significantly. Depending on our open derivative positions, we may require additional liquidity with little advance notice to meet margin calls. We have had to in the past, and in the future will likely be required to, cover margin calls. While we continuously monitor our exposure to margin calls, we cannot guarantee that we will be able to maintain adequate liquidity to cover margin calls in the future.
Ethanol production is energy intensive and interruptions in our supply of energy, or volatility in energy prices, could have a material adverse impact on our business.
Ethanol production requires a constant and consistent supply of energy. If our production is halted for any extended period of time, it will have a material adverse effect on our business. If we were to suffer interruptions in our energy supply, our business would be harmed. We have entered into the Steam Contract for our primary energy source. We also are able to operate at full capacity using natural gas-fired boilers, which mitigates the risk of disruption in steam supply. However, the amount of natural gas we are permitted to use for this purpose is currently limited and the price of natural gas may be significantly higher than our steam price. In addition, natural gas and electricity prices have historically fluctuated significantly. Increases in the price of steam, natural gas or electricity would harm our business by increasing our energy costs. The prices which we will be required to pay for these energy sources will have a direct impact on our costs of producing ethanol and our financial results.
Our ability to successfully operate depends on the availability of water.
To produce ethanol, we need a significant supply of water, and water supply and quality are important requirements to operate an ethanol plant. Our water requirements are supplied by our wells, but there are no assurances that we will continue to have a sufficient supply of water to sustain the Facility in the future, or that we can obtain the necessary permits to obtain water directly from the Missouri River as an alternative to our wells. As a result, our ability to make a profit may decline.
We have executed an output contract for the purchase of all of the ethanol we produce, which may result in lower revenues because of decreased marketing flexibility and inability to capitalize on temporary or regional price disparities.
Bunge is the exclusive purchaser of our ethanol and markets our ethanol in national, regional and local markets. We do not plan to build our own sales force or sales organization to support the sale of ethanol. As a result, we are dependent on Bunge to sell our principal product. When there are temporary or regional disparities in ethanol market prices, it could be more financially advantageous to have the flexibility to sell ethanol ourselves through our own sales force. We have decided not to pursue this route. Our strategy could result in lower revenues and reduce the value of Units if Bunge does not perform as we plan.
Risks Associated With the Ethanol Industry
Continued price volatility and recent increases in the price of corn may adversely impact our operating results and profitability.
Our operating results and financial condition are significantly affected by the price and supply of corn. Because ethanol competes with non-corn derived fuels, we generally are unable to pass along increases in corn costs to our customers. At certain levels, corn prices may make the production of ethanol uneconomical. There is currently significant price pressure on local corn markets caused by nearby ethanol plants, livestock industries and other corn consuming enterprises. If the demand for corn continues to drive corn prices significantly higher, we may not be able to acquire the corn needed to continue operations.
Additionally, local corn supplies and prices could be adversely affected by rising prices for alternative crops, increasing input costs, changes in government policies, shifts in global markets, or damaging growing conditions such as plant disease or adverse weather. Corn prices have increased in response to drought conditions in the Midwestern region of the U.S. and concern that a resulting decrease in the supply of corn could lead to the rationing of corn supplies, which could cause further increases in the price of corn and negatively impact our production margins. The continuation of drought conditions resulting in a decreased corn supply combined with rising demand and corn prices may have a material adverse impact on our cash flows, results of operations and financial condition.
The oversupply of ethanol and decreased prices for ethanol could adversely affect our results of operations and our ability to operate at a profit.
Our revenues are dependent on market prices for ethanol. Market prices for ethanol can be volatile as a result of a number of factors, including, but not limited to, the availability and price of competing fuels, the overall supply and demand for ethanol and corn, the price of gasoline and corn, and the level of government support.
Ethanol is marketed as a fuel additive to reduce vehicle emissions from gasoline, as an octane enhancer to improve the octane rating of the gasoline with which it is blended and, to a lesser extent, as a gasoline substitute. As a result, ethanol prices are influenced by the supply of and demand for gasoline. Our results of operations may be adversely impacted if the demand for, or the price of gasoline decreased. The United States ethanol industry presently has a nameplate production capacity of approximately 14.7 billion gallons per year according to the Renewable Fuels Association. However, the current Federal Renewable Fuels Standard, known as RFS2, requires that U.S. ethanol blenders purchase only 13.2 billion gallons of renewable biofuels during 2012. During 2011, the U.S. exported a record 1.2 billion gallons of ethanol, according to the Renewable Fuels Association. However, net exports in 2012 remain uncertain given a jump in imports following the expiration of the import tariff on December 31, 2011 and a weaker Brazilian currency in 2012. Brazil purchased approximately 40% of U.S. ethanol exports in 2011. If the U.S. ethanol supply imbalance continues, then ethanol prices and our profit margins may remain narrow or further decrease.
Our results of operations can also be materially harmed when the price of ethanol exceeds the price of wholesale gasoline because it discourages the blending of ethanol with gasoline and encourages the use of surplus 2012 renewable identification numbers (RINs) by obligated parties to satisfy applicable standards. The reduction in the demand for ethanol due to the use of 2012 RINs further reduces production margins due to lower volumes and resulting pressure on the price of ethanol. Such conditions could adversely affect our cash flows and results of operations.
Any waiver granted by the EPA to the mandated RFS2 requirements, in whole or in part, could further negatively impact the demand for ethanol. Although on November 16, 2012, the EPA denied a recent waiver requests filed by various state governors, we cannot guarantee that the EPA will deny future waiver requests. Any grant any waiver request could have a material adverse impact on our cash flows, results of operations and financial condition.
The Federal Volumetric Ethanol Excise Tax Credit expired on December 31, 2011 and its absence could negatively impact our profitability.
The VEETC program allowed gasoline distributors who blend ethanol with gasoline to receive a $0.45 federal excise tax credit for each gallon of ethanol they blended. This excise tax credit expired on December 31, 2011. It is unclear exactly how the absence of this tax credit will affect the ethanol market over time, but it could negatively impact the price we receive for our ethanol and our operating results and financial condition.
The secondary tariff on imported ethanol expired in December 2011, and its absence could have a material adverse impact on our cash flows, operating results and financial condition.
The secondary tariff on imported ethanol expired in December 2011. Accordingly, it is possible that we could see an increase in ethanol produced in foreign countries being marketed in the United States, which could negatively impact our profitability. The secondary tariff on imported ethanol was a $0.54 per gallon tariff on ethanol imports from certain foreign countries. If market prices make importing ethanol to the United States profitable for foreign producers, we could see an influx of imported ethanol on the domestic ethanol market which could impair our ability to profitably compete with low-cost international producers and have a material adverse impact on domestic ethanol prices and our cash flows, operating results and financial condition.
We compete with larger, better financed entities, which could negatively impact our ability to operate profitably.
There is significant competition among ethanol producers with numerous producers and privately-owned ethanol plants planned and operating throughout the Midwest and elsewhere in the United States. Our business faces a competitive challenge from larger plants, from plants that can produce a wider range of products than we can, and from other plants similar to ours. Large ethanol producers such as Abengoa Bioenergy Corp., Archer Daniels Midland, Cargill, Inc., Green Plains Renewable Energy, Inc., Valero and POET, among others, are capable of producing a significantly greater amount of ethanol than we produce. Furthermore, ethanol from certain Central American or Caribbean countries may be a less expensive alternative to domestically-produced ethanol.
Excess capacity in the domestic ethanol market may adversely impact our operations, cash flow and general financial performance.
According to the Renewable Fuel Association as of November 17, 2012, there were 14.71 billion gallons of nameplate capacity installed in the U.S. of which 13.3 billion gallons of annual production capacity was in operations. An additional .16 billion gallons were under construction or expansion. Iowa alone is estimated to produce approximately 3.57 billion gallons of ethanol in 2012. Excess capacity in the ethanol market will have an adverse impact on our operations, cash flows and general financial conditions. If demand for ethanol does not grow at the same pace as increases in supply, the price of ethanol will likely decline. If excess capacity in the ethanol industry continues, the combination of the excess capacity with lower domestic corn supply and higher
corn prices may make it difficult to generate sufficient cash flow to cover our costs in the short term. This could negatively impact our future profitability.
Low ethanol prices and low gasoline prices could reduce our profitability.
Prices for ethanol products can vary significantly over time and decreases in price levels could adversely affect our profitability and viability. The price for ethanol has some relation to the price for oil and gasoline. The price of ethanol tends to increase as the price of gasoline increases, and the price of ethanol tends to decrease as the price of gasoline decreases, although this may not always be the case. Any lowering of gasoline prices will likely also lead to lower prices for ethanol and adversely affect our operating results. Further increased production of ethanol may lead to lower prices. Any downward change in the price of ethanol may decrease our prospects for profitability.
Changes and advances in ethanol production technology could require us to incur costs to update our Facility or could otherwise hinder our ability to complete in the ethanol industry or operate profitably.
Advances and changes in the technology of ethanol production are expected to occur. Such advances and changes may make the ethanol production technology installed in our plant less desirable or obsolete. These advances could also allow our competitors to produce ethanol at a lower cost than us. If we are unable to adopt or incorporate technological advances, our ethanol production methods and processes could be less efficient than our competitors, which could cause our plant to become uncompetitive or completely obsolete. If our competitors develop, obtain or license technology that is superior to ours or that makes our technology obsolete, we may be required to incur significant costs to enhance or acquire new technology so that our ethanol production remains competitive. Alternatively, we may be required to seek third-party licenses, which could also result in significant expenditures. We cannot guarantee or assure that third-party licenses will be available or, once obtained, will continue to be available on commercially reasonable terms, if at all. These costs could negatively impact our financial performance by increasing our operating costs and reducing our net income.
Competition from the advancement of alternative fuels may decrease the demand for ethanol and negatively impact our profitability.
Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean burning gaseous fuels. Like ethanol, the emerging fuel cell industry offers a technological option to address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets in order to lower fuel costs, decrease dependence on crude oil and reduce harmful emissions. If the fuel cell and hydrogen industries continue to expand and gain broad acceptance, and hydrogen becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would negatively impact our profitability.
Corn-based ethanol may compete with cellulose-based ethanol in the future, which could make it more difficult for us to produce ethanol on a cost-effective basis.
Most ethanol produced in the U.S. is currently produced from corn and other raw grains, such as milo or sorghum - especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste and energy crops. This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas which are unable to grow corn. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. It may not be practical or cost-effective to convert our Facility into a plant which will use cellulose-based biomass to produce ethanol. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue will be negatively impacted.
Risks Associated With Government Regulation and Subsidization
Federal regulations concerning tax incentives could expire or change, which could reduce our revenues.
The federal government presently encourages ethanol production by taxing it at a lower rate which indirectly benefits us. Some states and cities provide additional incentives. The 2005 Act and the 2007 Act effectively mandated increases in the amount of annual ethanol consumption in the United States. The result is that the ethanol industry’s economic structure is highly dependent on governmental policies. Although current policies are favorable factors, any major change in federal policy, including a decrease in
ethanol production incentives, would have significant adverse effects on our operations and might make it impossible for us to continue in business.
We are subject to extensive environmental regulation and operational safety regulations that impact our expenses and could reduce our profitability.
Ethanol production involves the emission of various airborne pollutants, including particulate matters, carbon monoxide, oxides of nitrogen, volatile organic compounds and sulfur dioxide. We are subject to regulations on emissions from the EPA and the IDNR. The EPA’s and IDNR’s environmental regulations are subject to change and often such changes are not favorable to industry. Consequently, even if we have the proper permits now, we may be required to invest or spend considerable resources to comply with future environmental regulations.
Our failure to comply or the need to respond to threatened actions involving environmental laws and regulations may adversely affect our business, operating results or financial condition. We must follow procedures for the proper handling, storage, and transportation of finished products and materials used in the production process and for the disposal of waste products. In addition, state or local requirements also restrict our production and distribution operations. We could incur significant costs to comply with applicable laws and regulations. Changes to current environmental rules for the protection of the environment may require us to incur additional expenditures for equipment or processes.
We could be subject to environmental nuisance or related claims by employees, property owners or residents near the Facility arising from air or water discharges. Ethanol production has been known to produce an odor to which surrounding residents could object. We believe our plant design mitigates most odor objections. However, if odors become a problem, we may be subject to fines and could be forced to take costly curative measures. Environmental litigation or increased environmental compliance costs could significantly increase our operating costs.
We are subject to federal and state laws regarding operational safety. Risks of substantial compliance costs and liabilities are inherent in ethanol production. Costs and liabilities related to worker safety may be incurred. Possible future developments-including stricter safety laws for workers or others, regulations and enforcement policies and claims for personal or property damages resulting from our operation could result in substantial costs and liabilities that could reduce the amount of cash that we would otherwise have to distribute to Members or use to further enhance our business.
Carbon dioxide may be regulated by the EPA in the future as an air pollutant, requiring us to obtain additional permits and install additional environmental mitigation equipment, which may adversely affect our financial performance.
Our Facility emits carbon dioxide as a by-product of the ethanol production process. The United States Supreme Court has classified carbon dioxide as an air pollutant under the Clean Air Act in a case seeking to require the EPA to regulate carbon dioxide in vehicle emissions. Similar lawsuits have been filed seeking to require the EPA to regulate carbon dioxide emissions from stationary sources such as our ethanol plant under the Clean Air Act. While there are currently no regulations applicable to us concerning carbon dioxide, if Iowa or the federal government, or any appropriate agency, decides to regulate carbon dioxide emissions by plants such as ours, we may have to apply for additional permits or we may be required to install carbon dioxide mitigation equipment or take other steps unknown to us at this time in order to comply with such law or regulation. Compliance with future regulation of carbon dioxide, if it occurs, could be costly and may prevent us from operating the Facility profitably.
Our site borders nesting areas used by endangered bird species, which could impact our ability to successfully maintain or renew operating permits. The presence of these species, or future shifts in its nesting areas, could adversely impact future operating performance.
The Piping Plover ( Charadrius melodus ) and Least Tern ( Sterna antillarum ) use the fly ash ponds of the existing MidAm power plant for their nesting grounds. The birds are listed on the state and federal threatened and endangered species lists. The IDNR determined that our rail operation, within specified but acceptable limits, does not interfere with the birds’ nesting patterns and behaviors. However, it was necessary for us to modify our construction schedules, plant site design and track maintenance schedule to accommodate the birds’ patterns. We cannot foresee or predict the birds’ future behaviors or status. As such, we cannot say with certainty that endangered species related issues will not arise in the future that could negatively affect the plant’s operations.
Item 2. Properties.
We own the Facility site located near Council Bluffs, Iowa, which consists of three parcels totaling 200 acres. This property is encumbered under the mortgage agreement with Lenders. We lease a building on the Facility site to an unrelated third party, and lease 55.202 acres on the south end of the property to an unrelated third party for farming.
Item 3. Legal Proceedings.
There are no items to report.
Item 4. (Removed and Reserved).
PART II
Item 5. Market for Registrant’s Common Equity, Related Member Matters, and Issuer Purchases of Equity Securities.
As of September 30, 2012, we had (i) 8,805 Series A Units issued and outstanding held by 823 persons, (ii) 3,334 Series B Units issued and outstanding held by Bunge, and (iii) 1,000 Series C Units issued and outstanding held by ICM. We do not have any established trading market for its Units, nor is one contemplated. To date, we have made distributions totaling $1,000,009 to our Members; however, we cannot be certain if or when we will be able to make additional distributions. Further, our ability to make distributions is restricted under the terms of the Credit Agreement.
Item 6. Selected Financial Data.
| | | |
| Fiscal 2012 | | Fiscal 2011 |
| Amounts | | Amounts |
| in 000's | | in 000's |
Balance Sheet Data | | | |
Cash and cash equivalents | 6,285 | | 11,007 |
Total current assets | 36,753 | | 42,032 |
Total Assets | 192,383 | | 207,834 |
Total current liabilities | 29,798 | | 37,110 |
Total long term liabilities | 115,523 | | 122,000 |
Total Liabilities | 145,321 | | 159,110 |
Total members' equity | 47,062 | | 48,724 |
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:
| | |
| Ÿ | 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. |
| Ÿ | 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):
| | | |
| Fiscal 2012 | | Fiscal 2011 |
| Amounts | | Amounts |
| in 000's | | in 000's |
Income Statement | | | |
Revenues | 362,876 | | 333,089 |
Cost of Goods Sold | 349,812 | | 321,599 |
Gross Margin | 13,064 | | 11,490 |
General and administrative expenses | 4,533 | | 4,357 |
Other Expense | 9,193 | | 9,840 |
Net Loss | (662) | | (2,707) |
Loss per Unit: | | | |
Basic & Diluted | (50.35) | | (206.05) |
| | | |
| Fiscal 2012 | | Fiscal 2011 |
| Amounts | | Amounts |
| in 000's | | in 000's |
EBITDA | | | |
Net Loss | (662) | | (2,707) |
Interest Expense | 10,156 | | 9,884 |
Depreciation | 11,393 | | 13,536 |
EBITDA | 20,887 | | 20,713 |
| | | |
Unrealized Hedging (gain) loss | (8,063) | | 5,585 |
| | | |
Adjusted EBITDA | 12,824 | | 26,298 |
| | | |
Adjusted EBITDA per unit | 976.02 | | 2,001.50 |
Item 7. 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 thereto and the risk factors contained herein.
Overview
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 (the “Facility”). We began producing ethanol in February, 2009 and sell our ethanol, modified wet distillers grains with solubles, 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.
Industry Factors Affecting our Results of Operations
During Fiscal 2012, the ethanol industry experienced compressed ethanol margins as a result of a combination of factors, including the following:
| · | Ethanol stocks at the end calendar year 2011 exceeded normal market levels as a result of increase production during the last three months of calendar year 2011 to meet demand from ethanol blenders trying to take advantage of VEETC prior to its expiration on December 31, 2011. |
| · | Corn prices increased substantially during Fiscal 2012 and traded at all-time highs during the fourth quarter of Fiscal 2012. |
| · | Estimates of supply and demand provided by the U.S. Department of Agriculture forecasted lower production levels and correspondingly reduced demand levels as result of higher corn prices. |
| · | 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 91% of August 2012 shipments received in U.S. ports, according to the Renewal Fuels Association. |
The combination of these factors caused ethanol margins to compress to near break-even levels during Fiscal 2012. In response to the compressed margin environment, according to the Energy Information Administration (“EIA”), as an industry, ethanol producers reduced production rates from 962 thousand barrels per day as of the end of the fourth quarter of calendar 2011 to 785 thousand barrels per day as of the end of the third quarter of calendar 2012 representing an 18.4% decrease. Although it appears that the margin environment in the first quarter of Fiscal 2013 is improving, 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 could adversely affect our operating results in Fiscal 2013.
Results of Operations
The following table shows our results of operations, stated as a percentage of revenue for Fiscal 2012 and 2011.
| | | | | | | | | | | |
| Fiscal 2012 | | Fiscal 2011 |
| Amounts | | % of Revenues | | Gallons Average Price | | Amounts | | % of Revenues | | Gallons Average Price |
| in 000's | | | | | | in 000's | | | | |
Income Statement Data | | | | | | | | | | | |
Revenues | 362,876 | | 100% | | $ 2.96 | | 333,089 | | 100% | | $ 2.91 |
Cost of Good Sold | | | | | | | | | | | |
Material Costs | 305,723 | | 84% | | 2.49 | | 259,184 | | 78% | | 2.26 |
Variable Production Exp | 26,894 | | 7% | | 0.22 | | 31,369 | | 9% | | 0.27 |
Fixed Production Exp | 17,195 | | 5% | | 0.14 | | 31,046 | | 9% | | 0.27 |
Gross Margin | 13,064 | | 4% | | 0.11 | | 11,490 | | 3% | | 0.11 |
General and Administrative Expenses | 4,533 | | 1% | | 0.04 | | 4,357 | | 1% | | 0.04 |
Other Expenses | 9,193 | | 3% | | 0.07 | | 9,840 | | 3% | | 0.09 |
Net Loss | (662) | | 0% | | $ (0.00) | | (2,707) | | -1% | | $ (0.02) |
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. The increase in revenue from Fiscal 2011 to Fiscal 2012 was due to an 8.1 million gallon increase in ethanol sold during Fiscal 2012 over Fiscal 2011 (partially offset by the average price per gallon of ethanol decreasing by approximately $ 0.10 per gallon) and an increase in the combined DDG, WDG, & Syrup average price per ton of approximately $ 35, with 22,089 additional tons being produced between the two years. Corn oil, first introduced in Fiscal 2011, generated an extra $4.8 million of revenue. Corn oil revenue was equal to about 3% and 2% of our total revenue for Fiscal 2012 and Fiscal 2011, respectively.
| | | | | | | | | | | |
| Fiscal 2012 | | Fiscal 2011 |
| Gallons/Tons Sold | | % of Revenues | | Gallons/Tons Average Price | | Gallons/Tons Sold | | % of Revenues | | Gallons/Tons Average Price |
Statistical Revenue Information | | | | | | | | | | | |
Denatured Ethanol | 122,626,702 | | 76.460% | | $ 2.26 | | 114,506,382 | | 81.223% | | $ 2.36 |
Dry Distiller's Grains | 293,806 | | 17.472% | | $ 216 | | 305,929 | | 15.888% | | $ 173 |
Wet Distiller's Grains | 110,725 | | 2.862% | | $ 94 | | 43,877 | | 0.959% | | $ 73 |
Syrup | 29,522 | | 0.443% | | $ 54 | | 62,158 | | 0.357% | | $ 19 |
Corn Oil | 13,382 | | 2.763% | | $ 749 | | 5,858 | | 1.573% | | $ 894 |
Cost of Goods Sold
Our cost of goods sold as a percentage of our revenues was 96% and 97% for Fiscal 2012 and 2011, respectively. Our two primary costs of producing ethanol and distillers grains are corn and energy, with steam as our primary energy source and to a lesser extent, natural gas. Cost of goods sold also includes net (gains) or losses from derivatives and hedging relating to corn. We ground 43,597,171 and 40,779,371 bushels of corn at an average price of $6.68 and $6.49 per bushel during Fiscal 2012 and 2011, respectively. Our average steam and natural gas energy cost was $3.85 and $4.76 per MMBTU for Fiscal year 2012 and Fiscal 2011, respectively.
Realized and unrealized gains related to our derivatives and hedging related to corn resulted in a decrease of $7,766,608 in our cost of goods sold for Fiscal 2012, compared to a decrease of $6,325,414 in our cost of goods sold for Fiscal 2011. 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 an increase when comparing Fiscal 2012 to Fiscal 2011 due to the quantity and price of chemicals increasing. Fixed production expenses showed a decrease when comparing Fiscal 2012 to Fiscal 2011 due to a reduction in depreciation expense. While depreciation expense decreased, marketing expenses and repairs and maintenance expense increased when comparing Fiscal 2012 to Fiscal 2011.
Effective January 1, 2011, the Company increased the estimated useful life on a significant portion of its processing equipment. Management believes this change of estimate more closely approximates the actual life. This change in estimate is accounted for on a prospective basis. This change resulted in a decrease in depreciation expense, an increase to operating income, a decrease net (loss) of approximately $7.3 million and $5.4 million for Fiscal 2012 and 2011, respectively, and a decrease in (loss) per unit of $556 and $411 for Fiscal 2012 and 2011, respectively.
General & Administrative Expense
Our general and administrative expenses as a percentage of revenues were 1% for both Fiscal 2012 and 2011. Operating expenses include salaries and benefits of administrative employees, professional fees and other general administrative costs. Our general and administrative expenses for Fiscal 2012 were approximately $4,533,000, as compared to approximately $4,357,000 for Fiscal 2011. The increase in general and administrative expenses from Fiscal 2011 to Fiscal 2012 is due to an increase in professional fees. We expect our operating expenses to remain flat to slightly decreasing during the first two quarters of the year ending September 30, 2013 (“Fiscal 2013“).
Other (Expense)
Our other expenses for both Fiscal 2012 and 2011 were approximately 3% of our revenues, respectively. Our other expenses for the years ended Fiscal 2012 and 2011 were approximately $9,193,000 and $9,840,000, respectively. The majority of this decrease in other expenses was a result of a Patronage Dividend recorded as other income which occurred in Fiscal 2012
Net (Loss)
Our net losses from operations for Fiscal 2012 and 2011 were approximately 0% and 1% of our revenues, respectively.
Liquidity and Capital Resources
As of September 30, 2012, we had a balance of $84,866,648 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) fifteen million dollars ($15,000,000.00), 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 September 30, 2012.
Under our $15 million revolving line of credit with the Lenders (the “Revolving LOC”), we had $5,875,000 outstanding as of September 30, 2012 and $3,500,000 as of September 30, 2011, respectively, with an additional $9,125,000 and $11,500,000 available at September 30, 2012 and 2011, 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 September 30, 2012 and September 30, 2011, the balance outstanding was $3,750,000 and $3,000,000, 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 DDGS) are expected to be volatile in the first 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 be weak in the first 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.
Primary Working Capital Needs
Cash provided by operations for Fiscal 2012 and 2011 was $8,464,000 and $25,307,000, respectively. This change is a result of increased corn and ethanol prices. For Fiscal 2012 and 2011, net cash used in investing activities was ($875,000) and ($3,159,000), respectively, primarily for fixed asset additions. For Fiscal 2012 and 2011, net cash used in financing activities was ($12,311,000) and ($14,574,000), respectively. In 2012 the cash was used to pay down our debt. During Fiscal 2012, pursuant to contractual terms, we made principal payments on our term debt in the amount of $14,262,287, which included an Excess Cash Flow Payment of $3,757,406.
During the first quarter of Fiscal 2012, we estimate that we will require approximately $68,100,000 for our primary input of corn and $3,130,000 for our energy sources of steam and natural gas. We currently have approximately $9,125,000 available under our Revolving LOCs 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.
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 the wholesale price of gasoline. Ethanol prices can vary from state to state at any given time. For the past two years as of September, 2012 according to the Chicago Board of Trade (“CBOT”), the average U.S. ethanol price was $2.54 per gallon. For the same time period, the average U.S. wholesale gasoline price was $2.83 per gallon or approximately $0.29 per gallon above ethanol prices. As of September 28, 2012, the average U.S. ethanol price was $2.35 per gallon. For the same time period, U.S. wholesale gasoline prices (RBOB) averaged $2.92 per gallon, or approximately $0.57 per gallon above ethanol prices. We believe the trend exhibited in the fourth quarter of Fiscal 2012 matches the exhibited trend over the past two years.
In response to the anticipated expiration of the VEETC, during the fourth quarter of 2011, the ethanol industry increased production in order to meet the demand of ethanol blenders seeking to take advantage of the blenders’ credit before it expired. This increased production resulted in an ethanol supply that exceeded normal market levels which has caused ethanol margins to constrict to break even or negative levels since the end of 2011. According to the Energy Information Administration, as an industry, ethanol producers responded by reducing weekly production levels from 962 thousand barrels per day as of the end of the fourth quarter of calendar 2011 to 785 thousand barrels per day as of the end of the third quarter of calendar 2012 representing an 18.4% decrease. We believe that ethanol producers may continue to reduce production until ethanol supply and demand returns to normal market levels. This combined with 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 has been volatile during Fiscal 2012; recently reaching all-time highs in excess of $8.00 per bushel. As of November 26, 2012, the Chicago Mercantile Exchange (“CME”) near-month corn price for December, 2012 was $8.13; for March 2013 it was at $8.06 and for July 2013 it was $7.53. Corn prices have increased in response to drought conditions in the Midwestern region of the U.S. and concern that a resulting decrease in the supply of corn could lead to the rationing of corn supplies, which could cause further increases in the price of corn. The price of corn may also be impacted by reduced ethanol production levels as well as the current drought conditions and other market factors, including the reduced demand for motor fuels in the U.S. resulting from higher gasoline prices and more fuel-efficient vehicles. 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.
On August 10, 2012, the USDA decreased its original forecast of the amount of corn to be used for ethanol production during the current marketing year (2011-12) to a total of 4.32 billion bushels. The forecast is 680 million bushels less than used last year. In the August, 2012 update, the USDA also decreased the projection of U.S. corn exports for the current marketing year by .05 billion bushels. This decrease is a result of the drought in 2012.
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 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 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.
Credit and Counterparty Risks
Through our normal business activities, we are subject to significant credit and counterparty risks that arise through normal commercial sales and purchases, including forward commitments to buy and sell, and through various other over-the-counter (OTC) derivative instruments that we utilize to manage risks inherent in our business activities. We define credit and counterparty risk as a potential financial loss due to the failure of a counterparty to honor its obligations. The exposure is measured based upon several factors, including unpaid accounts receivable from counterparties and unrealized gains (losses) from OTC derivative instruments (including forward purchase and sale contracts). We actively monitor credit and counterparty risk through credit analysis (by our marketing agent). We record provisions for counterparty losses from time to time as a result of our credit and counterparty analysis.
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 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.
Summary of Critical Accounting Policies and Estimates
Note 2 to our financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. Accounting estimates are an integral part of the preparation of financial statements and are based upon management’s current judgment. We used our knowledge and experience about past events and certain future assumptions to make estimates and judgments involving matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We believe that of our significant accounting policies, the following are noteworthy because changes in these estimates or assumptions could materially affect our financial position and results of operations:
We sell ethanol and related products pursuant to marketing agreements. Revenues are recognized when the marketing company or the customers have taken title to the product, prices are fixed or determinable and collectability is reasonably assured. Our products are generally shipped FOB loading point. Our ethanol sales are handled through our ethanol agreement with Bunge. Syrup, distillers grains and solubles, and modified wet distillers grains with solubles are sold through our agreement with Bunge, which sets the price based on the market price to third parties. Marketing 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 us for the sale of ethanol and co-products are included in cost of goods sold.
| | |
| | |
| | |
| Ÿ | Investment in Commodities Contracts, Derivative Instruments and Hedging Activities |
Our operations and cash flows are subject to fluctuations due to changes in commodity prices. We are subject to market risk with respect to the price and availability of corn, our principal raw material. In general, rising corn prices can result in lower profit margins, especially if there is not a corresponding increase in the price of ethanol and our co-products. 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.
We maintain a risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by market volatility. Our specific goal is to protect ourselves from large fluctuations in commodity costs but, our hedging activities can also 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 cash cost and use of the commodity being hedged. The effects, positive or negative, on our financial statements tend to be mitigated by offsetting changes in future periods; however, these offsetting changes do not always occur, in the same amounts and can have lag times of as much as twelve months.
To minimize the risk and the volatility of commodity prices, primarily corn and ethanol, we use various derivative instruments, including forward contracts for corn, ethanol and distillers grain, as well as over-the-counter and exchange-trade futures and option contracts. We enter into derivative contracts to hedge our exposure to price risk related to forecasted corn needs and forward corn purchase contracts.
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. Contracts that meet the requirements of normal purchases or sales are documented as normal and exempted from the accounting and reporting requirements of derivative accounting. Gains and losses on contracts designated as normal purchases or normal sales contracts are not recognized until quantities are delivered or utilized in production.
Although our derivative instruments are intended to be effective economic hedges of specified risks, all of our derivatives are designated as “non-hedge derivatives” for accounting purposes. For derivative instruments that are not accounted for as hedges, the change in fair value is recorded through earnings in the period of change (commonly referred to as the “mark to market” method). The fair value of our derivatives are marked to market each period and changes in fair value are included in revenue when the contract relates to ethanol and costs of goods sold when the contract relates to corn.
By using derivatives to hedge exposures to changes in commodity prices, we have exposures on these derivatives to credit and market risk. We are exposed to credit risk that the counterparty might fail to fulfill its performance obligations under the terms of the derivative contract. We minimize our credit risk by entering into transactions with high quality counterparties, limiting the amount of financial exposure we have with each counterparty and monitoring the financial condition of our counterparties. Market risk is the risk that the value of the financial instrument might be adversely affected by a change in commodity prices. We manage market risk by incorporating monitoring parameters within our risk management strategy that limit the types of derivative instruments and derivative strategies we use, and the degree of market risk that may be undertaken by the use of derivative instruments.
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 anticipated profit margin.
Property and equipment is stated at cost. Construction in progress is comprised of costs related to constructing the plant and is depreciated upon completion of the plant. Depreciation is computed using the straight-line method over the following estimated useful lives:
| | | |
| Buildings | 40 Years | |
| Process Equipment | 10-20 Years | |
| Office Equipment | 3-7 Years | |
��
Maintenance and repairs are charged to expense as incurred; major improvements are capitalized.
Effective January 1, 2011, we increased the estimated useful life on a significant portion of our processing equipment. This change in estimate is accounted for on a prospective basis.
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 our policies, management has evaluated the plants for possible impairment based on projected future cash flows from operations. Management has determined that its projected future cash flows from operations exceed the carrying value of the plant and that no impairment existed at September 30, 2012.
Off-Balance Sheet Arrangements
We do not have any off balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Not applicable.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm
To the Board of Directors
Southwest Iowa Renewable Energy, LLC
We have audited the accompanying balance sheets of Southwest Iowa Renewable Energy, LLC as of September 30, 2012 and 2011, and the related statements of operations, members’ equity, and cash flows for years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financing reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Iowa Renewable Energy, LLC as of September 30, 2012 and 2011, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.
/s/ McGladrey, LLP
Des Moines, Iowa
December 18, 2012
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SOUTHWEST IOWA RENEWABLE ENERGY, LLC | | | | | | |
Balance Sheets - September 30, 2012 and 2011 | | | | | | |
(Dollars in thousands) | | | | | | |
| | | Year Ended | | | Year Ended |
| | | September 30, 2012 | | | September 30, 2011 |
ASSETS | | | | | | |
Current Assets | | | | | | |
Cash and cash equivalents | | $ | 6,285 | | $ | 11,007 |
Restricted cash | | | 302 | | | 301 |
Accounts receivable | | | 268 | | | 224 |
Accounts receivable, related party | | | 12,088 | | | 17,642 |
Derivative financial instruments | | | 976 | | | 553 |
Inventory | | | 12,427 | | | 11,198 |
Derivative financial instruments, related party | | | 4,013 | | | - |
Prepaid expenses and other | | | 394 | | | 1,107 |
Total current assets | | | 36,753 | | | 42,032 |
| | | | | | |
Property, Plant and Equipment | | | | | | |
Land | | | 2,064 | | | 2,064 |
Plant, building and equipment | | | 204,597 | | | 203,750 |
Office and other equipment | | | 751 | | | 742 |
| | | 207,412 | | | 206,556 |
Accumulated depreciation | | | (53,679) | | | (42,293) |
Net property and equipment | | | 153,733 | | | 164,263 |
| | | | | | |
Other Assets | | | | | | |
Financing costs, net of amortization of | | | 1,001 | | | 1,539 |
$3,202 and $2,341, respectively | | | | | | |
Other assets | | | 896 | | | - |
| | | 1,897 | | | 1,539 |
Total Assets | | $ | 192,383 | | $ | 207,834 |
| | | | | | |
LIABILITIES AND MEMBERS' EQUITY | | | | | | |
Current Liabilities | | | | | | |
Accounts payable | | $ | 1,366 | | $ | 2,090 |
Accounts payable, related parties | | | 3,937 | | | 5,239 |
Derivative financial instruments, related party | | | - | | | 2,097 |
Accrued expenses | | | 2,837 | | | 2,615 |
Accrued expenses, related parties | | | 1,657 | | | 3,832 |
Current maturities of notes payable | | | 20,001 | | | 21,237 |
Total current liabilities | | | 29,798 | | | 37,110 |
| | | | | | |
Long Term Liabilities | | | | | | |
Notes payable, less current maturities | | | 115,023 | | | 121,400 |
Other long-term liabilities | | | 500 | | | 600 |
Total long term liabilities | | | 115,523 | | | 122,000 |
Commitments and Contingencies (Note 9 and 10) | | | | | | |
| | | | | | |
Members' Equity | | | | | | |
Members' capital | | | | | | |
13,139 Units issued and outstanding | | | 76,474 | | | 76,474 |
Accumulated profit (deficit) | | | (29,412) | | | (27,750) |
Total members' equity | | | 47,062 | | | 48,724 |
Total Liabilities and Members' Equity | | $ | 192,383 | | $ | 207,834 |
| | | | | | |
See Notes to Financial Statements | | | | | | |
| | | | | | |
SOUTHWEST IOWA RENEWABLE ENERGY, LLC | | | | | | |
Statement of Operations | | | | | | |
(Dollars in thousands) | | | | | | |
| | | | | | |
| | | Year Ended | | | Year Ended |
| | | September 30, 2012 | | | September 30, 2011 |
| | | | | | |
Revenues | | $ | 362,876 | | $ | 333,089 |
Cost of Goods Sold | | | | | | |
Cost of goods sold-non hedging | | | 357,579 | | | 327,924 |
Realized & unrealized hedging (gains) | | | (7,767) | | | (6,325) |
| | | 349,812 | | | 321,599 |
| | | | | | |
Gross Margin | | | 13,064 | | | 11,490 |
| | | | | | |
General and administrative expenses | | | 4,533 | | | 4,357 |
| | | | | | |
Operating Income | | | 8,531 | | | 7,133 |
| | | | | | |
Other Income (Expense) | | | | | | |
Interest income | | | 20 | | | 18 |
Other income | | | 963 | | | 44 |
Interest expense | | | (10,176) | | | (9,902) |
| | | (9,193) | | | (9,840) |
| | | | | | |
Net (Loss) | | $ | (662) | | $ | (2,707) |
| | | | | | |
Weighted Average Units Outstanding | | | 13,139 | | | 13,139 |
Net (loss) per unit, basic & diluted | | $ | (50.35) | | $ | (206.05) |
| | | | | | |
See Notes to Financial Statements | | | | | | |
| | | | | | | | | | |
SOUTHWEST IOWA RENEWABLE ENERGY, LLC | | | | | | | | | | |
Statement of Members' Equity | | | | | | | | | | |
(Dollars in thousands) | | | | | | | | | | |
| | | Members' Capital | | | Earnings (Deficit) Accumulated | | | Total | |
| | | | | | | | | | |
Balance, 09/30/2010 | | $ | 76,474 | | $ | (25,043) | | $ | 51,431 | |
Net (loss) | | | | | | (2,707) | | | (2,707) | |
| | | | | | | | | | |
Balance, 09/30/2011 | | | 76,474 | | | (27,750) | | | 48,724 | |
Net (loss) | | | - | | | (662) | | | (662) | |
Dividends | | | - | | | (1,000) | | | (1,000) | |
| | | | | | | | | | |
Balance, 09/30/2012 | | $ | 76,474 | | $ | (29,412) | | $ | 47,062 | |
| | | | | | | | | | |
See Notes to Financial Statements | | | | | | | | | | |
| | | | | | |
SOUTHWEST IOWA RENEWABLE ENERGY, LLC | | | | | | |
Condensed Statements of Cash Flows | | | | | | |
(Dollars in thousands) | | | | | | |
| | | Year Ended | | | Year Ended |
| | | September 30, 2012 | | | September 30, 2011 |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | |
Net (loss) | | $ | (662) | | $ | (2,707) |
Adjustments to reconcile net (loss) to net | | | | | | |
cash provided by operating activities: | | | | | | |
Depreciation | | | 11,393 | | | 13,536 |
Amortization | | | 861 | | | 392 |
Loss on disposal of property | | | 11 | | | - |
Other assets | | | (896) | | | - |
Accrued interest added to long term debt | | | 3,578 | | | 3,285 |
(Increase) decrease in current assets: | | | | | | |
Accounts receivable | | | 5,510 | | | 5,526 |
Inventories | | | (1,229) | | | (3,185) |
Prepaid expenses and other | | | 510 | | | (574) |
Derivative financial instruments, related party | | | (4,013) | | | 688 |
Due from broker | | | (423) | | | 1,632 |
Decrease in other long-term liabilities | | | (100) | | | (100) |
Increase (decrease) in current liabilities: | | | | | | |
Accounts payable | | | (2,026) | | | 3,809 |
Derivative financial instruments, related party | | | (2,097) | | | 2,097 |
Accrued expenses | | | (1,953) | | | 908 |
Net cash provided by operating activities | | | 8,464 | | | 25,307 |
| | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | |
Purchase of property and equipment | | | (874) | | | (2,858) |
Increase in restricted cash | | | (1) | | | (301) |
Net cash (used in) investing activities | | | (875) | | | (3,159) |
| | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | |
Payments for financing costs | | | (120) | | | - |
Dividends paid to members | | | (1,000) | | | - |
Proceeds from notes payable | | | 18,763 | | | 13,300 |
Payments on borrowings | | | (29,954) | | | (27,874) |
Net cash (used in) financing activities | | | (12,311) | | | (14,574) |
| | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (4,722) | | | 7,574 |
| | | | | | |
CASH AND EQUIVALENTS | | | | | | |
Beginning | | | 11,007 | | | 3,433 |
Ending | | $ | 6,285 | | $ | 11,007 |
| | | | | | |
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES | | | | | | |
Use of deposit for financing fee | | $ | 203 | | $ | - |
Use of deposit for purchase of property and equipment | | | - | | | 1,142 |
| | | | | | |
SUPPLEMENTAL CASH FLOW INFORMATION | | | | | | |
Cash paid for interest | | $ | 8,057 | | $ | 5,716 |
| | | | | | |
See Notes to Financial Statements | | | | | | |
|
SOUTHWEST IOWA RENEWABLE ENERGY, LLC Notes to Condensed Financial Statements September 30, 2012 |
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. In the year ended September 30, 2012 (“Fiscal 2012”) and the year ended September 30, 2011 (“Fiscal 2011”), the Company operated at 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
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.
Cash & Cash Equivalents
The Company considers all highly liquid debt instruments purchased with a maturity of three months or less when purchased to be cash equivalents.
Restricted Cash
The Company has restricted cash used as collateral for a loan with the Iowa Department of Economic Development (“IDED”).
Financing Costs
Financing costs associated with the construction and revolving loans are recorded at cost and include expenditures directly related to securing debt financing. The Company began amortizing these costs using the effective interest method over the terms of the agreements in March 2008.
Concentration of Credit Risk
The Company’s cash balances are maintained in bank deposit accounts which at times may exceed federally-insured limits. The Company has not experienced any losses in such accounts.
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 and 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. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering customers’ financial condition, credit history and current economic conditions. As of September 30, 2012 and 2011, management had determined no allowance is 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 its 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 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 enters 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 are 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 September 30, 2012, the Company was committed to sell 7.272 million gallons of ethanol and 35,113 tons of distillers grains and solubles.
For forward corn contracts initiated prior to September 28, 2010, the Company applied the normal purchase and sales exemption under derivative accounting. However, forward corn purchase contracts initiated after September 28, 2010 are treated as derivative financial instruments. Changes in fair value of forward corn contracts, which are marked to market each period, are included in costs of goods sold. As of September 30, 2012, the Company was committed to purchasing 3.093 million bushels of corn on a forward contract basis resulting in a total commitment of $19,281,149. These forward contracts had a fair value of $23,294,154 at September 30, 2012.
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. All derivatives are designated as non-hedge derivatives and the contracts will be accounted for at fair value. Although the contracts will be effective economic hedges of specified risks, they are not designated as and accounted for as hedging instruments.
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 are included in revenue if the contracts relate to ethanol and cost of goods sold if the contracts relate to corn. During the twelve months ended September 30, 2012 and September 30, 2011, the Company recorded a combined realized and unrealized gain of $7,766,608 and $6,325,414, respectively, as a component of cost of goods sold. During the twelve months ended September 30, 2012 and 2011, the Company did not enter into any 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.
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 co-products. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This 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.
Derivatives not designated as hedging instruments along with cash held by brokers at September 30, 2012 and 2011 are as follows:
| | | |
| Balance Sheet Classification | September 30, 2012 | September 30, 2011 |
| | | |
Futures and option contracts | | | |
In gain position | | $ 806,710 | $ 695,663 |
In loss position | | (1,668,970) | (3,570,738) |
Cash held by broker | | 1,838,048 | 3,428,450 |
| Current asset | 975,788 | 553,375 |
| | | |
Forward contracts, corn, related party | Current asset | 4,013,005 | - |
| | $ 4,988,793 | $ 553,375 |
| | | |
Forward contracts, corn, related party | Current liability | $ - | $ (2,097,075) |
The net realized and unrealized gains and losses on the Company’s derivative contracts for the years ended September 30, 2012 and 2011 consist of the following:
| | | |
| | September 30, 2012 | September 30, 2011 |
| | | |
Net realized and unrealized (gains) losses related to: | | | |
Purchase contracts (corn): | | | |
Forward contracts | | $ 1,134,140 | $ (24,477,488) |
Futures and option contracts | | (8,960,637) | 18,152,074 |
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:
| 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. Effective January 1, 2011 the Company increased the estimated useful life on a significant portion of its processing equipment. This change in estimate is accounted for on a prospective basis. This change resulted in a decrease in depreciation expense, an increase to operating income, a decrease net (loss) of approximately $7.3 million and $5.4 million for Fiscal 2012 and 2011, respectively, and a decrease in (loss) per unit of $556 and $411 for Fiscal 2012 and 2011, respectively.
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. Management has determined that its projected future undiscounted cash flows from operations exceed the carrying value of the plant and that no impairment existed at September 30, 2012
Income Taxes
The Company has elected to be treated as a partnership for federal and state income tax purposes and generally does not incur income taxes. Instead, the Company’s earnings and losses are included in the income tax returns of the members. Therefore, no provision or liability for federal or state income taxes has been included in these financial statements.
Management has evaluated the Company’s tax positions under the Financial Accounting Standards Board issued guidance on accounting for uncertainty in income taxes and concluded that the Company has taken no uncertain tax positions that require adjustment to the financial statements to comply with the provisions of this guidance. With few exceptions, the Company is no longer subject to income tax examinations by the U.S. Federal, state or local authorities for the years before 2009.
Net (loss) per unit
Net (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, derivative financial instruments, accounts receivable, accounts payable and accrued expenses approximate fair value due to the short term nature of these instruments.
Reclassifications:
Certain items in Fiscal 2011 balance sheet have been reclassified to conform to Fiscal 2012 classifications. These reclassifications had no impact on net income, member’ equity or working capital.
Note 3: Inventory
Inventory is comprised of the following at:
| | | | | | |
| | | | | | |
| | | September 30, 2012 | | | September 30, 2011 |
| | | (000's) | | | (000's) |
Raw Materials - corn | | $ | 2,731 | | $ | 1,738 |
Supplies and Chemicals | | | 2,661 | | | 2,168 |
Work in Process | | | 3,225 | | | 2,026 |
Finished Goods | | | 3,810 | | | 5,266 |
Total | | $ | 12,427 | | $ | 11,198 |
| | | | | | |
Note 4: Members’ Equity
At September 30, 2012 and 2011outstanding 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 Board member. The Series B unit holders as a group have the right 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 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. 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 September 30, 2012). 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 nonfinancial covenants. As of September 30, 2012, 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, 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, the Company may draw the lesser of $15,000,000 or 75 percent of eligible accounts receivable and eligible inventory. 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 September 30, 2012. The term of the $15,000,000 revolving working capital facility renewed on March 31, 2012 and matures on March 29, 2013
As of September 30, 2012 and 2011, the outstanding balance under the Credit Agreement was $84,866,648 and $96,753,936, 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. An Excess Cash Flow payment of $21,828 for Fiscal 2012 is due and payable in four equal installments in Fiscal 2013.
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. As of September 30, 2012 and 2011, there was $33,922,334 and $31,663,730 outstanding under the Bunge Note, respectively. There was $473,162 and $425,464 of accrued interest (included in accrued expenses, related parties) due to Bunge as of September 30, 2012 and 2011, respectively.
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 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. As of September 30, 2012 and 2011, the balance outstanding was $3,750,000 and $3,000,000, respectively, under the Bunge Revolving Note.
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 September 30, 2012 and 2011, there was $11,691,666 and $10,902,885,respectively, outstanding under the ICM Term Note, respectively, and $163,068 and $146,501 of accrued interest due (included in accrued expense, related party) to ICM, respectively. Interest on the note accrues monthly and is added to the note principal on February 1st and August 1steach year.
Note 6: Notes Payable
Notes payable consists of the following:
| | | | | | |
| | | September 30, 2012 | | | September 30, 2011 |
$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. (A) | | $ | 250,000 | | $ | 280,000 |
| | | | | | |
$200,000 Note payable to IDED, a non-interest bearing obligation | | | | | | |
with monthly payments of $1,667 due through the maturity, | | | | | | |
was paid off in Fiscal 2012. | | | - | | | 8,333 |
| | | | | | |
Convertible Notes payable to unitholders, bearing interest at LIBOR | | | | | | |
plus 7.50-10.5% (8.23% at September 30, 2012); maturity on August 31, 2014. | | | 531,508 | | | - |
| | | | | | |
| | | | | | |
Note payable to affiliate Bunge, N.A., bearing interest at LIBOR plus | | | | | | |
7.50-10.5% (8.23% at September 30, 2012); maturity on August 31, 2014. | | | 33,922,334 | | | 31,663,730 |
| | | | | | |
Note payable to affiliate ICM, bearing interest at LIBOR plus | | | | | | |
7.50-10.5% (8.23% at September 30, 2012); maturity on August 31, 2014. | | | 11,691,666 | | | 10,902,885 |
| | | | | | |
Term facility payable to AgStar bearing interest at LIBOR plus | | | | | | |
4.45% with a 6.00% floor (6.00% at September 30, 2012); maturity | | | | | | |
on August 1, 2014. | | | 33,745,859 | | | 43,593,856 |
| | | | | | |
Term facility payable to AgStar bearing interest at a fixed 6%; maturity | | | | | | |
on August 1, 2014. | | | 35,245,790 | | | 39,660,080 |
| | | | | | |
Term revolver payable to AgStar bearing interest at LIBOR plus | | | | | | |
4.45% with a 6.00% floor (6.00% at September 30, 2012); 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 | | | | | | |
September 30, 2012), maturing March 29, 2013. | | | 5,875,000 | | | 3,500,000 |
| | | | | | |
Capital leases payable to AgStar bearing interest at 3.088% | | | | | | |
maturing May 15, 2013. | | | 12,256 | | | 28,701 |
| | | | | | |
Revolving line of credit payable to Bunge, bearing | | | | | | |
interest at LIBOR plus 7.50-10.5% with a floor of 3.00% | | | | | | |
(8.23% at September 30, 2012). | | | 3,750,000 | | | 3,000,000 |
| | | | | | |
| | | 135,024,413 | | | 142,637,586 |
Less Current Maturities | | | (20,001,369) | | | (21,237,680) |
| | | | | | |
Total Long Term Debt | | | 115,023,044 | | | 121,399,906 |
(A) The $300,000 IDED loan is comprised of two components under the Master Contract (the “ Master Contract”) between the Company and IDED: i) a $150,000, non interest-bearing component that requires monthly payments of $2,500, which began in March, 2011 with a final payment of $2,500 due February, 2016; and ii) a $150,000 forgivable loan. The Company has a $300,000 letter of credit with regard to the $300,000 loan (secured by a time deposit account in the same amount) to collateralize the loan. The note under the Master Contract is collateralized by substantially all of the Company’s assets, subordinate to the Credit Agreement.
Approximate aggregate maturities of notes payable as of September 30, 2012 are as follows:
| | | |
2013 | | | 20,001,369 |
| | | |
2014 | | | 114,833,044 |
| | | |
2015 | | | 30,000 |
| | | |
2016 | | | 160,000 |
| | | |
Total | | | 135,024,413 |
Note 7: 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 September 30, 2012 and 2011, categorized by the level of the valuation inputs within the fair value hierarchy:
| | | | | | | | | | |
| | | 2012 |
| | | | Level 1 | | | Level 2 | | | Level 3 |
Assets: | | | | | | | | | | |
Derivative financial instruments | | | $ | 806,710 | | $ | 4,013,005 | | $ | - |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
Derivative financial instruments | | | | 1,668,970 | | | - | | | - |
| | | | | | | | | | |
| | | | | | | | | | |
| | | 2011 |
| | | | Level 1 | | | Level 2 | | | Level 3 |
Assets: | | | | | | | | | | |
Derivative financial instruments | | | $ | 695,663 | | $ | - | | $ | - |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
Derivative financial instruments | | | | 3,570,738 | | | 2,097,075 | | | - |
Certain financial assets and liabilities are measured at fair value on a non-recurring basis; that is the instruments are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances, for example, when there is evidence of impairment.
Note 8: Incentive Compensation
The Company has an equity incentive plan which provides that the Board of Directors may make awards of equity appreciation units (“EAU”) and equity participation units (“EPU”) and to employees from time to time, subject to vesting provisions as determined for each award. The EPUs are valued at fair-value. The Company had 14.55 unvested EPUs outstanding under this plan as of September 30, 2012, which will vest three years from the date of the award. During the twelve months ended September 30, 2012 and 2011, the Company recorded compensation expense related to this plan of approximately $12,000 and $5,000, respectively. As of September 30, 2012 and 2011, the Company had a liability of approximately $17,000 and $5,000, respectively, outstanding as deferred compensation and has approximately $36,950 to be recognized as future compensation expense over the weighted average vesting period of approximately three years. The amount to be recognized in future years as compensation expense is estimated based on book value of the Company. The liability under the plan is recorded at fair market value on the balance sheet based on the book value of the Company’s equity units as of September 30, 2012.
Note 9: Related Party Transactions
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.
In December, 2008, the Company and Bunge entered into other various agreements. Under a Lease Agreement (the “Lease Agreement”), the Company leased from Bunge a grain elevator located in Council Bluffs, Iowa, for approximately $67,000 per month. The lease was terminated on May 1, 2011. Expenses for the twelve months ended September 30, 2012 and 2011 were $0 and $467,063, respectively, under the Lease Agreement.
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. Bunge and the Company were parties to a prior ethanol agreement dated December 15, 2008 (the “Prior Ethanol Agreement”) which was set to expire in August 2012. Prior to the expiration of the Prior Ethanol Agreement, the Company and Bunge agreed to new terms under the Ethanol Agreement and to replace the Prior Ethanol Agreement with the Ethanol Agreement which commenced January 1, 2012 and runs through August 31, 2014. The Ethanol Agreement will automatically renew for successive three-year terms 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 $1,717,529 and $1,820,836 during the twelve months ended September 30, 2012 and 2011, 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 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 twelve months ended September 30, 2012 and 2011 were $300,000.
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 twelve months ended September 30, 2012 and September 30, 2011 were $5,414,296 and $4,855,718, respectively.
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. The Company expensed $2,258,148 and $1,725,423 in fees during Fiscal 2012 and Fiscal 2011
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 “Bunge 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.
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 procured by Bunge for the Company 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 ten years, subject to earlier termination upon specified events. The annual expenses were $1,310,366 and $1,203,342 for the fiscal years ended September 30, 2012 and 2011, 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 twelve months ended September 30, 2012 and 2011 were $201,068 and $87,870, 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 September 30, 2012, the Company had paid $2,796,142 under the Tricanter Agreement with no amounts remaining due.
The Company and ICM have also entered into a convertible term note. See Note 5 Revolving Loan/Credit Agreements, for the terms of this financing arrangement.
Note 10: Commitments
The Company has entered into a steam contract with an unrelated party under which the vendor agreed to provide the steam required by the Company, up to 475,000 pounds per hour. The Company agreed to pay a net energy rate for all steam provided under the contract as well as a monthly demand charge. The net energy rate is set for the first three years then adjusted each year beginning on the third anniversary date. The steam contract will remain in effect until January 1, 2019. Expenses under this agreement for the year ended September 30, 2012 and 2011 were $5,678,358 and $10,984,798, respectively.
In April, 2008 the Company entered into a Firm Throughput Service Agreement with a natural gas supplier, an unrelated party, under which the vendor agreed to provide the gas required by the Company, up to 900 Dth per day. The Company agreed to pay the maximum reservation and commodity rates as provided under the vendor’s FERC Gas Tariff as revised from time to time, as well as other additional charges. The agreement specifies an in-service date of October 1, 2008, and the term of the agreement is seven years. Expenses for the years ended September 30, 2012 and 2011 were $40,217 and $40,217, respectively.
The Company purchased 74,977 and 70,608 megawatts of electricity for the years ended September 30, 2012 and 2011, respectively, from an unrelated party, MidAmerica Energy Company (“MidAm”) under an Electric Service Contract (“Electric Contract”) dated December 15, 2006. Under the Electric Contract, the Company is allowed to install a standby generator, which would operate in the event MidAm is unable to provide the Company with electricity.
In the Electric Contract, the Company agreed to own and operate a 13 kV switchgear with metering bay, all distribution transformers, and all 13 kV and low voltage cable on the Company’s side of the switchgear. The Company agreed to pay (i) a service charge of $200 per meter, (ii) a demand charge of $3.38 in the summer and $2.89 in the winter (iii) a reactive demand charge of $0.49/kVAR of reactive demand in excess of 50% of billing demand, (iv) an energy charge ranging from $0.03647 to $0.01837 per kilowatt hour, depending on the amount of usage and season, (v) tax adjustments, (vi) AEP and energy efficiency cost recovery adjustments, and (vii) a CNS capital additions tracker. These rates only apply to the primary voltage electric service provided under the Electric Contract. The electric service continued at these prices for 60 months, but terminated on June 30, 2012. Subsequently, the Company elected to be charged under one of MidAm’s electric tariffs.
In January, 2007, the Company entered into an agreement with an unrelated party, Iowa Interstate Railroad, LTD, to provide the transportation of the Company’s commodities from Council Bluffs, Iowa to an agreed upon customer location. The agreement had an initial term of five years and then automatically renews for additional one year periods unless cancelled by either party. The Company agreed to pay a mutually agreed upon rate per car. Expenses for the year ended September 30, 2012 and 2011 were approximately $845,777 and $574,058, respectively, of which approximately $58,272 and $45,850 was included in accounts payable for September 30, 2012 and 2011, respectively.
The Company entered into a natural gas supply agreement with Encore Energy. The agreement is month to month and may be cancelled upon 30 days written notice. The Company has incurred expenses of $6,626,113 and $3,358,519, for the year ended September 30, 2012 and 2011, respectively.
The Company leases certain equipment, vehicles, and operating facilities under non-cancellable operating leases that expire on various dates shown thereafter below through 2019. The future minimum lease payments required under these leases are $5,334,419 in 2013, $5,398,689 in 2014, $5,398,107 in 2015, $5,398,107 in 2016, $5,398,107 in 2017 and $7,787,529 thereafter. Rent expense related to operating leases for the years ended September 30, 2012 and 2011 was $5,330,493 and $5,633,982, respectively.
Note 11: Major Customers
The Company is party to the Ethanol Agreement, the Grain Feedstock Agreement, and the Corn Oil Agreement with Bunge for the exclusive marketing, selling, and distributing of all of the ethanol, distillers grains, and corn oil produced by the Company. The Company has expensed $4,176,745 and $3,634,129 in marketing fees under this agreement for the twelve months ended September 30, 2012 and 2011, respectively. Revenues with this customer were $352,849,830 and $327,849,110, respectively, for the twelve months ended September 30, 2012 and 2011. Trade accounts receivable due from this customer were $12,088,093 and $17,642,245 September 30, 2012 and 2011, respectively.
Note 12: Contingent Liability
On March 24, 2011, the Company received a letter from the Environmental Protection Agency (the “EPA”) alleging violations of environmental regulations which could lead to the imposition of a civil penalty. The Company had a reserve as of October 31, 2011 of $50,000 for this matter; however, the violations alleged in the letter have been addressed and the Company is aware of no ongoing violations with respect to the matters addressed in the letter.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
There are no items to report.
Item 9A. 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 amended, the “Exchange Act”), as of September 30, 2012. 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 September 30, 2012 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 September 30, 2012. 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 September 30, 2012, 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.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The Directors and/or officers listed below under “Independent Directors & Officers” meet the “independent director” standards applicable to companies listed on the NASDAQ Capital Market (though our Units are not listed on any exchange or quotation system). Contrariwise, those Directors listed below under “Interested Directors” do not meet the “independent director” standards applicable to companies listed on the NASDAQ Capital Market. None of the Directors listed below have served on the board of directors of any other company having a class of securities registered under Section 12 of the Exchange Act or subject to the requirements of Section 15(d) of the Exchange Act, nor have any of our Directors served as directors of an investment company registered under the Investment Company Act of 1940.
Our Board of Directors
Our Board of Directors (“Board”) consists of seven Directors currently comprised of four Series A Directors, two Series B Directors and one Series C Director. Our four Series A Directors are nominated by the Board, following consideration by the Board Nominating Committee, and then elected by our Series A members. Under the Operating Agreement, the independent Directors’ terms are staggered such that one Director will be up for election every year. The two Series B directors and the Series C Director are appointed by Bunge and ICM, respectively, under the terms of our Operating Agreement. Each Series B Director and Series C Director will hold office indefinitely until a successor is appointed by Bunge or ICM, respectively, or until the earlier death, resignation, removal or disqualification of such Director.
Director Qualifications
The table below discusses the experiences, qualifications and skills of each of our Directors serving as of December 10, 2012. We believe all of our Directors are individuals of high character and integrity, are able to work well with others, and have sufficient time to devote to the affairs of our company.
| |
Current Director | Experiences, Qualifications and Skills |
| |
Series A Directors | Elected by Series A Unit Holders |
Theodore V. Bauer | Mr. Bauer’s background as a farmer and agribusinessman, as well as his past service on a number of civic and corporate boards, including the Iowa Quality Producers Alliance, an organization devoted to value-added agriculture and rural economic development, are important factors qualifying Mr. Bauer as one of the Board’s Series A independent directors. |
Michael K. Guttau | Mr. Guttau was recruited to serve as an independent Series A Board member and as the Audit Committee Financial expert given his background and experience as a banking executive and board member of a number of banking and civic organizations. Mr. Guttau’s experience includes more than 30 years as a rural banker, providing a long-term view of agriculture and ag-related businesses. |
Hubert M. Houser | Senator Houser brings to the Board more than 30 years of experience as a member of the Iowa legislature and the county board in which the Company is located. During his career, Senator Houser has developed a reputation as a leader in rural economic development. He provides significant assistance to the Board in the Company’s interaction with all levels of local and state government and also provides a long-term view of the further development of SIRE’s site and business. |
Karol D. King | Mr. King, the Board’s Chairman and an independent Director elected by Series A members, has a long career as a farmer and owner of a number of ag-related business. In addition, Mr. King has held leadership positions in numerous local and national ag producer groups, in particular the Iowa and national corn growers associations. In these capacities he has participated in the development of the ethanol industry. |
Series B Directors | Appointed by Bunge |
C. Bailey Ragan1 | Mr. Ragan has more than 30 years of agribusiness experience with Bunge North America as well as his past service as a Series B director from 2006 until July 2009. At Bunge, Mr. Ragan has managed soy bean crush facilities as well as grain operations for one of the largest agribusiness companies in the United States. Mr. Ragan’s responsibilities include commodity risk management which is a critical function of SIRE’s Board and to which Mr. Ragan brings his substantial experience. |
Tom J. Schmitt | With more than 32 years of agribusiness experience with Bunge, and in his capacity as Manager of Western Region, Bunge North America Oilseed Processing, Mr. Schmitt brings extensive experience to the Board in oversight of agribusiness facilities. Mr. Schmitt’s current responsibilities include management of the Bunge soy bean crush facility in Council Bluff’s, located near SIRE’s plant. This Bunge facility has an annual crush capacity of approximately 77 million bushels and is the largest soy bean crush facility in the United States |
Series C Directors | Appointed by ICM |
| |
Gregory P. Krissek | In his capacity as Director of Government Affairs for ICM, Mr. Krissek is intensely involved in public biofuels issues at the local, state and national level. In addition to bringing this insight to the Board, in addition to service on the Company’s Board, Mr. Krissek serves on the boards of six private ethanol companies and brings a broad view of ethanol plant operations to the Company. |
1 Bunge appointed Mr. Ragan as one of our Series B Directors effective November 20, 2012.
Former Class B Director
Eric L. Hakmiller served as a Series B Director from July 2009 until his resignation in November 20, 2012. During his tenure as a Series B Director, Mr. Hakmiller served as Vice-President and General Manager, Bunge Biofuels, Bunge North America. Bunge Biofuels is involved in sourcing and supplying corn, selling DDGS in both domestic and export markets, selling biodiesel and marketing and trading ethanol. Bunge Biofuels also manages the risk of these volatile commodities to decrease market risk both for its own account and its marketing partners. Mr. Hakmiller received a Bachelor’s degree in economics from the University of Maine and a graduate degree from Loyola Marymount University.
Current Independent Directors & Officers
| | | |
Name and Age | Position(s) Held with the Company | Term of Office and Length of Time Served | Principal Occupation(s) During Past 5 Years |
| | | |
Karol D. King, 65 | Series A Director and Chairman | Term expires 2013, Director since November, 2006 | Corn, popcorn and soybean farmer near Mondamin, Iowa, since 1967; President, King Agri Sales, Inc. (marketer of chemicals, fertilizer and equipment) since 1995; President, Kelly Lane Trucking, LLC, since 2007. Mr. King attended Iowa State University and has served on the Harrison County Farm Bureau Board, the Iowa Corn Growers Board, the Iowa Corn Promotion Board, the US Feed Grains Council Board, the National Gasohol Commission, and the National Corn Growers Association Board. |
Theodore V. Bauer, 60 | Series A Director, Secretary and Treasurer | Term expires 2016, Director since March 2005; Officer since November 2006 | Director, Secretary and Treasurer (since 2005) of the Company; Owner and operator of a farming operation and hunting preserve near Audubon, Iowa, since 1977; Co-Founder, and from 2005 to 2007, Director, Templeton Rye Spirits LLC; Director, Iowa Quality Producers Alliance, since 2003; Vice President, West Central Iowa Rural Water, from 2002 to 2007. Mr. Bauer has an Ag Business degree from Iowa State University and is a graduate of the Texas A&M TEPAP program. |
Hubert M. Houser, 70 | Series A Director | Term expires 2014, Director since 2005 | Lifetime owner of farm and cow-calf operation located near Carson, Iowa. Mr. Houser has served in the Iowa Legislature since 1993, first in the House of Representatives and currently in the Senate. Mr. Houser also served on the Pottawattamie County Board of Supervisors from 1979 to 1992, director of the Riverbend Industrial Park, and was a founder of the Iowa Western Development Association and Golden Hills RC&D. |
Michael K. Guttau, 66 | Series A Director | Term expires 2015, Director since 2007 | Council of Federal Home Loan Banks, Washington, D.C.: Chairman from 2008 to 2009; Federal Home Loan Bank of Des Moines: Chairman 2008-2012, Vice Chairman from 2004 to 2007, Chairman of Audit Committee from 2004 to 2006 and Chairman of Risk Management Committee 2007; since 1972, various positions with Treynor State Bank, currently CEO and Chairman of the Board; Superintendent of Banking, Iowa Division of Banking, from 1995 to 1999; Director, Iowa Bankers Association, Iowa Bankers Mortgage Corporation, Iowa Student Loan Liquidity Corp., Iowa Business Development Finance Corp. and Iowa Seed Capital Liquidation Corp.; President, Southwest Iowa Bank Administration Institute; Past Chairman, ABA Community Bankers from 1991 to 1992. Mr. Guttau received his B.S., Farm Operation, from Iowa State University in 1969 and completed numerous U.S. Army education programs from 1969 to 1978. Mr. Guttau is the 2010 recipient of the James Leach Bank Leadership Award. |
Interested Directors
| | | |
Name and Age | Position(s) Held with the Company | Term of Office† and Length of Time Served | Principal Occupation(s) During Past 5 Years |
| | | |
Tom J. Schmitt, 62‡ | Series B Director | Since July 17, 2009 | Manager, Western Region, Bunge North America Oilseed Processing. Mr. Schmitt has worked with Bunge over thirty-two years. Mr. Schmitt received a Bachelor’s degree in business administration from St. Ambrose University. |
C. Bailey Ragan, 58‡ | Series B Director and Vice Chairman | Since November 20, 2012 | Vice-President, Grains, Biofuels and Fertilizer, Bunge North America since 2011. Mr. Ragan has worked with Bunge for thirty years. Mr. Ragan joined Bunge in 1981 as procurement manager at the soybean processing facility in Decatur, Ala. when Bunge purchased the facility. He served as a commercial manager of the facility starting in 1983. In 1998 he assumed responsibility for Bunge’s soybean crushing facilities in the South Central region. From 2002 through 2011, Mr. Ragan served in various positions, including vice president and general manager, of Bunge’s grain operations. |
Gregory P. Krissek, 50‡ | Series C Director | Since November 1, 2006 | Director of Government Affairs, ICM, Inc., since 2006; Director of Marketing and Governmental Affairs, United Bio Energy, from 2003 to 2006; Chairman, National Ethanol Vehicle Coalition, 2007; Secretary-Treasurer of the Board, Ethanol Promotion and Information Council since 2004, President since June 2008; director, Kansas Association of Ethanol Processors since 2004; Kansas Energy Council, since 2004 prior Director of Operations, Kansas Corn Commission; Assistant Secretary, Kansas Department of Agriculture, 1997 to 2000. |
† The Interested Directors’ terms do not have a specified number of years, as these directors are nominated by the
Series B Member and the Series C Member, as discussed further below under Items 11 and 13.
‡ The information provided below under Item 13, “Certain Relationships and Related Transactions, and Director
Independence,” respecting the election of Messrs. Krissek, Schmitt, and Ragan as Directors, is incorporated into
this Item 10 by reference.
Executive Officers and Key Employees
Name and Age | Position(s) Held with the Company | Length of Time Served | Principal Occupation(s) During Past 5 Years |
| | | |
Brian T. Cahill, 59 | President and Chief Executive Officer | Since September, 2009 | Executive Vice President, Distillery Innovations Segment, MGP Ingredients, Inc. (“MGP”) (a public company, which provides services in the development, production and marketing of naturally-derived specialty ingredients and alcohol products) from 2007 to 2008; CFO/Vice President of Finance and Administration, MGP, from 2002 to 2007; General Manager, MGP, from 1992 to 2002. Mr. Cahill received a Bachelor of Science in Accounting from Bradley University and is a Certified Public Accountant. |
Brett L. Frevert, 50 | Chief Financial Officer | Since June, 2012 | Managing Director of CFO Systems, LLC (“CFO Systems”), which he founded, since 2004. During that time he has served as CFO of several Midwestern companies, including SEC registrants and private companies, including ethanol and other renewable fuels companies. Prior to founding CFO Systems, Mr. Frevert was Chief Financial Officer of a regional real estate firm and also served as Interim Chief Financial Officer of First Data Europe. Mr. Frevert began his career with Deloitte & Touche, serving primarily SEC-registered clients in the food and insurance industries. . |
Dan D. Wych, 36 | Plant Manager | Since April, 2008 | Operations/Fermentation Coordinator, U.S. Bio Energy/VerSun Energy (a public company which produces ethanol and co-products from corn) from 2006 to 2008; Plant Manager, United Bio Energy (a company that provides services for ethanol plants) in 2006; Production Manager, Little Sioux Corn Processors (a company which produces ethanol and co-products from corn) from 2005 to 2006; Operations/Lab/Safety Manager, Quad County Corn Processors (a company which produces ethanol and co-products from corn) from 2000 to 2005. Mr. Wych attended Iowa Lakes Community College and completed over 60+ credit hours within their Associated Arts Program |
Former Executive Officer
Karen L. Kroyman served as our Controller and principal financial officer from June 2009 through June 2012. On June 18, 2012, we entered into a Separation Agreement and Release of All Claims with Ms. Kroymann, its controller and Principal Financial Officer (the “Separation Agreement”). Pursuant to the Separation Agreement, Ms. Kroymann received severance compensation from the Company for a period of twelve weeks and she is subject to certain confidentiality obligations.
Code of Ethics
The Company adopted a code of ethics that applies to its Directors, executive officers and employees (including our principal executive officer, principal financial officer, controller and senior financial officers) effective January 16, 2009. Our Board amended the Code of Ethics on October 19, 2012. The code of ethics is available in the investor relations section of our website at www.sireethanol.com. We will disclose amendments to, or waivers of, certain provisions of our code of ethics relating to our principal executive officer, principal financial officer, controller or persons performing similar functions on our website promptly following the adoption of any such amendment or waiver.
Audit Committee
We have a separately-designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act, which operates under a written charter (the “Audit Committee Charter”)and currently consists of Michael K. Guttau (Chair), Theodore V. Bauer and Karol D. King. All of the members of the Audit Committee meet the “independent director” standards applicable to companies listed on the NASDAQ Capital Market (though our Units are not listed on any exchange or quotation system). The Board has determined that Mr. Guttau is an “audit committee financial expert” as that term is defined in Item 401(h) of Regulation S-K under the Exchange Act. Among other things, the Audit Committee has the authority for appointing and supervising our independent registered public accounting firm and is primarily responsible for approving the services performed by the our independent registered public accounting firm and for reviewing and evaluating the our accounting principles and system of internal accounting controls. A copy of the Audit Committee charter is available on our website at www.sireethanol.com at “Investor Relations”. The Audit Committee held four meetings in Fiscal 2012.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act and the rules of the SEC require our Directors, certain officers and beneficial owners of more than 10% of our outstanding Series A Units to file reports of their ownership and changes in ownership of our Series A Units with the SEC. Company employees and advisors generally prepare these reports on behalf of our Directors and officers on the basis of information obtained from them and review the forms submitted to us by our non-employee Directors and beneficial owners of more than 10% of the Series A Units. Based on such information, we believe that all reports required by Section 16(a) of the Exchange Act to be filed by our Directors, officers and beneficial owners of more than 10% of the Series A Units during or with respect to Fiscal 2012 were filed on time.
Item 11. Executive Compensation.
Governance / Compensation Committee
The Governance / Compensation Committee (the “Governance Committee”) operates under a written charter, which the Governance Committee approved on February 15, 2007, and which was adopted by the Board of Directors on February 16, 2007 (the “Governance Charter”). The Governance Charter is available on the Company’s website www.sireethanol.com in the investor relations section. The Governance Charter provides that the Governance Committee will annually review and approve our compensation program for our Directors, officers and managers. The Governance Charter does not exclude from the Governance Committee’s membership Directors who also serve as officers of the Board or Interested Directors. Presently, the Governance Committee’s membership consists of Messrs. Schmitt (Chair), Bauer, and King. The Governance Charter provides that the Governance Committee may form and delegate its responsibilities to subcommittees, and the Governance Charter does not contemplate (nor does it prohibit) the use of compensation consultants to assist the Governance Committee in its determination of Director, officer and managers’ compensation.
Compensation of Executive Officers
In June 2010, we adopted an Equity Incentive Plan (the “Plan”). The purpose of the Plan is to allow any officer or employee of the Company to share in the Company’s value through the issuance, from time to time, of equity participation units (“Equity Participation Units”) and/or unit appreciation rights (“Unit Appreciation Right”) (as further described immediately below in “Long-Term Incentive Compensation”). The Governance Committee is responsible for designing, reviewing and overseeing the administration of the Plan. Subject to the terms of the Plan and the individual award agreement, the Governance Committee recommended and the board approved the award of 9.44 Equity Participation Units to Mr. Cahill on November 21, 2011. Mr. Cahill’s award will vest in full on November 21, 2014.
Pursuant to the Governance Charter, the Governance Committee also approves the compensation terms for our executive officers approves all adjustments to the compensation terms. During Fiscal 2010, the Governance Committee engaged an independent compensation consultant (the “Consultant”) to evaluate the compensation of its executive officers in relation to other executive officers in comparable positions in the industry.
Additionally, during Fiscal 2010, the Governance Committee met with the Consultant to develop a company-wide compensation philosophy based on comparable market data and establishment of a management evaluation process. Our compensation philosophy provides that the compensation of our senior executives is designed to achieve the following objectives: (i) align the interests of the executive officers and our Unit holders; (ii) attract, retain and motivate high caliber executive officers; and (iii) pay for performance by linking a significant amount of executive compensation to individual contribution to selected metrics of our business plan. The following are the main elements of compensation under our agreements with our two senior officers.
| ● | Base Salary : A portion of annual cash compensation is paid as base salary to provide a level of security and stability. |
| | |
| ● | Annual Cash Incentive : We expect that a significant portion of the annual cash compensation paid to the executive officers will be directly related to the achievement of individual performance goals and contributions. Awards were available for 2012 and were paid to employees in November 2012. |
| ● | Long-Term Incentive Compensation : As mentioned above, on June 30, 2010 our Board of Directors adopted the Plan for the purpose of attracting and retaining key personnel. The Plan is designed to allow Participants, who consist of any officer or employee, to share in our value through the issuance of Equity Participation Units and/or Unit Appreciation Rights. Each award will be granted pursuant to an individual award agreement, which will set forth the number of units or rights granted, the book value of our Series A Units as of the grant date for purposes of valuing each Equity Participation Unit or Unit Appreciation Right, the fiscal year for which the Equity Participation Unit or Unit Appreciation Right is granted, and any In-Service Payment Date (as defined in the Plan). All awards will be recommended by our Governance Committee and then approved by the Board of Directors. |
| ● | Retirement and Welfare Benefits : We sponsor both a standard 401(k) and Roth 401(k) plan. To be eligible to participate, a new hire is eligible to participate the first of the month after their start date. While eligible employees are given an option to enroll, those who do not choose either “yes” or “no” are automatically enrolled in the standard 401(k) plan at 3% withholding. Under the program, we match the first 3%, and ½ of the next 2%, of the employee’s contributions. Each participant picks his or her own investment strategy—either the planned grouping of investments or individually selected investments. We have implemented a basic benefits plan for all full time employees, including medical, dental, life insurance and disability coverage. |
Agreements with Our Executive Officers
CEO Employment Agreement
On August 27, 2009, we entered into a letter agreement with Brian T. Cahill which summarizes the basic terms of his employment (the “CEO Employment Agreement”). Pursuant to the terms of the CEO Employment Agreement, Mr. Cahill’s initially annual base salary was $180,000 with future salary increases based on both Mr. Cahill’s individual performance and the Company’s performance and will be determined in accordance with the Board compensation policy. Mr. Cahill’s current annual base salary is $196,000. The CEO Employment Agreement also provides that Mr. Cahill is eligible to participate in our short-term and long-term incentive programs and provides Mr. Cahill with the use of a company car.
CFO Systems Letter Agreement
Effective June 22, 2012, we entered into a letter agreement with CFO Systems and Brett L. Frevert. Under the letter agreement CFO Systems will provide financial and consulting services to us at rates of $75 to $150 per hour depending on the level of expertise involved. The services will include providing Chief Financial Officer duties and other financial and accounting expertise on a time share basis. In connection with the letter agreement, Mr. Frevert agreed to serve as our Chief Financial Officer. We were charged $104,275 for the services provided by CFO Systems during 2012, which included $28,425 for Mr. Frevert's services and $75,850 for Controller and other professionals' services.
Separation Agreement
We entered into the Separation Agreement with Karen L. Kroymann, our former Controller and principal financial officer in connection with the termination of her employment with the Company in June 2012. See the section entitled “Former Executive Officer” under Item 10 above for additional information on the terms of this Separation Agreement.
Summary Compensation Table
The following table provides all compensation paid to or earned by our executive officers in Fiscal 2012 and 2011. In addition, the table below sets forth the compensation for Karen L. Kroymann, a former executive officer, who served as our Controller and principal financial officer until June 18, 2012.
| | | | | | | | | | | | |
Name and Principal Position | | Fiscal Year | | Salary ($) | | Bonus ($) | | Stock Awards1 ($) | | All Other Income | | Total ($) |
| | | | | | | | | | | | |
Brian T. Cahill, President and CEO | | 2012 | | $ 194,269 | | $ 40,000 | | $ 35,000 | | | | $ 269,269 |
| | | | | | | | | | | | |
| | 2011 | | $ 187,897 | | $ 45,000 | | $ 20,001 | | | | $ 252,898 |
| | | | | | | | | | | | |
Brett L. Frevert, Chief Financial Officer2 | | 2012 | | | | | | | | $ 28,425 | | $ 28,425 |
| | | | | | | | | | | | |
Karen L. Kroymann, Controller | | 2012 | | $ 101,895 | | $ 8,240 | | $ 0 | | | | $ 110,135 |
| | | | | | | | | | | | |
| | 2011 | | $ 101,694 | | $ 6,147 | | $ 0 | | | | $ 107,841 |
Mr. Cahill was awarded 5.11 Equity Participation Units on December 17, 2010 (Fiscal 2011) valued at $3,914 per unit, the book value of our Units, or $20,001 in the aggregate, as of the grant date and 9.44 Equity Participation Units on November 21, 2011 (Fiscal 2012) valued at $3,708.33 per unit, the book value of our Units, or $35,000 in the aggregate, as of the grant date. No portion of the Equity Participation Units vest until the third anniversary of the grant date, subject to certain events which may result in accelerated vesting.
| 1 | Mr. Cahill receives no benefit from the Equity Participation Units until they vest and the amount shown does not correspond to the actual value that will be recognized by Mr. Cahill. As described in footnote 8 to the Company’s audited financial statements for the year ended September 30, 2012, the Equity Participation Units are valued at book value. The grant date fair value included in the Stock Awards column for the Equity Participation Units is based upon the probable outcome of the performance conditions as required by FASB ASC Topic 718 and assuming Mr. Cahill remains at the company for the required three years. |
| 2 | Mr. Frevert did not begin serving as our Chief Financial Officer until June 2012; therefore, compensation information for Fiscal 2012 reflects less than full-year amounts. |
Outstanding Equity Awards at Fiscal 2012 Year-End
The following table provides certain information concerning outstanding equity awards held by our executive officers as of September 30, 2012
| | | | | | | | |
Name and Principal Position | | Date Granted | | This Will Vest | | Number of Unvested Units | | Market Value of Unvested Units |
| | | | | | | | |
Brian T. Cahill, President and CEO | | December 17, 2010 | | December 17, 2013 | | 5.11 | | $ 18,950 |
| | | | | | | | |
| | November 24, 2011 | | November 24, 2014 | | 9.44 | | $ 35,000 |
As mentioned above, Mr. Cahill was awarded 5.11 Equity Participation Units under the Plan of which 5.11 units will vest on December 17, 2013 and 9.44 units will vest on November 24, 2014. Mr. Cahill receives no benefit from any of the Equity Participation Units until such time they are vested in 2013 and 2014. The Equity Participation Units awarded to Mr. Cahill were valued at $3,708 per unit as of September 30, 2012 for an aggregate award of $53,950.
Compensation of Directors
We do not provide our Directors with any equity or equity option awards, nor any non-equity incentive payments or deferred compensation. Similarly, we do not provide our Directors with any other perquisites, “gross-ups,” defined contribution plans, consulting fees, life insurance premium payments or otherwise. Following recommendation by the Governance Committee and subsequent approval by the Board on March 18, 2011, we pay our Directors the following amounts (collectively, the “Compensation Policy”): (i) each Director receives an annual retainer of $12,000, (ii) each Director receives $1,000 per Board meeting attended (whether in person or telephonic), provided that the foregoing amounts in (i) – (ii) shall not exceed $24,000 per Director in any calendar year. Additionally, the following amounts are paid to Directors for specified services: (i) the Chairman of the Board is paid $7,500 per year, (ii) the Chairman of the Audit Committee and Audit Committee Financial Expert is paid $5,000 per year, (iii) the Chairmen of all other Committees are paid $2,500 per year, and (iv) the Secretary of the Board is paid $2,500 per year.
Independent Directors
The following table lists the compensation we paid in Fiscal 2012 to our Directors who are considered “independent” under standards applicable to companies listed on the NASDAQ Capital Market (though the Company’s Units are not listed on any exchange or quotation system) (the “Independent Directors”).
| | | | | | | | |
Name | | Fee Earned or Paid in Cash | | All Other Compensation | | Equity or Non-Equity Incentives | | Total |
| | | | | | | | |
Theodore V. Bauer | | $ 26,500 | | $ 0 | | $ 0 | | $ 26,500 |
Hubert M. Houser | | $ 26,500 | | $ 0 | | $ 0 | | $ 26,500 |
Karol D. King | | $ 31,500 | | $ 0 | | $ 0 | | $ 31,500 |
Michael K. Guttau | | $ 27,000 | | $ 0 | | $ 0 | | $ 27,000 |
Interested Directors
The following table lists the compensation we paid in Fiscal 2012 to our Directors who are not considered “independent” under standards applicable to companies listed on the NASDAQ Capital Market (though our Units are not listed on any exchange or quotation system) (the “Interested Directors”).
| | | | | | | | |
Name | | Fee Earned or Paid in Cash | | All Other Compensation | | Equity or Non-Equity Incentives | | Total |
| | | | | | | | |
Eric L. Hakmiller1 | | $ 25,500 | | $ 0 | | $ 0 | | $ 25,500 |
Tom J. Schmitt | | $ 24,500 | | $ 0 | | $ 0 | | $ 24,500 |
Gregory P. Krissek | | $ 22,000 | | $ 0 | | $ 0 | | $ 22,000 |
| | | | | | | | |
| | | | | | | | |
† The Directors fees payable to the Interested Directors are paid directly to their corporate employers at such Directors’ request, and the Interested Directors do not receive any compensation from the Company for their service as Directors.
1 Mr. Hakmiller resigned as a Director effective November 20, 2012.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Member Matters.
As of September 30, 2012, there were 8,805 Series A Units, 3,334 Series B Units, and 1,000 Series C Units issued and outstanding. The following table sets forth certain information as of September 30, 2012, with respect to the Unit ownership of: (i) those persons or groups (as that term is used in Section 13(d)(3) of the Exchange Act) who beneficially own more than 5% of any Series of Units, (ii) each Director of the Company, and (iii) all officers and Directors of the Company as a group as well as one former executive officer of the Company. The address of those in the following table is 10868 189th Street, Council Bluffs, Iowa 51503. Except as noted below, the persons listed below possess sole voting and investment power over their respective Units. The following does not reflect any Units which may be issued to Bunge and ICM, respectively, under the terms of the convertible debt owed to them.
| | | |
Title of Class | Name of Beneficial Owner | Amount and Nature of Beneficial Ownership | Percent of Class |
| | | |
Directors and Executive Officers | | | |
Series A | Theodore V. Bauer | 36 Units 1 | 0.41% |
Series A | Hubert M. Houser | 54 Units 2 | 0.61% |
Series A | Karol D. King | 29 Units 3 | 0.33% |
Series A | Michael K. Guttau | 12 Units 4 | 0.14% |
-- | Brian T. Cahill | -0- | -- |
| Karen L. Kroymann5 | -0- | -- |
| Brett L. Frevert | -0- | -- |
-- | Eric L. Hakmiller6 | -0- | -- |
-- | Tom J. Schmitt | -0- | -- |
-- | Gregory P. Krissek | -0- | -- |
| | | |
Series A | All Officers and Directors as a Group | 131 Units | 1.49% |
|
|
Other Members |
Series B | Bunge North America, Inc. | 3334 Units | 100% |
Series C | ICM, Inc. | 1000 Units | 100% |
Series A | ICM Inc. | 18 Units | 0.20% |
| | | |
____________________________________
1 These Series A Units are owned jointly by Mr. Bauer and his spouse.
2 These Series A Units are owned jointly by Mr. Houser and his spouse.
3 These Series A Units are owned jointly by Mr. King and his spouse.
4 These Series A Units are owned jointly by Mr. Guttau and his spouse.
5 Mr. Kroymann’s employment with the Company terminated effective June 18, 2012.
6 Mr. Hakmiller resigned as a Director effective November 20, 2012.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Review and Approval of Related Person Transactions
In October 2012, our Board adopted a Related Party Policy which formalized into a written policy certain practices and procedures historically followed by our Board relating to the approval of any transaction, arrangement or series of similar transactions, arrangements or relations, including indebtedness or guarantees of indebtedness, with related parties. Related persons include our directors or executive officers and their respective immediate family members and 5% beneficial owners of our units. Pursuant to the terms of the policy, the Corporate Governance / Compensation Committee must review the material facts of any related party transaction and approve such transaction.
Relationships and Related Party Transactions
The Company is party to the related party transactions discussed in detail in our financial statements above. See Note 5, Revolving Loan/Credit Agreements and Note 9, Related Party Transactions for the terms of our current related party transactions. The Company complied with the informal practices and procedures relating to the approval of related party transactions reflected in the Related Party Policy in connection with the approval of each of these related party transactions.
Director Independence
We classify our directors as “independent” according to the standards applicable to companies listed on the NASDAQ Capital Market (though our Units are not listed on any exchange or quotation system). Under the Operating Agreement, the independent directors’ terms are staggered such that one director will be up for election every year. Our independent directors are Karol D. King, Theodore V. Bauer, Herbert M. Houser, and Michael K. Guttau. The Audit Committee currently consists of Michael K. Guttau (Chair), Theodore V. Bauer and Karol D. King. All of the members of the Audit Committee meet the “independent director” standards applicable to companies listed on the NASDAQ Capital Market (though our Units are not listed on any exchange or quotation system). Presently, the Nominating Committee’s membership consists of Theodore V. Bauer, Hubert M. Houser (Chair), Michael K. Guttau, and Karol D. King, all of whom meet the “independent director” standards applicable to companies listed on the NASDAQ Capital Market (though the Company’s Units are not listed on any exchange or quotation system). The Committee Charter does not exclude from its membership directors who also serve as officers or Interested Directors. The Governance Committee’s membership consists of Messrs. Bauer, King, and Schmitt (Chair). Mr. Schmitt is considered an Interested Director.
Item 14. Principal Accountant Fees and Services.
Independent Public Accountant Fees and Services
The following table presents fees paid for professional services rendered by our independent public accountants for Fiscal 2012 and Fiscal 2011:
| | | | |
| | | | |
Fee Category | | Fiscal 2012 Fees | | Fiscal 2011 Fees |
| | | | |
Audit Fees | | $155,638 | | $131,250 |
| | | | |
Audit-Related Fees | | $0 | | $0 |
| | | | |
Tax Fees | | $31,435 | | $33,787 |
| | | | |
All Other Fees | | $15,000 | | $0 |
| | | | |
Total Fees | | $202,073 | | $165,037 |
Audit Fees are for professional services rendered by McGladrey LLP (“McGladrey”) for the audit of the Company’s annual financial statements, review of the interim financial statements included in quarterly reports and services that are normally provided by McGladrey in connection with statutory and regulatory filings or engagements, including review of SEC registration statements and related correspondence.
Audit-Related Fees are for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees.” These services include accounting, consultations in connection with acquisitions, consultations concerning financial accounting and reporting standards. We did not pay any fees for such services in Fiscal 2012 or 2011.
Tax Fees are for professional services rendered by McGladrey LLP (“McGladrey”), for tax compliance, tax advice and tax planning and include preparation of federal and state income tax returns, and other tax research, consultation, correspondence and advice.
All Other Fees are for services other than the services reported above. We did not pay any fees for such other services in Fiscal 2011.
The Audit Committee has concluded the provision of the non-audit services listed above is compatible with maintaining the independence of McGladrey.
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors
The Audit Committee pre-approves all audit and permissible non-audit services provided by our independent auditors. These services may include audit services, audit-related services, tax services and other services. Pre-approval is generally provided for up to one year and any pre-approval is detailed as to the particular service or category of services and is generally subject to a specific budget. The independent auditors and management are required to periodically report to the Audit Committee regarding the extent of services provided by the independent auditors in accordance with this pre-approval, and the fees for the services performed to date. The Audit Committee may also pre-approve particular services on a case-by-case basis.
Item 15. Exhibits and Financial Statement Schedules.
| (a) | Documents filed as part of this Report. |
Balance Sheets at September 30, 2012 and September 30, 2011
Statements of Operations for the two years ending September 30, 2012 and 2011.
Statements of Members’ Equity for the two years ending September 30, 2012 and 2011.
Statement of Cash Flows for the two years ending September 30, 2012 and 2011.
Notes to Financial Statements
| (b) | The following exhibits are filed herewith or incorporated by reference as set forth below: |
2 Omitted – Inapplicable.
3(i) Articles of Organization, as filed with the Iowa Secretary of State on March 28, 2005 (incorporated by reference to Exhibit 3(i) of Registration Statement on Form 10 filed by the Company on January 28, 2008).
4(i) Third Amended and Restated Operating Agreement dated July 17, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on August 21, 2009).
4(ii) Amended and Restated Indenture between the Company and Treynor State Bank dated as of December 1, 2011 (1)
4(iii) Form of Subscription Agreement between Holders and the Company (incorporated by reference to Exhibit 4(iv) of Form S-1/A filed by the Company on October 19, 2011).
4(iv) Unit Transfer Policy, including QMS Manual attached thereto as Appendix 1 (incorporated by reference to Exhibit 4(v) of Form S-1/A filed by the Company on October 19, 2011).
4(v) Form of Subscription Agreement between Holders and the Company for Iowa Purchasers who are not Members of the Company (incorporated by reference to Exhibit 4(vi) of Form S-1/A filed by the Company on October 19, 2011).
4(vi) Form of Subscription Agreement between Holders and the Company for Iowa Purchasers who are already Members of the Company (incorporated by reference to Exhibit 4(vii) of Form S-1/A filed by the Company on October 19, 2011).
4(vii) Form of Subscription Agreement between Holders and the Company for Arkansas Purchasers (incorporated by reference to Exhibit 4(viii) of Form S-1/A filed by the Company on October 19, 2011).
9 Omitted – Inapplicable.
10.1 Agreement dated October 13, 2006 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.1 of Registration Statement on Form 10/A filed by the Company on October 23, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.2 Executed Steam Service Contract dated January 22, 2007 with MidAmerican Energy Company (incorporated by reference to Exhibit 10.4 of Registration Statement on Form 10/A filed by the Company on October 23, 2008). Portions of the Contract have been omitted pursuant to a request for confidential treatment.
10.3 Assignment of Steam Service Contract dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.5 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.4 Electric Service Contract dated December 15, 2006 with MidAmerican Energy Company (incorporated by reference to Exhibit 10.6 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.5 Assignment of Electric Service Contract dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.7 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.6 Distillers Grain Purchase Agreement dated October 13, 2006 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.8 of Registration Statement on Form 10 filed by the Company on January 28, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.7 Assignment of Distillers Grain Purchase Agreement dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.9 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.8 Grain Feedstock Agency Agreement dated October 13, 2006 with AGRI-Bunge, LLC (incorporated by reference to Exhibit 10.10 of Registration Statement on Form 10 filed by the Company on October 23, 2008). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.9 Assignment of Grain Feedstock Agency Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.11 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.10 License Agreement dated September 25, 2006 between the Company and ICM, Inc. (incorporated by reference to Exhibit 10.10 of Form S-1/A filed by the Company on February 24, 2011). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.11 Security Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.15 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.12 Mortgage, Security Agreement Assignment of Rents and Leases and Fixture Filing dated May 2, 2007 in favor of AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.16 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.13 Environmental Indemnity Agreement dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.17 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.14 Convertible Note dated May 2, 2007 in favor of Monumental Life Insurance Company (incorporated by reference to Exhibit 10.18 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.15 Convertible Note dated May 2, 2007 in favor of Metlife Bank, N.A. (incorporated by reference to Exhibit 10.19 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.16 Convertible Note dated May 2, 2007 in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.20 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.17 Convertible Note dated May 2, 2007 in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.21 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.18 Convertible Note dated May 2, 2007 in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.22 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.19 Revolving Line of Credit Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.23 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.20 Revolving Line of Credit Note in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.24 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.21 Revolving Line of Credit Note in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.25 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.22 Term Revolving Note in favor of Metlife Bank, N.A. (incorporated by reference to Exhibit 10.26 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.23 Term Revolving Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A. (incorporated by reference to Exhibit 10.27 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.24 Term Revolving Note in favor of Metropolitan Life Insurance Company (incorporated by reference to Exhibit 10.28 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.25 Term Revolving Note in favor of First National Bank of Omaha (incorporated by reference to Exhibit 10.29 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.26 Lien Subordination Agreement dated May 2, 2007 among the Company, AgStar Financial Services, PCA and Iowa Department of Economic Development (incorporated by reference to Exhibit 10.30 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.27 Value Added Agricultural Product Marketing Development Grant Agreement dated November 3, 2006 with the United States of America (incorporated by reference to Exhibit 10.31 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.28 Fee Letter dated May 2, 2007 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.33 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.29 Master Contract dated November 21, 2006 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.35 of Registration Statement on Form 10 filed by the Company on January 28, 2008).
10.30 Amended and Restated Disbursing Agreement dated March 7, 2008 with AgStar Financial Services, PCA (incorporated by reference to Exhibit 10.39 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.31 Allonge to Revolving Line of Credit Note in favor of First National Bank of Omaha dated March 7, 2008 (incorporated by reference to Exhibit 10.43 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.32 Allonge to Revolving Line of Credit Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.44 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.33 Allonge to Revolving Line of Credit Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.45 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.34 Allonge to Convertible Note in favor of First National Bank of Omaha, dated March 7, 2008 (incorporated by reference to Exhibit 10.46 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.35 Allonge to Convertible Note in favor of Metlife Bank, N.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.47 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.36 Allonge to Convertible Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.48 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.37 Allonge to Convertible Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.49 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.38 Allonge to Term Revolving Note in favor of First National Bank of Omaha, dated March 7, 2008 (incorporated by reference to Exhibit 10.50 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.39 Allonge to Term Revolving Note in favor of Cooperative Centrale Raiffeisen-Boerenleenbank, B.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.51 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.40 Allonge to Term Revolving Note in favor of Metlife Bank, N.A., dated March 7, 2008 (incorporated by reference to Exhibit 10.52 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.41 Allonge to Term Revolving Note in favor of Metropolitan Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.53 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.42 Allonge to Convertible Note in favor of Monumental Life Insurance Company, dated March 7, 2008 (incorporated by reference to Exhibit 10.54 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.43 Term Revolving Note in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.55 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.44 Allonge to Term Revolving Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.56 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.45 Convertible Note dated May 2, 2007, in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.57 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.46 Allonge to Convertible Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.58 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.47 Revolving Line of Credit Note in favor of Amarillo National Bank (incorporated by reference to Exhibit 10.59 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.48 Allonge to Revolving Line of Credit Note in favor of Amarillo National Bank, dated March 7, 2008 (incorporated by reference to Exhibit 10.60 of Amendment No. 1 to Registration Statement on Form 10 filed by the Company on March 21, 2008).
10.49 Amendment No. 01 dated March 9, 2007 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on June 10, 2006).
10.50 Amendment No. 02 dated May 30, 2008 with Iowa Department of Economic Development (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 10, 2006).
10.51 Base Agreement dated August 27, 2008 between the Company and Cornerstone Energy, LLC (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 2, 2008).
10.52 Risk Management Services Agreement dated December 15, 2008 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on December 22, 2008).
10.53 Grain Feedstock Supply Agreement dated December 15, 2008 with AGRI-Bunge, LLC. Portions of the Agreement have been omitted pursuant to a request for confidential treatment (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 22, 2008).
10.54 Subordinated Revolving Credit Note made by the Company in favor of Bunge N.A. Holdings, Inc. dated effective August 26, 2009 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on September 2, 2009).
10.55 Amendment to Steam Service Contract by and between the Company and MidAmerican Energy Company dated effective October 3, 2008. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.61 of Form S-1/A filed by the Company on February 24, 2011)
10.56 Second Amendment to Steam Service Contract by and between the Company and MidAmerican Energy Company dated effective January 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.62 of Form S-1/A filed by the Company on February 24, 2011)
10.57 Third Amendment to Steam Service Contract by and between the Company and MidAmerican Energy Company dated effective January 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.63 of Form S-1/A filed by the Company on February 24, 2011)
10.58 Fourth Amendment to Steam Service Contract by and between the Company and MidAmerican Energy Company dated effective December 1, 2009. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.64 of Form S-1/A filed by the Company on February 24, 2011)
10.59 Amended and Restated Railcar Sublease Agreement dated March 25, 2009 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on August 14, 2009). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.60 Amended and Restated Credit Agreement by and among the Company and AgStar Financial Services, PCA, the Banks named therein, dated as of March 31, 2010 (incorporated by reference to Exhibit 99.1 of Form 8-K filed by the Company on April 5, 2010).
10.61 Loan Satisfaction Agreement, by and among the Company, ICM, Inc., and Commerce Bank, N.A., dated June 17, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 23, 2010).
10.62 Negotiable Subordinated Term Loan Note issued by the Company in favor of ICM, Inc., dated June 17, 2010 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on June 23, 2010).
10.63 ICM, Inc. Agreement – Equity Matters, by and between ICM, Inc. and the Company, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on June 23, 2010).
10.64 Subordinated Term Loan Note issued by the Company in favor of Bunge N.A. Holdings, Inc., dated June 17, 2010 (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on June 23, 2010).
10.65 Bunge Agreement - Equity Matters by and between the Company and Bunge N.A. Holdings, Inc. dated effective August 26, 2009. (incorporated by reference to Exhibit 10.72 of Form S-1/A filed by the Company on February 24, 2011)
10.66 First Amendment to Bunge Agreement – Equity Matters, by and between Bunge N.A. Holdings, Inc. and the Company, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.5 of Form 8-K filed by the Company on June 23, 2010).
10.67 Subordination Agreement, by and among Bunge N.A. Holdings, Inc., ICM, Inc., and AgStar Financial Services, PCA and acknowledged by the Company, dated as of June 17, 2010 (incorporated by reference to Exhibit 10.6 of Form 8-K filed by the Company on June 23, 2010).
10.68 Intercreditor Agreement, by and between Bunge N.A. Holdings, Inc. and ICM, Inc. and acknowledged by the Company, dated as of June 17, 2010. (incorporated by reference to Exhibit 10.7 of Form 8-K filed by the Company on June 23, 2010).
10.69 Southwest Iowa Renewable Energy Equity Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 6, 2010).
10.70 Joint Defense Agreement between ICM, Inc. and the Company dated July 13, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 16, 2010).
10.71 Tricanter Purchase and Installation Agreement by and between ICM, Inc. and the Company dated August 25, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K/A filed by the Company on January 12, 2011). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.72 Corn Oil Agency Agreement by and between Bunge North America, Inc. and the Company effective as of November 12, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on November 30, 2010). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10.73 Amendment to Amended and Restated Credit Agreement by and among the Company and AgStar Financial Services, PCA and the Banks named therein, effective as of March 31, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 5, 2011).
10.74 Second Amendment to Amended and Restated Credit Agreement by and among the Company and AgStar Financial Services, PCA and the Banks named therein, effective as of June 30, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 6, 2011).
10.75 Trustee Joinder to Intercreditor Agreement by Treynor State Bank dated December 12, 2011. (incorporated by reference to Exhibit 10.80 of Amendment No. 2 to Form S-1 filed by the Company on December 14, 2011).
10.76 Trustee Joinder to Subordination Agreement by Treynor State Bank dated December 12, 2011. (incorporated by reference to Exhibit 10.81 of Amendment No. 2 to Form S-1 filed by the Company on December 14, 2011).
10.77 Lease Agreement dated December 15, 2008 with Bunge North America, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on December 22, 2008).
10.78 Ethanol Purchase Agreement dated effective January 1, 2012 by and between the Company and Bunge North American, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on January 5, 2012) Portions of this agreement have been omitted pursuant to a request for confidential treatment.
10.79 Employment Agreement dated effective January 1, 2012 by and between the Company and Brian T. Cahill. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on January 5, 2012).
10.80 First Amendment to Promissory Note dated February 29, 2012 by and between the Company and Bunge N.A. Holdings, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on March 6, 2012)
10.81 Third Amendment to Amended and Restated Credit Agreement by and among the Company, AgStar Financial Services, PCA and the Banks named therein dated effective September 1, 2011. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on April 2, 2012).
10.82 Fourth Amendment to Amended and Restated Credit Agreement by and among the Company, AgStar Financial Services, PCA and the Banks named therein dated effective March 30, 2012. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on April 2, 2012).
10.83 Base Contract for Sale and Purchase of Natural Gas between Encore Energy Services, Inc. and the Company effective April 1, 2012. Portions of this Agreement have been omitted pursuant to a request for confidential treatment (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 1, 2012).
10.84 Confirming Order between Encore Energy Services, Inc. and the Company dated April 25, 2012. Portions of the Agreement have been omitted pursuant to a request for confidential treatment. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on May 1, 2012).
10.85 Separation Agreement and Release of All Claims by and between the Company and Karen L. Kroymann dated June 18, 2012. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 22, 2012).
10.86 Letter Agreement by and between the Company and CFO Systems, LLC dated June 21, 2012. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on June 22, 2012).
10.87 Notice of Assignment of Interests from Bunge N.A. Holdings, Inc. to Bunge North America, Inc. dated September 24, 2012.
11 Omitted – Inapplicable.
12 Omitted – Inapplicable.
13 Omitted – Inapplicable.
14 Omitted – Inapplicable.
16 Omitted – Inapplicable.
18 Omitted – Inapplicable.
21 Omitted – Inapplicable.
22 Omitted – Inapplicable.
23 Omitted – Inapplicable.
24 Omitted – Inapplicable.
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.XMLXBRL Instance Document
101.XSDXBRL Taxonomy Schema
101.CALXBRL Taxonomy Calculation Database
101.LABXBRL Taxonomy Label Linkbase
101.PREXBRL Taxonomy Presentation Linkbase
101.DEFXBRL Taxonomy Definition Linkbase
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: December 18, 2012 | /s/ Brian T. Cahill |
| Brian T. Cahill, President and Chief Executive Officer |
| |
Date: December 18, 2012 | /s/ Brett L. Frevert |
| Brett L. Frevert, CFO and Principal Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
| |
Signature | Date |
| |
/s/ Karol D. King | December 18, 2012 |
Karol D. King, Chairman of the Board | |
| |
/s/ Theodore V. Bauer | December 18, 2012 |
Theodore V. Bauer, Director | |
| |
/s/ Hubert M. Houser | December 18, 2012 |
Hubert M. Houser, Director | |
| |
/s/ Michael K. Guttau | December 18, 2012 |
Michael K. Guttau, Director | |
| |
/s/ C. Bailey Ragan | December 18, 2012 |
C. Bailey Ragan, Director | |
| |
| December 18, 2012 |
Tom J. Schmitt, Director | |
| |
/s/ Gregory P. Krissek | December 18, 2012 |
Gregory P. Krissek, Director | |
