Item 1. Business.
General
NEDAK Ethanol, LLC (the “Company,” or “us,” or “we”), a Nebraska limited liability company, was organized in 2003 and built a plant to produce ethanol and distiller’s grains on our 73-acre site located near Atkinson, Nebraska. Our principal business office is located at 87590 Hillcrest Road, Atkinson, Nebraska 68713. We completed full startup of the ethanol facility in June, 2009 and have the annual capacity to process approximately 17 million bushels of corn, through a dry milling process, into approximately 44 million gallons of ethanol per year (mgy). We also produce approximately 340,000 tons of wet distiller’s grains annually. We are currently operating at approximately 112% capacity.
Our Ethanol Plant
Our plant is comprised primarily of a raw material storage and processing area, a fermentation area comprised principally of fermentation tanks, a finished product storage and distillation area, and a drying unit for processing modified wet distiller’s grains. We also utilize a transload facility near O’Neill, Nebraska, approximately 16 miles from our plant, where ethanol is held in a storage tank or railcars pending rail shipment. Our plant uses a dry milling process to produce fuel-grade ethanol as its main product, in addition to the co-product distiller’s grains.
Ethanol
Ethanol is a chemical produced by the fermentation of sugars found in grains and other biomass. Ethanol can be produced from a number of different types of grains, such as wheat and sorghum, as well as from agricultural waste products such as sugar, rice hulls, cheese whey, potato waste, brewery and beverage wastes and forestry and paper wastes. However, approximately 90 percent of ethanol in the United States today is produced from corn because corn produces large quantities of carbohydrates, which convert into glucose more easily than other kinds of biomass.
Ethanol Supply
Annual U.S. ethanol production capacity has continually grown since 1980. According to the Renewable Fuels Association (the “RFA”), in 1992 ethanol production surpassed one billion gallons in the U. S., and production has steadily grown since then. In 2002, ethanol capacity in the U.S. surpassed two billion gallons, by 2007, capacity further increased to 6.5 billion gallons and by the end of 2009 capacity topped 13 billion gallons. However, because of economic difficulties in both the ethanol industry and the world economy, the temporary shutdown of significant portions of that capacity limited production in 2009 to approximately ten billion gallons. The Renewable Fuels Standard (“RFS”), which was created by the Energy Policy Act of 2005 (the “2005 Act”) established the RFS2 standard for blending of renewable fuels into automobile fuel in 2011 at 13.95 billion gallons, of which 2.56 billion gallons must come from non-corn based ethanol, leaving a maximum requirement of 11.4 billion gallons of corn based ethanol to be blended in 2011. As of December 2010, the RFA reported that nation-wide there were 191 operating ethanol refineries with a nameplate capacity of 13.1 billion gallons, another 21 non-operating facilities with 654 million gallons of capacity and 11 more plants under construction with additional capacity of 840 million gallons. Total capacity from these 223 facilities would be 14.6 billion gallons at nameplate, and at 110% of nameplate could produce over 16 billion gallons of ethanol per year. This means that compared to the RFS2 standard for 2011, there is nearly five billion gallons of potential corn based ethanol oversupply in the U.S.
Distiller’s grains
The chief co-product of the ethanol production process is distiller’s grains, which are the residues that remain after high quality cereal grains have been fermented by yeast. In the fermentation process, the remaining nutrients undergo a three-fold concentration to yield wet distiller’s grains to which is added evaporator syrup to create wet distiller’s grains with solubles, or WDGS. WDGS is a highly digestible feed ingredient marketed primarily to the dairy, beef, sheep, swine and poultry industries. Although we have drying capacity to dry up to 80% of our distiller’s grains volume, we expect to be able to distribute 100% of our output as WDGS into the local cattle feed market.
Current Markets and Future Demand
Federal Energy Policies
The 2005 Act eliminated the oxygen content requirement in reformulated gasoline, making use of oxygenates like ethanol optional for the petroleum industry in meeting clean air standards, and established a larger demand for ethanol, requiring an increase in production of approximately 700 million gallons per year over several years.
The Energy Independence and Security Act of 2007 (the “2007 Act”) modified the 2005 Act which created the RFS. The RFS is a national program that imposes requirements with respect to the amount of renewable fuel produced and used, and applies to refineries, blenders, distributors and importers, and does not restrict the geographic areas in which renewable fuels may be used. Among other things, the 2007 Act increased the RFS to require that a larger amount of renewable fuels (from 4.5 billion gallons in 2007 to 36 billion gallons by 2022) be used in the fuel refining industry, including 14 billion gallons of renewable fuels in 2011, and increased the RFS for renewable fuels to 15 billion gallons by 2015, while determining that the balance of the RFS production will come from other types of fuels, such as advanced biofuel, cellulosic biofuel and biomass-based diesel.
The federal government encourages ethanol production primarily by taxing it at a lower rate. The Volumetric Ethanol Excise Tax Credit (“VEETC”) is a tax credit of $0.45 per gallon of ethanol. Gasoline distributors apply for this credit, which is scheduled to expire on December 31, 2011. A number of bills have been introduced in the Congress to extend ethanol tax credits, including some bills that would make the ethanol tax credits permanent. There can be no assurance, however, that such legislation will be enacted. In addition, the small producer tax credit is available to plants producing up to 60 million gallons per year, of which the first 15 million gallons per year are eligible for a 10 cent per gallon credit, capped at $1.5 million per plant. In our limited liability company structure, this credit against tax liability would be passed through to our Members, subject to other considerations and the limitations discussed in the foregoing are applied at both the entity level and at the Member level. The small producer tax credit is also scheduled to expire on December 31, 2011, unless legislation extending the credit is enacted. While we are an eligible producer, the availability of this credit to our Members may be limited based on application at the Company and Member levels.
Changes in Corporate Average Fuel Economy (“CAFE”) 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.
In response to a request by Growth Energy, an ethanol industry trade association, under section 211(f)(4) of the Clean Air Act, the Environmental Protection Agency (“EPA”) has granted a partial waiver to allow fuel and fuel additive manufacturers to introduce gasoline that contains more than 10 volume percent (vol%) ethanol and up to 15 vol% ethanol (“E15”) for use in model year (“MY”) 2001 and newer light-duty motor vehicles, subject to several conditions. On October 13, 2010, the EPA granted a partial waiver for E15 for use in MY2007 and newer “light-duty vehicles.” “Light-duty vehicles” include cars, light-duty trucks and medium-duty passenger vehicles. On January 21, 2011, the EPA granted a partial waiver for E15 for use in MY2001-2006 “light-duty vehicles.” These decisions were based on test results provided by the U.S. Department of Energy (“DOE”) and other information regarding the potential effect of E15 on vehicle emissions. Taken together, the two actions allow, but do not require, E15 to be introduced into commerce for use in MY2001 and newer light-duty vehicles if conditions for mitigating,
misfueling and ensuring fuel quality are met. The EPA is in the process of completing work on regulations that would provide a more practical means of meeting the conditions.
State Incentives
Some states also provide various tax and production incentives, including reduced tax rates of state motor fuel tax, that combined with the federal incentive provide incentive for marketers to buy ethanol products. Several state programs require gasoline to contain a specified percentage of ethanol. The prospect of more states adopting a local requirement that either directly or indirectly requires ethanol is uncertain-primarily because of a decrease in political support of the production of ethanol.
Environmental and Other Regulation
Our ethanol production is subject to environmental and other regulations. We obtained environmental permits to construct and operate our ethanol plant.
Ethanol production involves the emission of various airborne pollutants, including particulate, carbon dioxide, oxides of nitrogen, hazardous air pollutants and volatile organic compounds. In 2007, the U.S. Supreme Court 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. On February 3, 2010, the EPA released its final regulations on the Renewable Fuels Standard, or RFS 2. We believe these final 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 distiller’s 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, though this standard is being challenged by numerous lawsuits.
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.
Clean Air Programs
Ethanol has been used primarily as a gasoline extender and is added in 10 percent volume blends to extend fuel supplies. It also is used as an octane enhancer due to the fact that 10 percent ethanol blends add three points of octane. In addition to a demand as a gasoline additive for reasons of supply and octane, ethanol has an established value as an oxygenate. Provisions in the Clean Air Act Amendments of 1990 resulted in the establishment of two fuel formulations that changed the entire marketing outlook for ethanol. The first of these is designed to combat carbon monoxide and requires that wintertime fuels in certain areas contain an oxygen content that could only be met by ethanol or an MTBE.
The second key program utilizing oxygenates deals with ozone, or summertime smog, and is the Federal Reformulated Gasoline Program. Nine U.S. cities, by federal law, and more than a dozen others, by local ordinance, have elected to use the RFG recipe for gasoline that controls a number of fuel properties such as vapor pressure and toxic content. Importantly, this formulation also requires a minimum oxygen content which could be met by using ethanol.
E10 plus
Unleaded gasoline with a 10% blend of ethanol accounts for the majority of ethanol consumption in the U.S. In 2008, production capacity in the U.S. surpassed the demand for ethanol and is expected to remain in surplus until the maximum blend for all highway gasoline powered vehicles is raised. The United States Department of Agriculture
(“USDA”) recently published comments discussing the potential for increasing the maximum ethanol blend as high as 20%. As noted above, the EPA has granted partial waivers to the 10% limit that allow distribution of E15 and is in the process of completing work on regulations that would provide more practical guidance.
E85
Demand for ethanol has been affected by the increased consumption of E85 fuel. E85 fuel is a blend of 85% ethanol and 15% gasoline. According to the Energy Information Administration, E85 consumption is projected to increase from a national total of 11 million gallons in 2003 to 47 million gallons in 2025. E85 can be used as an aviation fuel, as reported by the National Corn Growers Association, and as a hydrogen source for fuel cells. While the number of vehicles able to use E85 and the number of suppliers able to deliver it has increased each year, the consumption of ethanol in this form remains a relatively small percentage of the total demand for ethanol. In order for E85 fuel to increase demand for ethanol, it must be available for consumers to purchase it and the consumer needs to perceive an economic benefit from using 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.
Cellulosic Ethanol
Due to the volatile corn prices, discussion of cellulose-based ethanol has increased over the last few years. 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 and rice straw, among other common plants. Cellulosic ethanol is ethanol produced from cellulose, and currently, production of cellulosic ethanol is in its infancy. It is technology that is as yet unproven on a commercial scale. However, 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 if corn prices remain 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.
Raw Materials
Corn Requirements
Our plant needs approximately 16 to 18 million bushels of corn per year, or approximately 47,000 bushels per day, as the feedstock for its dry milling process. The grain supply for our plant is obtained primarily from local markets. We utilize the services of a third party agent on an at-will basis for nearly all contracts with local producers for the delivery of corn and pay the agent a service fee of $0.04 per bushel of grain delivered (plus $0.02 per bushel to reduce balance payable for fees not paid during the first two years of plant start-up pursuant to agreement with the third party agent), and we execute contracts directly with producers for some of our corn. We are also purchasing more corn through an arrangement with Tenaska BioFuels, LLC (“Tenaska”). Under this arrangement, Tenaska sells us corn netted against their receivable for marketed ethanol. Our arrangement with Tenaska can be terminated at any time by either party. In the ordinary course of business, we will enter into forward purchase contracts for our corn purchases.
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. As of March 4, 2011, corn for May 2011 delivery was $7.28 per bushel.
Energy Requirements
The production of ethanol is a very energy intensive process which uses significant amounts of electricity and natural gas. Water supply and quality are also important considerations. Presently, about 40,000 BTUs of energy are required to produce a gallon of ethanol.
Natural Gas
Our plant requires a natural gas supply of 1.3 to 1.7 billion cubic feet per year.
Supply. We have entered into a management consulting agreement with Tenaska to help us manage our gas supply. We receive distribution services for all of our natural gas from Source Gas. We entered into a Negotiated Rate Agreement for Distribution Transportation Service (“Negotiated Rate Agreement”) with Source Gas which establishes the minimum and maximum quantities of natural gas to be delivered to us under a separate Transportation Service Agreement. We agreed to pay Source Gas a distribution fee per therm delivered to us for the first five years of the Negotiated Rate Agreement, and such rate automatically increases thereafter according to a formula based upon the GDP Implicit Price Deflator published by the U.S. Department of Commerce.
Transportation. To access sufficient supplies of natural gas to operate the plant, a connection to a distribution pipeline approximately six miles from our site was constructed. We have entered into two Firm Transportation Service Agreements with Kinder Morgan Interstate Gas Transmission LLC under which we have agreed to pay monthly reservation fees for guaranteed interstate pipeline transportation. In conjunction with the second Firm Transportation Agreement, we have agreed to pay a monthly Facility Reimbursement Fee in addition to the normal reservation fee.
Electricity
Our plant requires a continuous supply of 1.3 kilovolt-ampere, 12,400 volt electrical energy, which we purchase from the Nebraska Public Power District.
Water
Our plant requires approximately 400 gallons of fresh water per minute. While much of the water used in an ethanol plant is recycled back into the process, boiler makeup water and cooling tower water must be fresh. 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 can be recycled back into the process, which will minimizes the effluent, which can have the long-term effect of lowering waste water treatment costs. Many new plants today are zero or near zero effluent facilities. We anticipate that there should be no more than 40 gallons per minute of non-contaminated water required. The water from the cooling tower and the boiler blowdown water are put in a pond and released to the environment either through evaporation, or by discharge into the Elkhorn River pursuant to our discharge permit. Our water requirements are supplied through wells, though allocations of future water resources for the Upper Elkhorn District will be set by the Upper Elkhorn Natural Resources District (“NRD”).
Competition
Ethanol has become a widely used commodity, but the market is still developing. Price competition is becoming a factor of the overall marketplace, as opposed to direct price competition between producers. The Nebraska Ethanol Board reports that there are currently 25 active ethanol production plants in Nebraska, with a combined production capacity of 1.8 billion gallons of ethanol each year, and these facilities require 653 million bushels of corn each year to operate. We contribute nearly 2.5% of the total produced volume in Nebraska.
Although the Nebraska legislature has historically provided incentives to ethanol producers in Nebraska, we do not qualify for any existing incentives. Only plants that were in production on June 30, 2004 are eligible for such incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years. Producers qualifying for this incentive have a competitive advantage over us.
The ten counties surrounding our production facility have produced nearly 81 million bushels of corn per year over the last ten years. Specifically, Holt County, where we are located, is the largest producer of those ten counties with an average corn production of 24 million bushels per year over the same time period. This large production in a region with limited demand has pressed the corn price down below the national average for the last 20 years at an
average of 40-45 cents per bushel. Our annual demand of 17 million bushels is more than 20% of production in the ten county region and more than 80% in Holt County.
We believe we have an advantage due to our westernmost location which lowers the cost of delivery from our plant into the western U.S. markets. Conversely, we are at a disadvantage delivering our product into the larger markets of the eastern U.S.
Foreign Competition
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. Several large companies produce ethanol in Brazil. For example, in August 2010, Royal Dutch Shell formed a joint venture with Cosan, which produces approximately 450 mmgy of sugar-based ethanol per year.
Ethanol produced in foreign countries, from sugarcane or other feed stocks imported into the United States, is subject to an import tariff of $0.54 per gallon. Production imported from the Caribbean region is eligible for tariff reduction or elimination under a program known as the Caribbean Basin Initiative. Large multinational companies have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would convert ethanol into fuel-grade ethanol for shipment to the United States. Depending on feed stock prices, ethanol imported from Caribbean Basin countries may be less expensive than domestically-produced ethanol though transportation and infrastructure constraints may temper the market impact on the United States.
Competition from Alternative Fuel Additives
Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development by ethanol and oil companies with far greater resources than we have. 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.
Marketing
Ethanol
Through December 31, 2010, we sold our ethanol through an Ethanol Marketing Agreement with Eco-Energy, Inc. of Franklin, Tennessee (“Eco”), under which Eco purchased all of our ethanol and resold it. We paid Eco a fee of $0.01 per gallon of ethanol purchased. We now sell our ethanol through a non-binding arrangement with Tenaska whereby Tenaska assists us in locating buyers for our ethanol on the spot market. We pay Tenaska a fee of $0.02 per gallon of ethanol sold, and our arrangement with Tenaska can be terminated at any time by either party.
Most of our ethanol is sold into markets throughout the United States and is shipped primarily by truck to our transload facility in O’Neill, Nebraska, and then by rail. Our target market area includes local, regional (Nebraska, South Dakota, Kansas, Missouri, Indiana, Colorado, Minnesota, Illinois, Wisconsin and Iowa) and national markets.
Distiller’s grains
Through February 28, 2011, we sold our WDGS through a Marketing Agreement with Distillers Grain Services LLC (“Distillers”), under which Distillers had the exclusive right to purchase from us, and was obligated to market, all distiller’s grains produced by us at our plant. Under the Marketing Agreement, we paid Distillers a marketing fee of $1.50 per ton of distiller’s grains sold at $50 per ton or less, and 3.0% of distiller’s grains tonnage sold over $50 a ton. We now market our WDGS directly to the feeders and incur no marketing fees. In the event that the local demand for WDGS becomes inadequate to move all of our production, we will likely market our WDGS through a non-binding arrangement with Tenaska whereby Tenaska will buy our DDGS directly from us at market prices.
Transportation and Storage
In order to capitalize on low land acquisition costs, local corn costs, and a number of other factors associated with locating our plant in Atkinson, we transport our ethanol by truck to a transload facility approximately 16 miles from our plant. We entered into a Transportation Agreement (the “Carrier Transportation Agreement”) with Western Oil Trans Inc. (“Carrier”), under which Carrier ships our ethanol to our rail facility. The term of the Carrier Transportation Agreement will continue until July 29, 2011 and automatically renew for successive one year periods. The Carrier Transportation Agreement may be terminated by either party upon providing notice 180 days prior to the end of the then-current term, if the Carrier’s authority to provide shipping services is modified, upon mutual agreement, or upon the discontinuance of either party’s business.
We entered into an Industry Track Agreement (“NENE Track Agreement”) with the Nebraska Northeastern Railway Company (“NENE”), under which we constructed a rail line (“Track”) over NENE’s property located near the center of the City of O’Neill, Nebraska. The NENE Track Agreement has an initial term of five years, expiring July 24, 2012, and will automatically continue thereafter until terminated by either party upon 30 days’ notice. The NENE Track Agreement may also be terminated in the event we are unable to cure certain specified defaults, if NENE is authorized to abandon its line which connects to the Track, or if NENE is no longer able to operate over the Track. Under the NENE Track Agreement, we are responsible for, among other things, maintaining all permits required to operate the Track, and maintain the Track; and NENE has agreed to provide rail service to transport our ethanol over the Track.
We entered into a Track Lease Agreement (the “Track Agreement”) with the Nebraska Game and Parks Commission (the “Commission”), under which we lease from the Commission a parcel of land (the “Property”) to use as a rail spur track over which we transport our ethanol. The Track Agreement has a term of ten years, expiring June 19, 2017, and will automatically renew for additional ten year terms unless one party notifies the other at least nine months prior to the expiration date of its intention to not renew. We pay an annual rental fee of $10,000 for use of the Property. Additionally, we are responsible for any public assessments respecting the maintenance or use of the Property. The Track Agreement provides that we are responsible to maintain the track on the Property and are solely responsible for our operations on the Property and complying with applicable laws regarding our use of the Property.
We are currently leasing approximately 170 rail cars for which we pay approximately $95,500 per month. The average cost per car is $562, which is above the current market as a result of originally entering into long term leases at a time when the market value was around $700 per month. With weather related problems in the winter of 2009-2010, we have been forced to enter into short-term (one and two month) leases in order to move ethanol when storage approaches full capacity.
Regulatory Environment
Governmental Approvals
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, construction and operating permits, some of which are discussed below. Our failure to obtain and maintain the permits discussed below or other similar permits which are required and those which may be required in the future could force us to make material changes to our business or to shut down altogether.
Environmental Regulations and Permits
We are subject to regulations on emissions from the U.S. Environmental Protection Agency (“EPA”) and the Nebraska Department of Environmental Quality (“NDEQ”). The EPA’s and NDEQ’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.
NDEQ Air Quality Permit
We received an Air Quality Operating Permit from NDEQ that allows us to operate our business. We received Notices of Violation (“NOV”) from the NDEQ arising from failures of emission equipment designed and installed by our design builder, Delta-T Corporation (“Delta-T”) under the Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T (the “Delta-T Contract”), and believe that we have resolved the problems.
Other Permits
A General Stormwater Permit for Industrial Activity has been obtained from NDEQ under which we are presently operating and we have implemented a Storm Water Pollution Prevention Plan for monitoring the storm water leaving the site. We also obtained a permit for non-process wastewater which governs the discharge of noncontact water used in the production of ethanol. There are presently three separate wells near our plant that provide us with our water supply. All three wells have been registered with the Nebraska Department of Natural Resources (“NDNR”) and their status is registered as “commercial.” The operation of the wells has also received the approval of the NRD. Any new or additional wells necessary for the operation of the facility will require registration and approval by the NRD.
Nuisance
We could be subject to environmental nuisance or related claims by employees, property owners or residents near our ethanol plant 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 increase our operating costs.
Operational Safety Regulations
We are also subject to federal and state laws regarding operational safety. Risks of substantial compliance costs and liabilities are inherent in ethanol production, and 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 construction or operation could result in substantial costs and liabilities.
Research and Development
We may conduct limited research and development to improve our operational efficiency and performance, but we have not determined the scope of such research and development.
Employees
As of December 31, 2010 we had 37 employees, including salaried employees, and five full time management independent contractors. We renewed an Employment Agreement with Jerome Fagerland as of November 1, 2009, under which Mr. Fagerland serves as our President and General Manager. Mr. Fagerland devotes substantially all of his time to our business. Our Board Chairman, Everett Vogel, Vice Chairman, Richard Bilstein and our Secretary-Treasurer, Timothy Borer, each devote about 15 hours per week to our business. See “Compensation of Directors and Executive Officers” in our 2011 Proxy Statement. We have entered into a Plant Operating Agreement with HWS Energy Partners, L.L.C. (“HWS”), under which HWS manages our ethanol plant. HWS provides, for the employment by us, a sufficient number of employees to operate our plant. While all employees excepting HWS’s key management personnel are our employees, HWS is responsible for timely identifying employee candidates and assuring that vacancies are filled.
Item 1A.
Item 1A. Risk Factors.
You should carefully read and consider the risks and uncertainties below and the other information contained in this report. The risks and uncertainties described below are not the only ones we may face. The following risks, together with additional risks and uncertainties not currently known to us or that we currently deem immaterial could impair our financial condition and results of operation.
RISKS ASSOCIATED WITH OUR FINANCING PLAN
Our Membership Units have no public trading market and are subject to significant transfer restrictions which could make it difficult to sell Membership Units and could reduce the value of Membership Units.
We do not expect an active trading market for our Membership Units to develop. To maintain our partnership tax status, our Membership Units may not be publicly traded. We will not apply for listing of the Membership Units on any stock exchange or on the NASDAQ Stock Market. As a result, Members may not sell Membership Units readily. Transfer of Membership Units is also restricted by our Third Amended and Restated Operating Agreement dated March 4, 2009 (the “Operating Agreement”) and subject to the procedures contained therein. Transfers without the approval of our Board of Directors are not permitted and are invalid. Furthermore, the Board of Directors will not approve transfer requests unless they fall within “safe harbors” contained in the publicly-traded partnership rules under the Internal Revenue Code of 1986, as amended (the “Code”). The fair value of our Membership Units will likely be lower because they are illiquid. Members may be required to bear the economic risks associated with an investment in us for an indefinite period of time.
If we issue additional Membership Units in the future this will result in dilution to our existing Members.
As discussed in more detail in the 2010 Annual Report under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we may, depending on many factors, issue additional equity. Our Board of Directors may choose to issue additional Units-including Class A Preferred Units which have preferred terms versus our Common Units-at prices lower than Units previously sold to provide additional financing in the near term or in the future. The issuance of any such Units may result in a reduction of the book value or fair value of the outstanding Units. If we do issue any such additional Units, such issuance also will cause a reduction in the proportionate ownership and voting power of all other Members.
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 our credit facility, we have made certain customary representations and we are subject to customary affirmative and negative covenants, including restrictions on our ability to incur debt, create liens, dispose of assets, pay distributions and to make capital expenditures, and customary events of default (including payment defaults, covenant defaults, cross defaults, construction related defaults and bankruptcy defaults). The credit facility also contains financial covenants including minimum working capital, certain reserves, minimum current assets to current liabilities, minimum tangible net worth, minimum owners’ equity ratio and a minimum fixed charge coverage ratio. As discussed in the 2010 Annual Report under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we presently are not in compliance with some of these covenants. These requirements, in addition to our obligations to repay principal and interest on the credit facility, make us more vulnerable to economic or market downturns. If we are unable to service our debt or modify our covenants, we may be forced to reduce or delay planned capital expenditures, sell assets, restructure our indebtedness or seek additional equity capital. We have classified this debt as a current liability on our December 31, 2010 balance sheet since we are presently in default on covenants and the lender could make the entire debt immediately due and payable. If this occurs, we likely will 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.
Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial debt.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which to a certain extent is subject to economic, financial, competitive and other factors beyond our control. As of December 31, 2010, we had approximately $45 million of total debt outstanding and were in default of our credit agreements. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations.
Members may not receive cash distributions on our Membership Units which could result in an investor receiving little or no return on his or her investment.
Distributions on our Membership Units are payable at the sole discretion of our Board, subject to the provisions of the Nebraska Limited Liability Company Act (the “Act”), our Operating Agreement and our loan agreements. Cash distributions are not assured even if we generate taxable income to our Members, and we may never be in a financial position to make distributions. Our Board may elect to retain future profits to provide operational financing for our ethanol plan, debt retirement and possible plant expansion. In addition, our loan agreements restrict our ability to make distributions. This means that Members may receive little or no return on their investment and may be unable to liquidate their investment due to transfer restrictions and lack of a public trading market. This could result in the loss of a Member’s entire investment.
We operate in capital intensive businesses and rely on cash generated from operations and external financing. Limitations on access to external financing could adversely affect our operating results.
Some ethanol producers have faced financial distress, culminating with bankruptcy filings by several companies. This, in combination with continued volatility in the capital markets has resulted in reduced availability of capital for the ethanol industry generally. Construction of our plant and anticipated levels of required working capital were funded under our long-term credit facility. Further increases in liquidity requirements could occur due to, for example, increased commodity prices. Our operating cash flow is dependent on our ability to profitably operate our business and overall commodity market conditions. In addition, we may need to raise additional financing to fund our operations. In this market environment, we may experience limited access to financing. This could cause us to reduce our business activity or, if we are unable to meet our debt repayment schedules, cause a default in our existing debt agreements. These events could have a material adverse effect on our operations and financial position.
Our ability to repay current and anticipated future indebtedness will depend on our financial and operating performance and on the successful implementation of our business strategies. Our financial and operational performance depend on numerous factors including prevailing economic conditions, volatile commodity prices, and financial, business and other factors beyond our control. If we cannot pay our debt service, we may be forced to sell assets, restructure our indebtedness or seek additional capital. If we are unable to restructure our indebtedness or raise funds through sales of assets, equity or otherwise, our ability to operate could be harmed and the value of our units could be significantly reduced.
We may be required to write down our long-lived assets and these impairment charges would adversely affect our operating results.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount on 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 assets at
the time of the impairment. Future impairment could be significant and could have a material adverse effect on our reported financial results for the period in which the charge is taken.
RISKS ASSOCIATED WITH OUR OPERATION
The nature of our operations and our profit potential may change considerably.
As further explained under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Annual Report, we are exploring the possibility of entering into a much more comprehensive business arrangement with Tenaska. While the final terms will depend on a variety of factors which include input from our lenders, it is possible we may turn over the majority of the risks we face in our business to Tenaska, along with the ability to enjoy most of the profits from our operations. This would constitute a significant change in our business model, and we cannot predict at this time the impact of any such agreement on our results of operations.
Presently, our results of operations and ability to operate at a profit are largely dependent on managing the spread among the prices of corn, natural gas, ethanol and distiller’s grains, the prices of which are subject to significant volatility and uncertainty.
The results of our current ethanol production business are highly impacted by commodity prices, including the spread between the cost of corn and natural gas that we must purchase, and the price of ethanol and distiller’s grains that we sell. Prices and supplies are subject to and determined by market forces over which we have no control, such as weather, domestic and global demand, shortages, export prices, and various governmental policies in the United States and around the world. As a result of price volatility for these commodities, our operating results may fluctuate substantially. Increases in corn prices or natural gas or decreases in ethanol or distiller’s grains prices may make it unprofitable to operate our ethanol plant. No assurance can be given that we will be able to purchase corn and natural gas at, or near, current prices and that we will be able to sell ethanol or distiller’s grains at, or near, current prices. Consequently, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol and distiller’s grains.
In early 2006, the spread between ethanol and corn prices was at historically high levels, driven in large part by oil companies removing a competitive product, methyl tertiary butyl ether, or MTBE, from the fuel stream and replacing it with ethanol in a relatively short time period. However, since that time, this spread has fluctuated widely and narrowed significantly. Fluctuations are likely to continue to occur. A sustained narrow spread or any further reduction in the spread between ethanol and corn prices, whether as a result of sustained high or increased corn prices or sustained low or decreased ethanol prices, would adversely affect our results of operations and financial position. Further, combined revenues from sales of ethanol and distiller’s grains could decline below our marginal cost of production, which could cause us to suspend production of ethanol and distiller’s grains at our ethanol plant.
For these and other reasons, as further explained under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Annual Report, we are exploring the possibility of altering our relationship with Tenaska whereby Tenaska assumes greater responsibility for the risks associated with our business. Assumption of such risks would necessarily mean that Tenaska would have the ability to enjoy the economic rewards of our business.
We are presently exposed to credit risk resulting from the possibility that a loss may occur from the failure of our contractual counterparties to perform according to the terms of our agreements.
In selling ethanol and distiller’s grains in our present business model, we may experience concentrations of credit risk from a variety of customers. We continually monitor this credit risk exposure. In addition, we may prepay for or make deposits on undelivered inventories. The inability of a third party to make payments to us for our accounts receivable or to provide inventory to us on advances made may cause us to experience losses and may adversely impact our liquidity and our ability to make our payments when due.
For these and other reasons, as further explained under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Annual Report, we are exploring the possibility of altering our relationship with Tenaska whereby Tenaska assumes greater responsibility for the risks associated with our business. Assumption of such risks would necessarily mean that Tenaska would have the ability to enjoy the economic rewards of our business.
We have limited working capital, which could result in losses that will affect the value of Units or Members’ investment return.
We were organized in 2003 and have negative working capital. We cannot make representations about our future profitable operation or our future income or losses. If our plans prove to be unsuccessful, Members will lose all or a substantial part of their investment. There can be no assurance that the funds we received in our equity offerings, combined with debt incurred, will be sufficient to allow us to operate our plant until profits are attained.
We may be at a competitive disadvantage compared to other ethanol producers because of our distance from a railhead, which increases our costs and could reduce the value of Membership Units or Members’ investment return.
Our plant is approximately 16 miles from the nearest railhead. We have constructed a transload facility near the railhead and truck our ethanol to the transload facility. Although these costs have been included in our construction and operating cost projections, we could be at a disadvantage compared to our competitors, which could adversely affect the value of an investment in us.
We are dependent upon our plant management company to hire and retain competent personnel.
We have entered into a Plant Operating Agreement with HWS, under which HWS manages all facets of our plant’s operations and provides, for the employment by us, employees to operate our plant. We have 37 paid persons operating our business. Our success will depend in part on the ability of HWS to attract and retain competent personnel who will be able to help us achieve our goals. It may be difficult to attract qualified employees to Atkinson, Nebraska, a rural and sparsely populated area. If HWS is unable to retain productive and competent personnel, our ability to produce and sell ethanol could be adversely affected.
Casualty losses may occur for which we have not secured adequate insurance.
We have acquired insurance that we believe to be adequate to prevent loss from foreseeable risks. However, events occur for which no insurance is available or for which insurance is not available on terms that are acceptable to us. Loss from such an event, such as, but not limited to, earthquake, tornados, war, riot, terrorism or other risks, may not be insured and such a loss may have a material adverse effect on our operations, cash flows and financial performance.
Our business is not diversified and this could reduce the value of Membership Units if our revenues from our primary products decrease.
Our business consists solely of ethanol and distiller’s grains production and sales. We have no other lines of business or other sources of revenue. Our lack of business diversification could cause Members to lose all or some of their investment if we are unable to generate a profit by the production and sales of ethanol and distiller’s grains since we do not expect to have any other lines of business or alternative revenue sources.
We have a history of losses and may not ever operate profitably.
From our inception in 2003 through December 31, 2010, we incurred an accumulated net loss of approximately $18,100,000. There is no assurance that we will be successful in operating the plant profitably.
If there are defects in our plant, it may negatively affect our ability to operate the plant.
There is no assurance that defects in materials and/or workmanship in our plant will not occur. Such defects occurred in 2009 and could cause us to halt or discontinue the plant’s operations. We have released Delta-T from any further responsibility for any construction defects or warranty claims under our settlement with Delta-T. Accordingly, we will be required to pay for any such defects should they occur. Any such event may have a material adverse effect on our operations, cash flows and financial performance.
We currently do not have a written contract for the procurement of our corn or the marketing of our ethanol, meaning our agent may discontinue its relationship with us at any time and we could be forced to seek alternatives that may not be as favorable.
Tenaska currently assists us in procuring corn and markets our ethanol for us, but we do not have a written agreement with Tenaska for these services. As a result, Tenaska may choose to stop assisting us in buying corn or marketing our ethanol at anytime. If Tenaska chooses to stop helping us procure corn or market our ethanol, then we will have to find corn and market our ethanol ourselves. We may not be able to perform those activities as well as Tenaska because we do not have a professional staff dedicated to procuring corn or marketing ethanol. Without third party assistance, we could have a more difficult time purchasing corn at more favorable prices and/or selling our ethanol at acceptable prices.
Our Operating Agreement contains restrictions on Members’ rights to participate in corporate governance of our affairs, which limits their ability to influence management decisions.
Our Operating Agreement provides that a Member or Members owning at least thirty percent of the outstanding Units may call a special meeting of the Members. This may make it difficult for Members to propose changes to our Operating Agreement, without support from our Board of Directors. Our Board of Directors is divided into three classes, with each class serving a staggered three-year term. The classification of the Board of Directors will make it more difficult for Members to change the composition of the Board because only a minority of the Directors can be elected at one time. If a vacancy develops in our Board of Directors for any reason other than removal or expiration of a term, the remaining Directors would fill it.
Our Directors have other business and management responsibilities which may cause conflicts of interest in the allocation of their time and services to the Company.
Since our project is currently managed both by our officers and to some extent by the Board of Directors (rather than completely by a professional management group), the devotion of the Directors’ time to the project is critical. However, the Directors have other management responsibilities and business interests apart from our business. As a result, our Directors may experience conflicts of interest in allocating their time and services between us and their other business responsibilities. We have adopted a related party transaction policy and a Code of Ethics, but there can be no assurance that these policies will fully alleviate conflicts of interest that could impact the Company.
The internal controls over financial reporting we have developed may not be adequate, which could have a significant and adverse effect on our business and reputation.
We have designed and tested our internal controls over financial reporting. We expect to incur ongoing additional expenses to comply with applicable law, which will negatively impact our financial performance and our ability to make distributions. This process may also divert management’s time and attention. Our management is required to report on our internal controls over financial reporting pursuant to Sections 302 and 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) and rules and regulations of the SEC thereunder in this report on Form 10-K. We are required to review on an annual basis our internal controls over financial reporting, and on a quarterly and annual basis to evaluate and disclose changes in our internal controls over financial reporting. There can be no assurance that our quarterly and annual reviews will not identify material weaknesses or that we will successfully resolve all issues which may arise under any such evaluations.
Disruption or difficulties with our information technology could impair our ability to operate.
Our business depends on the effective and efficient use of information technology. A disruption or failure of these systems could cause system interruptions, delays in production and a loss of critical data that could severely affect our ability to conduct normal business operations.
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. There are no assurances that we will continue to have a sufficient supply of water to sustain our ethanol plant in the future, or that we can obtain the necessary permits to obtain water directly from the Elkhorn River as an alternative to our wells. As a result, our ability to make a profit may decline.
Hedging transactions, which are intended to stabilize our corn costs, also involve risks and costs that could reduce our profitability.
In an attempt to mitigate the effects of the volatility of corn costs on operating profits, we may take hedging positions in corn futures markets provided we have sufficient working capital. Hedging means protecting the price at which we buy corn and the price at which we will sell our products in the future. It is a way to attempt to reduce the risk caused by price fluctuation. The effectiveness of hedging activities is dependent upon, among other things, the cost of corn and our ability to sell sufficient amounts of ethanol and distiller’s grains to utilize all of the corn subject to the futures contracts. Hedging activities result in costs such as brokers’ commissions and other transaction costs. If there are significant swings in corn prices, or if we purchase more corn for future delivery than we can use, and if the margin between what we purchase our corn at is not positive when compared to the margin for which we can sell our ethanol, we may have to pay to terminate a futures contract, resell unneeded corn inventory at a loss, or produce ethanol at a loss, all of which would have a material adverse effect on our financial performance.
Liquidity can be affected when margin account balances are insufficient to cover the margin requirements of these hedging transactions. These accumulated differences in value on these derivatives are marked to market as of the last day of every month and the change in value over the period is recorded in the income statement as a loss or profit each recording period. These financial statement charges can cause large swings in profitability.
Depending on the extent of our relationship with Tenaska, which we cannot provide assurance of, we may or may not continue to utilize hedging when our capital position allows. Even if we transfer the primary risks of our business to Tenaska, we cannot predict now the extent to which hedging-related risks may negatively impact our financial performance.
The Dodd-Frank Act could result in an increase in the cost of hedging, which could decrease our results of operations.
The regulations of “over-the-counter” derivatives introduced by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) could adversely impact our hedging strategy. Through its comprehensive new regulatory regime for derivatives, the Dodd-Frank Act will impose mandatory clearing, exchange-trading and margin requirements on many derivatives transactions (including formerly unregulated over-the-counter derivatives) in which we may engage. The Dodd-Frank Act also creates new categories of regulated market participants who will be subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements. The details of these requirements and the parameters of these categories remain to be clarified through rulemaking and interpretations by the Commodities Futures Trading Commission, the SEC, the Federal Reserve and other regulators in a regulatory implementation process, which is expected to take a year or more to complete. Nonetheless, based on information available as of the date of this prospectus, the possible effect of the Dodd-Frank Act will be to increase our overall costs of entering into derivatives transactions. In particular, new margin requirements, position limits and capital charges, even if not directly applicable to us, may cause an increase in the pricing of derivatives transactions sold by market participants to whom such requirements apply.
Administrative costs, due to new requirements such as registration, recordkeeping, reporting, and compliance, even if not directly applicable to us, may also be reflected in higher pricing of derivatives. New exchange-trading
and trade reporting requirements may lead to reductions in the liquidity of derivative transactions, causing higher pricing or reduced availability of derivatives, adversely affecting the performance of our hedging strategies. The Dodd-Frank Act could result in the cost of executing our hedging strategy increasing significantly, which could potentially result in an undesirable decrease in the amount of corn and ethanol we hedge. If our hedging costs increase and we are required to post cash collateral, our business would be adversely affected as a result of reduced cash flow and reduced liquidity. Additionally, in the event that we hedge lower quantities in response to higher hedging costs and increased margin requirements, our exposure to changes in commodity prices would increase, which could result in decreased cash flows.
Whether we enter into a more comprehensive relationship with Tenaska (as discussed in our 2010 Annual Report) or not, additional costs imposed by the Dodd-Frank Act could negatively impact our results of operations and profitability.
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. If we are unable to obtain a natural gas supply on terms that are satisfactory to us, the adverse impact on our plant and operations could be material. In addition, natural gas and electricity prices have historically fluctuated significantly. Increases in the price of natural gas or electricity would harm our business by increasing our energy costs. We will need to purchase significant amounts of electricity to operate our plant. The prices which we will be required to pay for electrical power will have a direct impact on our costs of producing ethanol and our financial results.
Changes and advances in ethanol production technology could require us to incur costs to update our plant or could otherwise hinder our ability to compete 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, all of which could reduce the value of Members’ investment.
We rely on a limited number of suppliers for our products, and the loss of one or several of these suppliers could increase our costs and have a material adverse effect on our business.
We rely on a limited number of suppliers for our products. If we are unable to obtain these raw materials and products from our current vendors, or if there were significant increases in our suppliers’ prices, it could disrupt operations, thereby significantly increasing our costs and reducing profit margins.
We are exposed to potential business disruption from factors outside our control, including natural disasters, seasonality, severe weather conditions, accidents, and unforeseen plant shutdowns, any of which could adversely affect our cash flows and operating results.
Potential business disruption in available transportation due to natural disasters, significant track damage resulting from a train derailment, or strikes by our transportation providers could result in delays in procuring and supplying raw materials to our ethanol plant, or transporting ethanol and distiller’s grains to our customers. We also
run the risk of unforeseen operational issues that may result in an extended shutdown of our ethanol plant. Such business disruptions would cause the normal course of our business operations to stall and may result in our inability to meet customer demand or contract delivery requirements, as well as the potential loss of customers.
Corn procurement for our ethanol plant is dependent on weather conditions. Adverse weather may result in a reduction in the sales of fertilizer or pesticides during typical application periods, a reduction in grain harvests caused by inadequate or excessive amounts of rain during the growing season, or by overly wet conditions, an early freeze or snowy weather during the harvest season. Additionally, corn stored in an open pile may become damaged by too much rain and warm weather before the corn is dried, shipped, consumed or moved into a storage structure.
RISKS ASSOCIATED WITH THE ETHANOL INDUSTRY
Increased ethanol industry penetration by oil companies or other multinational companies may adversely impact our margins.
We operate in a very competitive environment. In 2009 and 2010, significant investment in ethanol production was made by large oil distribution companies through the acquisition of failing organizations. Prior to that, the ethanol industry has been primarily comprised of smaller entities that engage exclusively in ethanol production and large integrated grain companies that produce ethanol along with their base grain businesses. We face competition for capital, labor, corn and other resources from these companies. Until recently, oil companies, petrochemical refiners and gasoline retailers have not been engaged in ethanol production to a large extent. These companies, however, form the primary distribution networks for marketing ethanol through blended gasoline. During the past few years, several large oil companies have entered the ethanol production market. If these companies increase their ethanol plant ownership or other oil companies seek to engage in direct ethanol production, there will be less of a need to purchase ethanol from independent ethanol producers like us. This negative factor may also lead to increasing capacity for ethanol production if new plants are built or existing plants expanded by those oil companies. Such a structural change in the market could result in a material adverse effect on our operations, cash flows and financial position.
There is scientific disagreement about the wisdom of policies encouraging ethanol production, which could result in changes in governmental policies concerning ethanol and reduce our profitability.
Some studies have challenged whether ethanol is an appropriate source of fuel and fuel additives, because of concerns about energy efficiency, potential health effects, cost and impact on air quality. Federal energy policy, as set forth in the 2005 Act and the 2007 Act, supports ethanol production. If a scientific consensus develops that ethanol production does not enhance our overall energy policy, our ability to produce and market ethanol could be materially and adversely affected.
Industry distress may adversely impact our ability to access credit necessary to operate.
The ethanol industry has faced significant industry distress in the past several years, with many producers filing bankruptcy. Furthermore, the overall capital markets in the United States have been less liquid and volatile. These conditions make it extremely difficult to secure credit, to refinance credit or negotiate forbearance terms with lenders. Although we have essentially fully drawn on our credit facility, we need to renegotiate the terms of our credit agreement. Given the market conditions, we may not be able to access credit or procure necessary waivers, which could cause us to have to reduce or shut down our operations and would have a material adverse effect on our operations and financial performance.
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., POET and Valero, among others, are capable of producing a significantly greater amount of ethanol than we produce. Furthermore, ethanol from certain Central American or Caribbean countries is eligible for tariff reduction or elimination upon importation to the United States. Ethanol imported from these Caribbean Basin countries may be a less expensive alternative to domestically-produced ethanol.
This competition also means that the supply of domestically-produced ethanol is at an all-time high. According to the RFA, as of December 2010, there were 191 operating ethanol refineries with a nameplate capacity of 13.1 billion gallons, another 21 non-operating facilities with 654 million gallons of capacity and 11 more plants under construction with additional capacity of 840 million gallons in the U.S. Total capacity from these 223 facilities would be 14.6 billion gallons at nameplate and at 110% of nameplate could produce over 16 billion gallons of
ethanol per year. Compared to the RFS2 standard for 2011, there is nearly five billion gallons of potential oversupply in the United States. Excess capacity in the ethanol industry will have an adverse impact on our operations, cash flows and general financial conditions. If the demand for ethanol does not grow the price of ethanol will likely remain low relative to costs. If excess capacity in the ethanol industry continues, the market price of ethanol may continue to decline to levels that are inadequate to generate sufficient cash flow to cover our costs. This could negatively impact our future profitability and decrease the value of our Membership Units and Members’ investment return.
Future demand for ethanol is uncertain and may be affected by changes to federal mandates, public perception and consumer acceptance, any of which could negatively affect demand for ethanol and our results of operations.
To support any expansion of the ethanol industry, domestic ethanol consumption must increase. Additionally, public opinion must be supportive of continued or increased mandates in order to maintain the preferred status of ethanol in public policy. The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline. At the present rate of expansion, it is probable that ethanol production will exceed levels set by federal mandate. Additionally, it is possible that ethanol production will exceed domestic blending capacity.
Ethanol production from corn has not been without controversy. There have been questions of overall economic efficiency and sustainability, given the industrialized and energy-intensive nature of modern corn agriculture. Additionally, ethanol critics frequently cite the moral dilemma of redirecting corn supplies from international food markets to domestic fuel markets. The controversy surrounding corn ethanol is dangerous to the industry because ethanol demand is largely dictated by federal mandate. If public opinion were to erode, it is possible that the federal mandates will lose political support and the ethanol industry will be left without a market.
Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, including the recently-released EPA regulations on the RFS program, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels and potentially depleting water resources. Some studies have suggested that corn-based ethanol is less efficient than ethanol produced from switchgrass or wheat grain and that it negatively impacts consumers by causing prices for dairy, meat and other foodstuffs from livestock that consume corn to increase. Additionally, ethanol critics contend that corn supplies are redirected from international food markets to domestic fuel markets. If negative views of corn-based ethanol production gain acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of federal mandates which would adversely affect the demand for ethanol. These views could also negatively impact public perception of the ethanol industry and acceptance of ethanol as an alternative fuel.
Beyond the federal mandates, there are limited markets for ethanol. Discretionary blending is an important secondary market. However, consumer acceptance of E85 fuels and flexible-fuel technology vehicles is needed before there will be any significant growth in market share. International markets offer possible opportunities. Ethanol has foreseeable applications as an aviation or locomotive fuel. Limited markets also exist for use of ethanol as an antiseptic, antidote or base compound for further chemical processing. Unfortunately, all these additional markets are undeveloped.
At present, we cannot provide any assurance that there will be any material or significant increase in the demand for ethanol beyond the increases in mandated gasoline blending. Increased production in the coming years is likely to lead to lower ethanol prices. Additionally, the increased production of ethanol could have other adverse effects as well. For example, the increased production could lead to increased supplies of by-products from the production of ethanol, such as distiller’s grains. Those increased supplies could lead to lower prices for those by-products. Also, the increased production of ethanol could result in a further increase in the demand for corn. This could result in higher prices for corn creating lower profits. There can be no assurance as to the price of ethanol, corn, or distiller’s grains in the future. Adverse changes affecting these prices may have a material adverse effect on our operations, cash flows and financial performance.
Competition from the advancement of alternative fuels may lessen the demand for ethanol and negatively impact our profitability, which could reduce the value of Members’ investment.
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 decrease fuel costs, lessen 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, causing a reduction in the value of Members’ investment.
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 and could reduce the value of Members’ investment.
Most ethanol 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. Although current technology is not sufficiently efficient to be competitive, a report dated August 25, 2000 by the U.S. Department of Energy entitled “Outlook for Biomass Ethanol Production and Demand” indicated that new conversion technologies may be developed in the future. If an efficient method of producing ethanol from cellulose-based biomass is developed, we may not be able to compete effectively. We do not believe it will be 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 and Members’ investment could lose value.
Depending on commodity prices, foreign producers may produce ethanol at a lower cost than we can, which may result in lower ethanol prices which would adversely affect our financial results.
There is a risk of foreign competition in the ethanol industry. Brazil is currently the second largest ethanol producer in the world. Brazil’s ethanol production is sugar-cane based, as opposed to corn based, and has historically been less expensive to produce. Other foreign producers may be able to produce ethanol at lower input costs, including costs of feedstock, facilities and personnel, than we can.
At present, there is a $0.54 per gallon tariff on foreign ethanol. However, this tariff might not be sufficient to deter overseas producers from importing ethanol into the domestic market, resulting in depressed ethanol prices. It is also important to note that the tariff on foreign ethanol is the subject of ongoing controversy and disagreement amongst lawmakers. Many lawmakers attribute increases in food prices to growth in the ethanol industry. They see foreign competition in ethanol production as a means of reducing food prices. Additionally, the tariff on ethanol is controversial internationally because critics contend that it diverts corn from export and impedes Latin American agricultural development.
Ethanol produced or processed in numerous countries in Central America and the Caribbean region is eligible for tariff reduction or elimination upon importation to the United States under a program known as the Caribbean Basin Initiative. Large multinational companies have expressed interest in building dehydration plants in participating Caribbean Basin countries, such as El Salvador, which would convert ethanol into fuel-grade ethanol for shipment to the United States Ethanol imported from Caribbean Basin countries may be a less expensive alternative to domestically produced ethanol. As a result, our business faces a threat from imported ethanol either from Brazil, even with the import tariff, or from a Caribbean Basin source. While transportation and infrastructure constraints may temper the market impact throughout the United States, competition from imported ethanol may
affect our ability to sell our ethanol profitably, which may have a material adverse effect on our operations, cash flows and financial position.
If significant additional foreign ethanol production capacity is created, such facilities could create excess supplies of ethanol on world markets, which may result in lower prices of ethanol throughout the world, including the United States. Such foreign competition is a risk to our business. Further, if the tariff on foreign ethanol is ever lifted, overturned, reduced, repealed or expires, our ability to profitably compete with low-cost international producers could be impaired. Any penetration of ethanol imports into the domestic market may have a material adverse effect on our operations, cash flows and financial position.
Our revenue from the sale of distiller’s grains depends upon its continued market acceptance as an animal feed.
Distiller’s grain is a co-product from the fermentation of various crops, including corn, to produce ethanol. The U.S. Food and Drug Administration’s (“FDA”) Center for Veterinary Medicine has expressed concern about potential animal and human health hazards from the use of distiller’s grains as an animal feed. As a result, the market value of this co-product could be diminished if the FDA were to introduce regulations that limit the sale of distiller’s grains in the domestic market or for export to international markets, which in turn would have a negative impact on our profitability. In addition, if public perception of distiller’s grains as an acceptable animal feed were to change or if the public became concerned about the impact of distiller’s grains in the food supply, the market for distiller’s grains would be negatively impacted, which would have a negative impact on our profitability.
Specifically, in the past, Escherichia coli (“E. coli”) outbreaks in beef cattle have been attributed to use of distiller’s grains as a cattle feed. At present, there is no conclusive causal relationship between E. coli and distiller’s grains. However, despite the current lack of scientific evidence, this continued controversy could have an adverse impact on distiller’s grains markets. Any connection, whether based on scientific evidence or popular opinion, between distiller’s grains and E. coli could have a material adverse effect on our operations, cash flows and financial performance, a result which is unlikely to change even if we enter into a more comprehensive arrangement with Tenaska.
The price of distiller’s grains is affected by the price of other commodity products, such as soybeans and corn, and decreases in the price of these commodities could decrease the price of distiller’s grains, which will decrease the amount of revenue we may generate.
Distiller’s grains compete with other protein-based animal feed products. The price of distiller’s 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 and corn, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distiller’s grains. Decreases in the price of distiller’s grains will result in lower revenues, a result which is unlikely to change even if we enter into a more comprehensive arrangement with Tenaska.
RISKS ASSOCIATED WITH GOVERNMENT REGULATION AND SUBSIDIZATION
Nebraska state producer incentives are unavailable to us, which places us at a competitive disadvantage.
Although the Nebraska legislature has historically provided incentives to ethanol producers in Nebraska, and may do so in the future, we do not qualify for any existing incentives. Only plants that were in production on June 30, 2004 are eligible for such incentives, which authorize a producer to receive up to $2.8 million of tax credits per year for up to eight years.
The ethanol industry is highly dependent on government usage mandates affecting ethanol production and favorable tax benefits for ethanol blending and any changes to such regulation could adversely affect the market for ethanol and our results of operations.
The domestic market for ethanol is largely dictated by federal mandates for blending ethanol with gasoline. The RFS mandate level for 2011 of 13.95 billion gallons approximates current domestic production levels. Future demand will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline versus ethanol, taking into consideration the blender’s credit and the RFS. Any significant increase in production capacity beyond the RFS level might have an adverse impact on ethanol prices. Additionally, the RFS mandate with respect to ethanol derived from grain could be reduced or waived entirely. A reduction or waiver of the RFS mandate could adversely affect the prices of ethanol and our future performance.
The American Jobs Creation Act of 2004 created the VEETC, which was renewed in December of 2010 and expires December 31, 2011. Referred to as the blender’s credit, VEETC provides companies with a tax credit to blend ethanol with gasoline. The Food, Conservation and Energy Act of 2008 (the “2008 Farm Bill”), amended the amount of tax credit provided under VEETC to 45 cents per gallon of pure ethanol and 38 cents per gallon for E85, a blended motor fuel containing 85% ethanol and 15% gasoline. The elimination or further reduction of VEETC or other federal tax incentives to the ethanol industry would likely have a material adverse impact on our business by reducing demand and price for the ethanol we produce.
Federal law mandates the use of oxygenated gasoline. If these mandates are repealed, the market for domestic ethanol would be diminished significantly. Additionally, flexible-fuel vehicles receive preferential treatment in meeting corporate average fuel economy, or CAFE, standards. However, high blend ethanol fuels such as E85 result in lower fuel efficiencies. Absent the CAFE preferences, it may be unlikely that auto manufacturers would build flexible-fuel vehicles. Any change in these CAFE preferences could reduce the growth of E85 markets and result in lower ethanol prices.
To the extent that such federal or state laws are modified, the demand for ethanol may be reduced, which could negatively and materially affect our ability to operate profitably. There has been an increase in the number of claims against the use of ethanol as an alternative energy source. Many of such claims attempt to draw a link between recently increasing global food prices and the use of corn to produce ethanol. Others claim that the production of ethanol requires too much energy. Such claims have led some, including members of Congress, to urge the modification of current government policies which affect the production and sale of ethanol in the United States. Similarly, several states which currently have laws which affect the production and sale of ethanol, such as mandated usage of ethanol, have proposed to modify or eliminate such mandates. To the extent that such state or federal laws were modified, the demand for ethanol may be reduced, which could negatively and materially affect our ability to operate profitably.
Increased federal support of cellulosic ethanol may result in reduced incentives to corn-derived ethanol producers.
Recent legislation, such as the American Recovery and Reinvestment Act of 2009 and the 2007 Act, provides numerous funding opportunities in support of cellulosic ethanol, which is obtained from other sources of biomass such as switchgrass and fast growing poplar trees. In addition, the amended RFS mandates an increasing level of production of biofuels that are not derived from corn. Federal policies suggest a long-term political preference for cellulosic processes using alternative feedstocks such as switchgrass, silage, wood chips or other forms of biomass. Cellulosic ethanol has a smaller carbon footprint because the feedstock does not require energy-intensive fertilizers and industrial production processes. Additionally, cellulosic ethanol is favored because it is unlikely that foodstuff is being diverted from the market. Several cellulosic ethanol plants are under development. As research and development programs persist, there is the risk that cellulosic ethanol could displace corn ethanol. In addition, any replacement of federal incentives from corn-based to cellulosic-based ethanol production may reduce our profitability.
We handle potentially hazardous materials in our businesses. If environmental requirements become more stringent or if we experience unanticipated environmental hazards, we could be subject to significant costs and liabilities.
A significant part of our business is regulated by environmental laws and regulations, including those governing the labeling, use, storage, discharge and disposal of hazardous materials. Because we use and handle hazardous substances in our businesses, changes in environmental requirements or an unanticipated significant adverse environmental event could have a material adverse effect on our business. There is no assurance that we have been, or will at all times be, in compliance with all environmental requirements, or that we will not incur material costs or
liabilities in connection with these requirements. Private parties, including current and former employees, could bring personal injury or other claims against us due to the presence of, or exposure to, hazardous substances used, stored or disposed of by us, or contained in our products. In addition, changes to environmental regulations may require us to modify our existing plant and processing facilities and could significantly increase the cost of those operations.
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 will be subject to regulations on emissions from the EPA and the NDEQ. The EPA’s and NDEQ’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.
As discussed elsewhere in this report, we must maintain a variety of permits and approvals from federal, state and local governmental authorities. Our failure to maintain any one of those permits or approvals could materially harm our financial performance.
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. As our business grows, we will have to develop and 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 may also restrict our production and distribution operations. We could incur significant costs to comply with applicable laws and regulations as production and distribution activity increases. Protection of the environment will require us to incur expenditures for equipment or processes.
We could be subject to environmental nuisance or related claims by employees, property owners or residents near the proposed ethanol plant 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 should mitigate 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 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 ethanol plant 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 Nebraska 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 our ethanol plant profitably, which may decrease the value of our Membership Units and Members’ investment return.
Our business is affected by the regulation of GHG, and climate change. New climate change regulations could impede our ability to successfully operate our business.
Our ethanol plant emits carbon dioxide as a by-product of the ethanol production process. On February 3, 2010, the EPA released its final regulations on the RFS program, or RFS 2. We believe these final regulations grandfather our ethanol plant at its current operating capacity, though expansion of our ethanol plant would need to meet a threshold of a 20% reduction in GHG emissions from a baseline measurement for the ethanol over current capacity to be eligible for the RFS 2 mandate. Additionally, legislation is pending in Congress on a comprehensive carbon dioxide regulatory scheme, such as a carbon tax or cap-and-trade system. If we sought to expand capacity at our ethanol plant, we would have to apply for additional permits, install advanced technology such as corn oil extraction, or reduce drying of certain amounts of distiller’s grains. We may also be required to install carbon dioxide mitigation equipment or take other steps unknown to us at this time in order to comply with other future law or regulation. Compliance with future law or regulation of carbon dioxide, or if we choose to expand capacity, compliance with then-current regulation of carbon dioxide could be costly and may prevent us from operating our ethanol plant as profitably, which may have a material adverse impact on our operations, cash flows and financial position.
RISKS RELATED TO TAX ISSUES IN A LIMITED LIABILITY COMPANY
MEMBERS SHOULD CONSULT THEIR OWN TAX ADVISOR CONCERNING THE IMPACT THAT THEIR OWNERSHIP IN US MAY HAVE ON THEIR FEDERAL INCOME TAX LIABILITY AND THE APPLICATION OF STATE AND LOCAL INCOME AND OTHER TAX LAWS TO OWNERSHIP OF UNITS.
IRS classification of us as a corporation rather than as a partnership would result in higher taxation and reduced profits, which could reduce the value of an investment in us.
We are a Nebraska limited liability company that has elected to be taxed as a partnership for federal and state income tax purposes, with income, gain, loss, deduction and credit passed through to our Members. However, if for any reason the Internal Revenue Service (“IRS”) would successfully determine that we should be taxed as a corporation rather than as a partnership, we would be taxed on our net income at rates of up to 35 percent for federal income tax purposes, and all items of our income, gain, loss, deduction and credit would be reflected only on our tax returns and would not be passed through to our Members. If we were to be taxed as a corporation for any reason, distributions we make to our Members will be treated as ordinary dividend income to the extent of our earnings and profits, and the payment of distributions would not be deductible by us, thus resulting in double taxation of our earnings and profits. If we pay taxes as a corporation, we will have less cash to distribute to our Members.
The IRS may classify an investment in us as passive activity income, resulting in a Member’s inability to deduct losses associated with an investment in us.
It is likely that the IRS will classify an interest in us as a passive activity. If a Member is either an individual or a closely held corporation, and if a Member’s interest is deemed to be “passive activity,” then such Member’s allocated share of any loss we incur will be deductible only against income or gains such Member is earned from other passive activities. Passive activity losses that are disallowed in any taxable year are suspended and may be carried forward and used as an offset against passive activity income in future years. These rules could restrict a Member’s ability to currently deduct any of our losses that are passed through.
Income allocations assigned to Units may result in taxable income in excess of cash distributions, which means a Member may have to pay income tax on our Units with personal funds.
Members will pay tax on their allocated shares of our taxable income. Members may receive allocations of taxable income that result in a tax liability that is in excess of any cash distributions we may make to the Members. Among other things, this result might occur due to accounting methodology, lending covenants contained in the Facility that restrict our ability to pay cash distributions, or our decision to retain the cash generated by the business
to fund our operating activities and obligations. Accordingly, Members may be required to pay some or all of the income tax on their allocated shares of our taxable income with personal funds.
If our allocations of income and deduction are not respected by the IRS, Members may be required to recognize additional taxable income.
We allocate items of income, gain, loss, deduction or credit, if any, consistent with the requirements of Code Section 704(b) of the Code. We maintain capital accounts in a manner which falls within the “safe harbor” standards for substantial economic effect under Treasury Regulations adopted under the Code, and we believe that our allocations of income and deduction are consistent with each Member’s interest in the Company and will be respected by the IRS. Nevertheless, if our allocations of income and deduction are not respected by the IRS, the Members may be required to recognize additional taxable income.
Risk of IRS audit.
An entity organized as a limited liability company and taxed as a partnership is likely to be subject to a greater risk of audit by the IRS than are other business entities. Certain tax aspects of our operations may be challenged upon audit by the IRS. Any adjustment resulting from an audit by the IRS also could result in adjustments to the tax returns of an individual Member and may lead to an examination of other items unrelated to the Company in such returns or an examination of prior tax returns of the Members. Moreover, we could incur substantial legal and accounting costs in connection with any challenge by the IRS of the position taken by us on our tax returns regardless of the outcome of such a challenge.
The foregoing is not intended to be an exhaustive discussion of all the risks that may be associated with an investment in us. Moreover, because there are many inherent risks that may not be anticipated by us, you should be aware that there are additional risks inherently associated with our Company and which are not presently foreseen by us.
Item 2.
Item 2.
Properties.
Our plant requires the use of four parcels of property. Each parcel is vital in bringing our ethanol product to market. The following is a brief description of each parcel, and how it relates to our ethanol production procedure. We believe that all of our properties are adequately covered by insurance. All of our properties are subject to first priority security interests we granted to our lender to secure our repayment of our obligations under our credit facility.
Plant Site
This 73.28 acre parcel of land is devoted to our ethanol production and is located in the City of Atkinson, Holt County, Nebraska. We own this property in fee and do not have any indebtedness respecting it. The nearest rail road access to this property is approximately 16 miles away in O’Neill, Nebraska. The cost to extend rail track to our production facility was excessive when compared to the operating costs of trucking our ethanol product to O’Neill. Therefore, the other three properties are required for delivery of our product to market.
Transload Facility
Our transload facility, on 10.97 acres, is in the City of O’Neill, Holt County, Nebraska. We own this property in fee. Trucked from our Atkinson production facility, our ethanol product is loaded into a 1,000,000 gallon storage tank at our transload facility and from that tank into rail cars.
Cowboy Trail
The Cowboy Trail is an abandoned rail road track that has been converted to a public park riding/walking trail across Holt County, Nebraska. It is owned by the State of Nebraska, Nebraska Game and Parks Commission (“NGP”). A portion of The Cowboy Trail separates our Transload Facility from the nearest end of the active rail track, which is owned and operated by NENE.
The NGP has authorized our use by lease of approximately one and a half miles of the Cowboy Trail (the “Property”) on which we have constructed a rail spur to connect with the NENE rail track. We entered into the Track Agreement with the NGP, under which we lease the portion of the Cowboy Trail property to use as a rail spur track over which we transport our ethanol. The Track Agreement has a term of ten years and will automatically renew for additional ten year terms unless one party notifies the other at least nine months prior to the expiration date of its intention to not renew. The annual rental cost to the Company is $10,000 for use of the Property. Additionally, we are responsible for any public assessments respecting the maintenance or use of the Property. The Track Agreement provides that we are responsible to maintain the track on the Property and are solely responsible for our operations on the Property and complying with applicable laws regarding our use of the Property.
O’Neill NENE Property
NENE owns property located in the City of O’Neill, Holt County, Nebraska. As this property approaches the center of O’Neill, Nebraska, our rail diverges off the Cowboy Trail, and runs through the center of town in an easterly direction for approximately six blocks. We have entered into the NENE Track Agreement with NENE. Under the NENE Track Agreement, NENE allows us to construct, maintain and operate the Track over NENE’s property. The Track links with existing rail owned and operated by NENE. The NENE Track Agreement has an initial term of five years and will automatically continue thereafter until terminated by either party upon 30 days’ notice. The NENE Track Agreement may also be terminated if NENE is authorized to abandon its line which connects to the Track, or if NENE is no longer able to operate over the Track. Under the NENE Track Agreement, we are responsible for, among other things, maintaining the Track; and NENE has agreed to provide rail service to transport our ethanol over the Track.
Item 3.
Item 3.
Legal Proceedings.
We may, from time to time, be named as a defendant in legal proceedings related not only to tort or contract disputes, but also workers compensation claims and other claims and disputes as well. On August 12, 2010, the lender (“TIF Lender”) of the tax increment financing note, the proceeds of which we received in September 2007 (“TIF Note”), filed a lawsuit against us in the District Court of Douglas County, Nebraska alleging that we failed to make certain payments due under the TIF Note and failed to maintain the required debt service reserve fund. In addition, the lawsuit stated that the TIF Lender accelerated the maturity of the TIF Note. The TIF Lender sought in the lawsuit repayment of $7,039,126 due as of August 9, 2010, plus such additional amounts as become due and owing under the TIF Note, with interest accruing after August 9, 2010 at the rate of 9.5% until the judgment is paid. It is uncertain when or how the court will rule on the several pending motions. Discovery is ongoing and no trial date has been set.
Item 4.
Item 4.
Reserved
PART II
Item 5.
Item 5.
Market for Common Equity, Related Member Matters, and Issuer Purchases of Equity Securities.
There is no public trading market for our Membership Units, and our Operating Agreement contains significant restrictions on the transfer of our Units to ensure that the Company is not deemed a “publicly traded partnership” and thus taxed as a corporation. Additionally, pursuant to the Operating Agreement, the Board has developed a Unit Transfer Policy which imposes conditions on the transfer of Membership Units.
As of March 15, 2011, there were 1,045 and 36 holders of record of our Common and Preferred Membership Units, respectively.
Subject to the provisions of the Act, distributions are payable at the discretion of our Board of Directors as provided in our Operating Agreement. The Board has no obligation to distribute profits, if any, to Members. We have not declared or paid any distributions on our Membership Units to date, and distributions on our Common Units are first subject to preferential distributions on our Class A Preferred Units. We anticipate distributing a
portion of our net cash flow, if any, to our Members in proportion to the Membership Units held and in accordance with our Operating Agreement and any loan covenants to which we may then be subject. By net cash flow, we mean our gross cash proceeds received less any portion, as determined by our Directors in their sole discretion, used to pay or establish reserves for our expenses, debt payments, capital improvements, replacements and contingencies. If our financial performance and loan covenants permit, our Board of Directors will consider cash distributions at times and in amounts that will permit Unit holders to make income tax payments. However, the Board may elect to retain future profits to provide operational financing for the plant, debt retirement and possible plant expansion.
Item 6.
Item 6.
Selected Financial Data
Not applicable.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Information in response to this Item is incorporated by reference to pages 5 through 16 of the 2010 Annual Report.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Information in response to this Item is incorporated by reference to pages through of the 2010 Annual Report.
Item 9.
Item 9. Change In and Disagreements With Accountants on Accounting and Financial Disclosure.
Information in response to this Item is incorporated by reference to page 14 of the 2010 Annual Report.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, including our President and Chief Executive Officer (our principal executive officer) along with our Chief Financial Officer (our principal financial officer) have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amended, the “Exchange Act”), as of December 31, 2010. Based upon this review and evaluation, these officers believe that our 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”).
Our management, including our principal executive officer and our principal financial officer, have reviewed and evaluated any changes in our internal control over financial reporting that occurred in our fourth quarter of fiscal 2010 and there has been no change that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, and effected by our Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP and includes policies and procedures that:
(i)
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our financial transactions,
(ii)
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our revenues and expenditures are being made only in accordance with authorizations of our management and directors, and
(iii)
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
Management assessed our internal control over financial reporting as of December 31, 2010. Management based its assessment on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management’s assessment included an evaluation of such elements as the design and operating effectiveness of key financial reporting controls, process documentation, accounting policies and our overall control environment.
Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2010. This annual report is not required to include an attestation report of our independent registered public accounting firm regarding our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
Information in response to this Item is incorporated by reference to the information under the captions “Election of Directors” and “Corporate Governance” of the 2011 Proxy Statement.
Item 11.
Item 11. Executive Compensation.
Information in response to this Item is incorporated by reference to the information under the captions “Compensation of Directors and Executive Officers,” “Summary Compensation Table” and “Director Compensation” of the 2011 Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Member Matters.
Information in response to this Item is incorporated by reference to the information under the caption “Voting, Voting Securities and Principal Unit Holders” of the 2011 Proxy Statement.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information in response to this Item is incorporated by reference to the information under the caption “Certain Relationships and Related Party Transactions” of the 2011 Proxy Statement.
Item 14.
Item 14. Principal Accountant Fees and Services
Information in response to this Item is incorporated by reference to the information under the caption “Independent Registered Public Accounting Firm Information” of the 2011 Proxy Statement.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)
Documents filed as part of this Report in Exhibit 13.1:
Balance Sheets as of December 31, 2010 and 2009
Statements of Operations for the years ended December 31, 2010 and 2009
Statements of Changes in Members' Equity for the years ended December 31, 2010 and 2009
Statements of Cash Flows for the years ended December 31, 2010 and 2009
Notes to Financial Statements
(b)
The following exhibits are filed herewith or incorporated by reference as set forth below:
Exhibit number 10(ii).34 is a management contract.
2.
Omitted - Inapplicable
3(i).1
Articles of Organization and First Amendment thereto (incorporated by reference to Exhibit 3.1 of the Registrant’s Registration Statement on Form SB-2, filed December 15, 2005)
3(i).2
Second Amendment to Articles of Organization (incorporated by reference to Exhibit 3 (i) of Report on Form 8-K filed January 23, 2007).
4(i).1
Third Amended and Restated Operating Agreement dated March 4, 2009 (incorporated by reference to Exhibit 3(ii).1 of Report on Form 8-K filed March 9, 2009)
4(i).2
Form of Membership Unit Certificate (incorporated by reference to Exhibit 4.1 of the Registrant’s Registration Statement on Form SB-2, filed December 15, 2005)
4(ii).1
Master Credit Agreement dated February 14, 2007 with Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.9 of Report on Form 8-K filed February 20, 2007)
4(ii).2
First Supplement to the Master Credit Agreement dated February 14, 2007 with Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.10 of Report on Form 8-K filed February 20, 2007)
4(ii).3
Second Supplement to the Master Credit Agreement dated February 14, 2007 with Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.11 of Report on Form 8-K filed February 20, 2007)
4(ii).4
Security Agreement dated February 14, 2007 with Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.12 of Report on Form 8-K filed February 20, 2007)
4(ii).5
Deed of Trust, Security Agreement, Assignment of Leases and Rents and Fixture Financing Statement dated February 14, 2007 in favor of Lawyers Title Insurance Corporation for the benefit of Farm Credit Services of Grand Forks, FLCA (incorporated by reference to Exhibit 10.13 of Report on Form 8-K filed February 20, 2007)
4(ii).6
Purchase Letter dated June 19, 2007 from NEDAK Ethanol, LLC to the City of Atkinson, Nebraska (incorporated by reference to Exhibit 10.2 of Report on Form 8-K filed June 25, 2007)
4(ii).7
Loan Agreement dated June 19, 2007 between NEDAK Ethanol, LLC and Arbor Bank (incorporated by reference to Exhibit 10.3 of Report on Form 8-K filed June 25, 2007)
4(ii).8
Security Agreement dated June 19, 2007 made by NEDAK Ethanol, LLC in favor of Arbor Bank (incorporated by reference to Exhibit 10.4 of Report on Form 8-K filed June 25, 2007)
4(ii).9
Promissory Note dated June 19, 2007 made by NEDAK Ethanol, LLC in favor of Arbor Bank (incorporated by reference to Exhibit 10.5 of Report on Form 8-K filed June 25, 2007)
4(ii).10
Redevelopment Contract dated June 19, 2007 between NEDAK Ethanol, LLC and the City of Atkinson, Nebraska (incorporated by reference to Exhibit 10.6 of Report on Form 8-K filed June 25, 2007)
10(i).1
Precedent Agreement dated September 27, 2007 between NEDAK Ethanol, LLC and Kinder Morgan Interstate Gas Transmission LLC (incorporated by reference to Exhibit 10.2 of Report on Form 8-K filed November 2, 2007)
10(i).2
Plant Operating Agreement dated July 11, 2007 and amended July 16, 2007, between NEDAK Ethanol, LLC and HWS Energy Partners, L.L.C. (incorporated by reference to Exhibit 10.1 of Report on Form 8 K filed July 16, 2007). Portions of the Agreement have been omitted pursuant to a request for confidential treatment.
10(i).3
Base Agreement dated February 7, 2006 between NEDAK Ethanol, LLC and Cornerstone Energy, Inc. (incorporated by reference to Exhibit 10.5 of Pre-Effective Amendment No. 3 to the Registrant’s Registration Statement on Form SB-2, filed June 5, 2006)
10(i).4
Firm Transportation Service Agreement dated May 8, 2006 with Kinder Morgan Interstate Gas Transmission LLC (incorporated by reference to Exhibit 10.2 of Report on Form 8-K filed February 20, 2007)
10(i).5
Ethanol Marketing Agreement dated November 15, 2006 with Eco-Energy, Inc. (incorporated by reference to Exhibit 10.3 of Report on Form 8-K filed February 20, 2007)
10(i).6
Grain Procurement Agreement dated December 14, 2006 with J.E. Meuret Grain Co., Inc. (incorporated by reference to Exhibit 10.4 of Report on Form 8-K filed February 20, 2007)
10(i).7
Marketing Agreement dated January 22, 2007 with Distillers Grain Services LLC (incorporated by reference to Exhibit 10.5 of Report on Form 8-K filed February 20, 2007)
10(i).8
Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T Corporation (incorporated by reference to Exhibit 10.2 of Report on Form 10-QSB filed November 20, 2006). Portions of the Contract have been omitted pursuant to a request for confidential treatment.
10(i).9
Negotiated Rate Agreement for Distribution Transportation Services dated June 5, 2006 between NEDAK Ethanol, LLC and Kinder Morgan Inc. (incorporated by reference to Exhibit 10(i).12 of Report on Form 10-KSB filed on April 2, 2007)
10(i).10
Option to Lease Real Estate Agreement dated January 15, 2007 with Dennis Grain, Inc. (incorporated by reference to Exhibit 10(i).13 of Report on Form 10-KSB filed on April 2, 2007)
10(i).11
Transportation Service Agreement on Transporter’s Distribution System dated June 15, 2006 between NEDAK Ethanol, LLC and Kinder Morgan Inc. (incorporated by reference to Exhibit 10(i).14 of Report on Form 10-KSB filed on April 2, 2007)
10(i).12
Industry Track Agreement dated July 24, 2007 between NEDAK Ethanol, LLC and the Nebraska Northeastern Railway Company (incorporated by reference to Exhibit 10.2 on Form 8-K filed July 25, 2007)
10(i).13
NEDAK Track Lease Agreement dated June 19, 2007 between NEDAK Ethanol, LLC and the Nebraska Game and Parks Commission (incorporated by reference to Exhibit 10.1 on Form 8-K filed June 25, 2007)
10(i).14
Amendment dated March 5, 2008 between NEDAK Ethanol, LLC and SourceGas Distribution, LLC (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed March 13, 2008)
10(i).15
Second Letter of Commitment and Intent between NEDAK Ethanol, LLC and Delta-T Corporation dated August 4, 2008 (incorporated by reference to Exhibit 10.4 of Report on Form 8-K filed August 6, 2008)
10(i).16
Amendment No. 3 to Engineering, Procurement and Construction Services Fixed Price Contract between NEDAK Ethanol, LLC and Delta-T Corporation dated April 11, 2008 (incorporated by reference to Exhibit 10.3 of Report on Form 8-K filed April 15, 2008)
10(i).17
Guaranty dated April 11, 2008 made by Bateman Litwin NV in favor of NEDAK Ethanol, LLC (incorporated by reference to Exhibit 10.9 of Report on Form 8-K filed April 15, 2008)
10(i).18
Deed of Trust dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of Delta-T Corporation (incorporated by reference to Exhibit 10.10 of Report on Form 8-K filed April 15, 2008)
10(i).19
Third Supplement and Forbearance to the Master Credit Agreement, dated April 11, 2008 between NEDAK Ethanol, LLC and AgCountry Farm Credit Services, FCA (f/k/a Farm Credit Services of Grand Forks, FLCA) (incorporated by reference to Exhibit 10.11 of Report on Form 8-K filed April 15, 2008)
10(i).20
Form of Guaranty in favor of AgCountry Farm Credit Services, FCA (incorporated by reference to Exhibit 10.12 of Report on Form 8-K filed April 15, 2008)
10(i).21
Promissory Note dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of Delta T Corporation (incorporated by reference to Exhibit 10.13 of Report on Form 8-K filed April 15, 2008)
10(i).22
10(i).23
Collateral Assignment dated April 11, 2008 made by NEDAK Ethanol, LLC in favor of AgCountry Farm Credit Services, FCA (incorporated by reference to Exhibit 10.14 of Report on Form 8-K filed April 15, 2008)
Control Agreement dated April 11, 2008 between AgCountry Farm Credit Services, FCA, NEDAK Ethanol, LLC and Jerome Fagerland (incorporated by reference to Exhibit 10.15 of Report on Form 8-K filed April 15, 2008)
10(i).24
Fourth Supplement and Forbearance Agreement to the Master Credit Agreement between NEDAK Ethanol, LLC and AgCountry Farm Services, FLCA dated March 27, 2009 (incorporated by reference to Exhibit 10.2 of Report on Form 10-Q filed March 31, 2009)
10(i).25
Facility Agreement between NEDAK Ethanol, LLC and Kinder Morgan Inc. dated June 15, 2006 (incorporated by reference to Exhibit 10.8 of Report on Form 8-K filed February 20, 2007)
10(i).26
Transportation Agreement between NEDAK Ethanol, LLC and Western Oil Trans Inc. dated July 19, 2007 (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed July 25, 2007)
10(i).27
Precedent Agreement between NEDAK Ethanol, LLC and Kinder Morgan Interstate Gas Transmission LLC dated September 27, 2007 (incorporated by reference to Exhibit 10.2 of Report on Form 8-K filed November 2, 2007)
10(i).28
Change Orders dated October 25, 2006, November 20, 2006 and December 14, 2006 to Engineering, Procurement and Construction Services Fixed Price Contract dated August 9, 2006 with Delta-T Corporation (incorporated by reference to Exhibit 10.6 of Report on Form 8-K filed February 20, 2007).
10(i).29
Form of Amended Promissory Note made by NEDAK Ethanol, LLC in favor of certain Directors (incorporated by reference to Exhibit 10.1 of Report on Form 10-Q filed May 15, 2009).
10(i).30
Amendment Number Three to Engineering, Procurement and Construction Services Fixed Price Contract between Delta-T Corporation and NEDAK Ethanol, LLC (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed September 4, 2009).
10(i).31
Fifth Supplement and Forbearance Agreement to Master Credit Agreement entered into as of September 30, 2009 by and between NEDAK Ethanol, LLC AgCountry Farm Credit Services FLCA (formerly Farm Credit Services of Grand Forks, FLCA) (incorporated by reference to Exhibit 10.1 of Report on Form 10-Q filed October 30, 2009).
10(i).32
Forbearance Agreement dated December 31, 2009 between NEDAK Ethanol, LLC and Arbor Bank (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed January 5, 2010).
10(i).33
Settlement Agreement and Mutual Release Between Delta-T Corporation, Bateman Engineering Inc., Bateman-Litwin N.V. and NEDAK Ethanol, LLC entered on March 19, 2010 (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed March 24, 2010).
10(ii).34
Employment Agreement dated October 30, 2007 between NEDAK Ethanol, LLC and Jerome Fagerland (incorporated by reference to Exhibit 10.1 of Report on Form 8-K filed November 2, 2007)
10(i).35
Sixth Supplement and Forbearance Agreement to the Master Credit Agreement dated July 30, 2010 by and among NEDAK Ethanol, LLC and AgCountry Farm Credit Services, FLCA (incorporated by reference to Exhibit 10.1 of Report on Form 10-Q filed August 13, 2010).
10(i).36
Seventh Supplement and Forbearance Agreement to the Master Credit Agreement effective February 1, 2011 by and among NEDAK Ethanol, LLC and AgCountry Farm Credit Services, FLCA.
11.
Omitted - Inapplicable
12.
Omitted - Inapplicable
13.1
Annual Report to Security Holders
14.
Code of Ethics (incorporated by reference to Exhibit 14 of Annual Report on Form 10-KSB filed April 1, 2008).
16.
Omitted - Inapplicable
17.
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 Chief Executive Officer.
31.2
Rule 15d-14(a) Certification (pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) executed by Chief Financial Officer.
32.1.
Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Chief Executive Officer.
32.2
Rule 15d-14(b) Certifications (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) executed by the Chief Financial Officer.
33.
Omitted - Inapplicable
34.
Omitted - Inapplicable
35.
Omitted - Inapplicable
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NEDAK ETHANOL, LLC
By: /s/ Jerome Fagerland
(Principal executive officer)
Date: March 31, 2011
By: /s/ Timothy Borer
(Principal financial and accounting officer)
Date: March 31, 2011
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Name
Date
Name
Date
/s/ Jeff Lieswald
/s/ Todd Shane
Jeff Lieswald, Director
March 31, 2011
Todd Shane, Director
March 31, 2011
/s/ Kirk Shane
Kirk Shane, Director
March 31, 2011
Gerald Winings, Director
March 31, 2011
/s/ Everett Vogel
/s/ Richard Bilstein,
Everett Vogel, Director, Chairman of the Board, Vice President
March 31, 2011
Richard Bilstein, Director, Vice Chairman of the Board
March 31, 2011
/s/ Robert Olson
Kenneth Osborne, Director
March 31, 2011
Robert Olson, Director
March 31, 2011
/s/ Steve Dennis
Clayton Goeke, Director
March 31, 2011
Steve Dennis, Director
March 31, 2011
/s/ Paul Corkle
Paul Corkle, Director
March 31, 2011
Paul Seger, Director
March 31, 2011
/s/ Jerome Fagerland
/s/ Timothy Borer
Jerome Fagerland, Director
March 31, 2011
Timothy Borer, Director
March 31, 2011