Item 1. Business.
Overview
Northern Growers, LLC (“Northern Growers”) is a South Dakota limited liability company that owns and manages a 77.16% interest in its subsidiary, Northern Lights Ethanol, LLC (“Northern Lights”). Broin Investments I, LLC owns the remaining minority interest in Northern Lights. (Northern Growers and Northern Lights are also referred to collectively in this report as “we,” “our,” or “us”). Northern Growers is owned by 859 members who principally reside in South Dakota, Minnesota, and immediately surrounding states. Northern Growers’ business primarily consists of owning and managing its interest in Northern Lights, a South Dakota limited liability company, which owns and operates an ethanol plant near Big Stone City, South Dakota (the “plant”).
Reorganization
Northern Growers was originally formed as a South Dakota cooperative on April 14, 2000. The purpose of the cooperative was to own and manage a 77.16% interest in Northern Lights and to supply corn to the plant. As a cooperative, Northern Growers was entitled to single-level, pass-through tax treatment on income generated through members’ patronage. This allowed Northern Growers to pass income onto its members in the form of distributions without first paying taxes at the company level, similar to the taxation of a partnership. As the cooperative’s board of directors became aware of certain disadvantages in remaining as a cooperative, the board of directors approved a plan to reorganize into a South Dakota limited liability company.
The reorganization from a cooperative to a limited liability company became effective on April 1, 2003 following approval of the reorganization by Northern Growers’ members. The transaction was an exchange of interests whereby the assets and liabilities of the cooperative were transferred for capital units of the newly formed limited liability company, Whetstone Ethanol, LLC. The capital units were distributed to Northern Growers’ members upon dissolution of the cooperative at a rate of one capital unit of the limited liability company for each share of equity stock owned in the cooperative. The distribution of capital units to the members was registered under the Securities Act of 1933. Upon completion of the reorganization, the name, Whetstone Ethanol, LLC, was changed to Northern Growers, LLC. As a limited liability company, Northern Growers elected to be taxed as a partnership in order to retain its historic single-level income tax treatment at the member level.
The Plant
The plant is a dry-mill processing facility, located immediately adjacent to Big Stone Plant near the city of Big Stone City in Grant County, South Dakota. The plant was designed and built in July 2002 by Broin and Associates, Inc. of Sioux Falls, South Dakota, a division of the Broin Companies, LLC, specializing in the design and construction of ethanol plants. The plant was originally built with a name-plate production capacity of 40 million gallons of ethanol annually. In June 2007, Broin and Associates expects to complete the construction of a major expansion of the plant, increasing the name-plate capacity to 75 million gallons annually. The plant’s day-to-day operations are managed by Broin Management, LLC, a division of the Broin Companies, LLC, specializing in the management and operation of ethanol plants.
The plant is essentially a fermentation plant. The corn supplied to the plant is ground and then mixed with water to form a mash. The mash is heated and enzymes added to convert the starch into fermentable sugars. Fermentation occurs when yeast is added to convert the sugars into alcohol and carbon dioxide. Fermentation produces a mixture called “beer,” which contains about 10% alcohol and 90% water. The “beer” is then boiled in a distillation column to separate the water, resulting in ethyl alcohol that is 90% to 95% pure. The mixture then goes through a dehydration process, which increases the alcohol content to 99% or greater. This product is then mixed with a certified denaturant to make the product unfit for human consumption and commercially saleable.
Principal Products
The principal products produced at our plant are fuel grade ethanol and distillers grains.
Ethanol
Ethanol is ethyl alcohol. Ethanol is produced from starch or sugar-based feed products such as corn, potatoes, wheat, and sorghum, as well as from agricultural waste products including sugar, rice straw, cheese whey, beverage wastes and forestry and paper wastes. Historically, corn has been the primary source of producing ethanol because of its relatively low cost, wide availability and ability to produce large quantities of carbohydrates that convert into glucose more easily than other products. Today, approximately 90% of the ethanol produced in the United States is produced from corn.
Ethanol is used for three primary purposes: 1) as an oxygenated fuel additive; 2) as an octane enhancer in fuels; and 3) as a non-petroleum based gas substitute. Approximately 95% of all ethanol is used for blending with unleaded gasoline and other fuel products. Ethanol has been utilized as a fuel additive since the late 1970s when its value as a product extender for gasoline was discovered during the OPEC oil embargo crisis. In the 1980s, ethanol began to see widespread use as an octane enhancer, replacing other environmentally harmful components in gasoline such as lead and benzene. Ethanol’s use as an oxygenate continued to increase with the passage of the Clean Air Act Amendments of 1990, which required the addition of oxygenates to gasoline in the nation’s most polluted areas. Because ethanol contains approximately 35% oxygen, its combination with gasoline increases the percentage of oxygen in gasoline. As a result, the gasoline burns cleaner and releases less carbon monoxide and other exhaust emissions into the atmosphere.
Distillers Grains
A principal co-product of the ethanol production process is distillers grains. Distillers grains are a high protein, high energy feed supplement marketed primarily to the dairy, beef, sheep, swine, and poultry industries. It is a popular animal feed supplement, with millions of tons produced in North America annually. Most of the distillers grains produced in the United States are sold for use in animal feeds within the continental United States, and a small percentage is exported primarily to Canada, Mexico and Europe.
Dry mill ethanol processing produces generally three forms of distillers grains, all of which differ in moisture content and shelf life: 1) dried distillers grains with solubles (DDGS); 2) distillers wet grains or “wet cake”; and 3) modified distillers grains. Distillers wet grains are processed corn mash that does not go through a drying process and contains approximately 70% moisture content. Distillers wet grains have a short shelf life of approximately three days and can be sold only to livestock producers within the immediate vicinity of the plant. Modified distillers grains are distillers wet grains that have been dried to a 50% moisture content. Modified distillers grains have a slightly
longer shelf life and are often sold to nearby livestock producers. DDGS is distillers wet grains that are dried to an 8-10% moisture content. DDGS have an almost indefinite shelf life and may be sold and shipped to any market regardless of its vicinity to the plant.
Marketing and Distribution
Ethanol
All of the ethanol produced at the plant is sold to Ethanol Products, LLC, a division of Broin Enterprises, Inc., under an ethanol marketing agreement. Ethanol Products, in turn, markets and sells the ethanol to major, multi-national oil companies with blending and refinery facilities located throughout the continental United States. The price received from the sale to Ethanol Products is based upon various types of contracts between the plant and Ethanol Products and is fixed upon the transfer of title to Ethanol Products.
The ethanol produced at the plant is shipped by Ethanol Products using rail cars operated by Ethanol Products or trucks supplied by companies with which Ethanol Products contracts. Transfer of title and risk of loss is made to Ethanol Products upon the loading of ethanol onto the railcars and trucks at the plant. The plant is served by rail facilities and connections to the Burlington Northern Santa Fe railroad system, which facilitate the transportation of ethanol to the customers’ terminals. The plant is also served by multiple South Dakota state highways and Interstate Highway 29, which provide transportation links in all directions.
The marketing agreement with Ethanol Products is in effect until July 2007, renewing automatically for five-year terms unless either party provides at least ninety days written notice of termination prior to the end of the term. Ethanol Products charges a marketing and service fee based upon each gallon of ethanol sold. Shipping costs in transporting the ethanol are borne by the plant and are included in our gross revenues and cost of revenues. In the event that the contractual relationship with Ethanol Products is interrupted for any reason, we believe that another entity to market the ethanol could be located. Any interruption, however, could temporarily disrupt the sale of ethanol and adversely affect our business and operations.
Distillers Grains
All of the distillers grains produced at the plant are sold to customers through Dakota Gold Marketing, Inc., a division of Broin Enterprises, Inc., under a distillers grains marketing agreement. As the plant’s exclusive marketing agent, Dakota Gold markets and sells the distillers grains produced at the plant to customers primarily located throughout the continental United States. The price received from the sale of distillers grain is the price received from the customers with which Dakota Gold Marketing has negotiated and entered a sale.
There are three variations of distillers grains produced at the plant and marketed by Dakota Gold Marketing: 1) DDGS; 2) Dakota Gold™; and 3) distillers wet grains. Dakota Gold™ is DDGS that is certified by Dakota Gold Marketing indicating DDGS meets certain standards and specifications. In 2006, approximately 78% of our revenues from the sale of distillers grains were attributable to sales of Dakota Gold™.
Dakota Gold Marketing markets Dakota Gold™, DDGS and distillers wet grains to local, regional, and national markets. The plant ships the majority of Dakota Gold™ and DDGS to national markets, which are primarily located in the southwestern United States, and the rest to local and regional markets. Shipments to national markets are primarily done by rail because of a longer shelf life, and shipments to local or regional markets are primarily done by truck. We also contract with Dakota Gold Marketing for the use of railcars in the shipping of DDGS and Dakota Gold™, paying Dakota Gold Marketing a flat fee per railcar in connection with each shipment. Through the marketing of Dakota Gold, we are not dependent upon one or a limited number of customers.
The marketing agreement with Dakota Gold Marketing is in effect until March 2012, renewing automatically for additional five-year terms unless discontinued by either party upon at least three months prior written notice. Dakota Gold Marketing charges the plant a marketing fee based upon a percentage of gross monthly sales of distillers grains less shipping costs. All shipping costs associated with transporting distillers grains from the plant to customers are borne by the plant and are included in our gross revenues and cost of revenues, and Dakota Gold Marketing is responsible for invoicing all loads and receiving payments from the customers, the payment of which is remitted to the plant.
Wind
Independent of the plant’s operations, Northern Growers is continuing to study the feasibility of entering the wind-generation business. In 2005, Northern Growers provided Northern Wind, LLC, a South Dakota limited liability company, a non-interest bearing loan in the amount of $52,000, the purpose of which was to assist Northern Wind in the study of wind generation in northeastern South Dakota. Northern Wind is currently analyzing the feasibility of developing wind-generation facilities within Grant and Roberts counties, South Dakota.
Risk Management
Due to fluctuations in the price of corn and natural gas, we use risk management or hedging strategies to minimize our commodity risk. Hedging is a means of protecting the price that we will buy corn and natural gas in the future. All of the commodity risk management services relating to corn and natural gas are provided by Broin Management under a corn and natural gas risk management agreement. This agreement is in effect until January 2012, renewing automatically for additional five-year terms unless discontinued by either party upon written notice prior to the expiration of the term.
Dependence Upon a Single or Few Customers
We, as discussed above, are substantially dependent upon Ethanol Products for the purchase, marketing and distribution of ethanol. Ethanol Products purchases 100% of the ethanol produced at the plant, all of which is marketed and distributed to its customers.
Sources and Availability of Raw Materials
Corn. The major raw material needed to produce ethanol and distillers grains at the plant is corn. To operate at a name-plate capacity of 75 million gallons of ethanol annually, the plant requires the supply of approximately 26.5 million bushels of corn annually. All of the plant’s corn requirements are purchased on the open market from local producers and storage elevators. The plant’s location in Grant County, South Dakota, is expected to continue to provide a sufficient supply of corn to meet the bushel requirement through 2007. In 2006, approximately 6.4 million bushels of corn were produced in Grant County and 32.6 million bushels of corn were produced in the nearby South Dakota counties of Codington, Day, Deuel, Hamlin, and Roberts. Another 37.1 million bushels were produced in the nearby Minnesota counties of Big Stone and Lac Qui Parle.
Steam. The production process at the plant requires a constant supply of steam. Steam is used for the cooking, evaporation, and distillation processes. While steam for the ethanol production process is generally received from an ethanol plant’s on-site boilers, the plant receives a substantial portion of its steam directly from Big Stone Plant, a coal fired, electrical generating facility located immediately adjacent to the plant, and co-owned by Otter Tail Corporation, Montana-Dakota Utilities and NorthWestern Corporation. In the event that additional steam is necessary or the supply of steam from Big Stone Plant is unexpectedly diminished or interrupted, the plant uses two on-site boilers to produce steam. The energy source to power the two on-site boilers and other machinery is natural gas. However, the use of steam from Big Stone Plant reduces the plant’s dependence on natural gas for operations. In 2006, for example, 48% of the plant’s natural gas requirements for operations were replaced directly with steam from Big Stone Plant, compared to 40% of the plant’s requirements in 2005.
The steam sale agreement with Big Stone Plant provides steam to the plant up to a maximum of 140 thousand pounds of steam per hour. The agreement’s ten year term ends on June 1, 2012, but automatically renews for two additional five-year terms unless terminated by either party by providing 12 months advance notice. Big Stone Plant has generally provided the plant with a consistent supply of steam to meet its requirements except during routine, semi-annual maintenance shutdowns.
Natural Gas. The production process at the plant requires a constant supply of natural gas. Natural gas is the primary energy source for drying distillers grains. It is primarily responsible for powering the two on-site boilers for the production of steam in the event that additional steam is necessary or the supply of steam from Big Stone Plant is unexpectedly diminished or interrupted. The plant contracts with NorthWestern Corporation of Sioux Falls, South Dakota, for the supply and distribution of natural gas to
the plant. The agreement with NorthWestern is for a term of ten years ending in 2012. Since the plant’s operations were commenced, there have been no material interruptions or shortages in the supply of natural gas to the plant.
Electricity. The production process at the plant requires a constant supply of electricity. Electricity is necessary for lighting purposes and powering much of the machinery and equipment at the plant. The plant contracts with Otter Tail Power Company of Otter Tail, Minnesota, to provide all the electric power and energy requirements for the plant. The agreement commenced at the start of plant operations in 2002 under an initial one-year term, but automatically renews for additional one-year terms unless terminated by 12 months advance written notice from either party. Since operations were commenced, there have been no interruptions or shortages in the supply of electricity to the plant.
Water. The production process at the plant requires a constant supply of water. Water is necessary for the slurry and cooking processes, cooling towers and boiler operations. The plant contracts with the city of Big Stone City and Big Stone Plant to supply the necessary water requirements for the production process. The agreement with the city of Big Stone City is in effect until 2012, and automatically renews for two, five-year terms unless terminated by either party with 12 months advance written notice. Since the plant’s operations were commenced, the city of Big Stone City and Big Stone Plant have provided an ample and consistent supply of water to meet the plant’s requirements.
Research and Development
We do not conduct any research and development of our own relating to the production of ethanol and distillers grains. Instead, we rely on Broin Research, Inc., a division of Broin and Associates, to research and develop new technologies in order to improve the production process and end products. Under a license agreement dated October 25, 2005, Broin Research licenses to us the right to use certain technology and patents owned, developed, or obtained by Broin Research and which relate to the ethanol and co-product production processes. The agreement terminates on June 30, 2015, the same date that the management agreement between the plant and Broin Management is scheduled to expire.
Competition
We are in direct competition with numerous other ethanol and distillers grains producers, many of which have significantly greater resources. We expect that additional ethanol and distillers grains producers will enter the market. The ethanol industry has grown to 113 production facilities in the United States as of February 2007, compared to 96 production facilities in the United States as of March 2006. The largest ethanol producers include Abengoa Bioenergy Corp, Archer Daniels Midland, Aventine Renewable Energy, Cargill, US Bioenergy and VeraSun Energy Corporation, all of which are capable of producing more ethanol than the plant. There are numerous ethanol plants
of a similar size to the plant located in the Midwest region. In addition, at least 77 new ethanol plants and 7 expanding plants, with a combined annual production capacity of over 3 billion gallons annually, are set to come into production in the next 12 months, which will increase the ethanol production capacity of competitors. In South Dakota, excluding the plant, there are currently 12 plants in full production, three of which are in an expansion phase, and four new plants undergoing construction, all of which have a combined production capacity of approximately 900 million gallons. Despite this concentration and growth, we believe that we will continue to compete favorably with other ethanol and distillers grains’ producers because of the plant’s existing efficiencies, the use of new technology from Broin Research, and the marketing arrangements with the companies owned and affiliated with Broin Companies.
The following table identifies most of the producers in the United States along with their production capacities.
Company
Location
Feedstock
Current
Capacity
(mgy)
Under
Construction/
Expansions
(mgy)
Abengoa Bioenergy Corp.
York, NE
Corn/milo
Colwich, KS
Portales, NM
Ravenna, NE
Aberdeen Energy*
Mina, SD
Corn
Absolute Energy, LLC*
St. Ansgar, IA
Corn
ACE Ethanol, LLC
Stanley, WI
Corn
Adkins Energy, LLC*
Lena, IL
Corn
Advanced Bioenergy
Fairmont, NE
Corn
AGP*
Hastings, NE
Corn
Agra Resources Coop. d.b.a. EXOL*
Albert Lea, MN
Corn
Agri-Energy, LLC*
Luverne, MN
Corn
Alchem Ltd. LLLP
Grafton, ND
Corn
10.5
Al-Corn Clean Fuel*
Claremont, MN
Corn
Amaizing Energy, LLC*
Denison, IA
Corn
Archer Daniels Midland
Decatur, IL
Corn
1,070
Cedar Rapids, IA
Corn
Clinton, IA
Corn
Columbus, NE
Corn
Marshall, MN
Corn
Peoria, IL
Corn
Wallhalla, ND
Corn/barley
Arkalon Energy, LLC
Liberal, KS
Corn
ASAlliances Biofuels, LLC
Albion, NE
Corn
Linden, IN
Corn
Bloomingburg, OH
Corn
Aventine Renewable Energy, LLC
Pekin, IL
Corn
Aurora, NE
Corn
Badger State Ethanol, LLC*
Monroe, WI
Corn
Big River Resources, LLC*
West Burlington, IA
Corn
Blue Flint Ethanol
Underwood, ND
Corn
Bonanza Energy, LLC
Garden City, KS
Corn/milo
Broin Enterprises, Inc.*
Scotland, SD
Corn
Bushmills Ethanol, Inc.*
Atwater, MN
Corn
Cardinal Ethanol
Harrisville, IN
Corn
Cargill, Inc.
Blair, NE
Corn
Eddyville, IA
Corn
Cascade Grain
Clatskanie, OR
Corn
CassCo Amaizing Energy, LLC
Atlantic, IA
Corn
Castle Rock Renewable Fuels, LLC
Necedah, WI
Corn
Center Ethanol Company
Sauget, IL
Corn
Central Indiana Ethanol, LLC
Marion, IN
Corn
Central Illinois Energy, LLC
Canton, IL
Corn
Central MN Ethanol Coop*
Little Falls, MN
Corn
21.5
Central Wisconsin Alcohol
Plover, WI
Seed corn
Chief Ethanol
Hastings, NE
Corn
Chippewa Valley Ethanol Co.*
Benson, MN
Corn
Commonwealth Agri-Energy, LLC*
Hopkinsville, KY
Corn
Corn, LP*
Goldfield, IA
Corn
Cornhusker Energy Lexington, LLC
Lexington, NE
Corn
Corn Plus, LLP*
Winnebago, MN
Corn
Coshoctan Ethanol, OH
Coshoctan, OH
Corn
Dakota Ethanol, LLC*
Wentworth, SD
Corn
DENCO, LLC
Morris, MN
Corn
21.5
Dexter Ethanol, LLC
Dexter, IA
Corn
E Energy Adams, LLC
Adams, NE
Corn
E3 Biofuels
Mead, NE
Corn
E Caruso (Goodland Energy Center)
Goodland, KS
Corn
East Kansas Agri-Energy, LLC*
Garnett, KS
Corn
Elkhorn Valley Ethanol, LLC
Norfolk, NE
Corn
ESE Alcohol Inc.
Leoti, KS
Seed corn
1.5
Ethanol2000, LLP*
Bingham Lake, MN
Corn
Ethanol Grain Processors, LLC
Obion, TN
Corn
First United Ethanol, LLC (FUEL)
Mitchell Co., GA
Corn
Frontier Ethanol, LLC
Gowrie, IA
Corn
Front Range Energy, LLC
Windsor, CO
Corn
Gateway Ethanol
Pratt, KS
Corn
Glacial Lakes Energy, LLC*
Watertown, SD
Corn
Global Ethanol/Midwest Grain Processors
Lakota, IA
Corn
Riga, MI
Corn
Golden Cheese Company of California*
Corona, CA
Cheese whey
Golden Grain Energy, LLC*
Mason City, IA
Corn
Golden Triangle Energy, LLC*
Craig, MO
Corn
Grand River Distribution
Cambria, WI
Corn
Grain Processing Corp.
Muscatine, IA
Corn
Granite Falls Energy, LLC*
Granite Falls, MN
Corn
Great Plains Ethanol, LLC*
Chancellor, SD
Corn
Greater Ohio Ethanol, LLC
Lima, OH
Corn
Green Plains Renewable Energy
Shenandoah, IA
Corn
Superior, IA
Corn
Hawkeye Renewables, LLC
Iowa Falls, IA
Corn
Fairbank, IA
Corn
Menlo, IA
Corn
Heartland Corn Products*
Winthrop, MN
Corn
Heartland Grain Fuels, LP*
Aberdeen, SD
Corn
Huron, SD
Corn
Heron Lake BioEnergy, LLC
Heron Lake, MN
Corn
Holt County Ethanol
O’Neill, NE
Corn
Horizon Ethanol, LLC
Jewell, IA
Corn
Husker Ag, LLC*
Plainview, NE
Corn
26.5
Illinois River Energy, LLC
Rochelle, IL
Corn
Indiana Bio-Energy
Bluffton, IN
Corn
Iowa Ethanol, LLC*
Hanlontown, IA
Corn
Iroquois Bio-Energy Company, LLC
Rensselaer, IN
Corn
James Valley Ethanol, LLC
Groton, SD
Corn
KAAPA Ethanol, LLC*
Minden, NE
Corn
Kansas Ethanol, LLC
Lyons, KS
Corn
Land O’ Lakes*
Melrose, MN
Cheese whey
2.6
Levelland/Hockley County Ethanol, LLC
Levelland, TX
Corn
Lincolnland Agri-Energy, LLC*
Palestine, IL
Corn
Lincolnway Energy, LLC*
Nevada, IA
Corn
Liquid Resources of Ohio
Medina, OH
Waste Beverage
Little Sioux Corn Processors, LP*
Marcus, IA
Corn
Marquis Energy, LLC
Hennepin, IL
Corn
Marysville Ethanol, LLC
Marysville, MI
Corn
Merrick & Company
Golden, CO
Waste beer
MGP Ingredients, Inc.
Pekin, IL
Corn/wheat starch
Atchison, KS
Michigan Ethanol, LLC
Caro, MI
Corn
Mid America Agri Products/Wheatland
Madrid, NE
Corn
Mid-Missouri Energy, Inc.*
Malta Bend, MO
Corn
Midwest Renewable Energy, LLC
Sutherland, NE
Corn
Millennium Ethanol
Marion, SD
Corn
Minnesota Energy*
Buffalo Lake, MN
Corn
Missouri Ethanol
Laddonia, MO
Corn
Missouri Valley Renewable Energy, LLC*
Meckling, SD
Corn
NEDAK Ethanol
Atkinson, NE
Corn
New Energy Corp.
South Bend, IN
Corn
North Country Ethanol, LLC*
Rosholt, SD
Corn
Northeast Biofuels
Volney, NY
Corn
Northeast Missouri Grain, LLC*
Macon, MO
Corn
Northern Lights Ethanol, LLC*
Big Stone City, SD
Corn
Northstar Ethanol, LLC
Lake Crystal, MN
Corn
Northwest Renewable, LLC
Longview, WA
Corn
Otter Creek Ethanol, LLC*
Ashton, IA
Corn
Otter Tail Ag Enterprises
Fergus Falls, MN
Corn
57.5
Pacific Ethanol
Madera, CA
Corn
Boardman, OR
Corn
Burley, ID
Corn
Panda Energy
Hereford, TX
Corn/milo
Panhandle Energies of Dumas, LP
Dumas, TX
Corn/Grain Sorghum
Parallel Products
Louisville, KY
Beverage waste
5.4
R. Cucamonga, CA
Patriot Renewable Fuels, LLC
Annawan, IL
Corn
Penford Products
Ceder Rapids, IA
Corn
Permeate Refining
Hopkinton, IA
Sugars & starches
1.5
Phoenix Biofuels
Goshen, CA
Corn
Pinal Energy, LLC
Maricopa, AZ
Corn
Pine Lake Corn Processors, LLC*
Steamboat Rock, IA
Corn
Pinnacle Ethanol, LLC
Corning, IA
Corn
Plainview BioEnergy, LLC
Plainview, TX
Corn
Platinum Ethanol, LLC*
Arthur, IA
Corn
Plymouth Ethanol, LLC*
Merrill, IA
Corn
Prairie Ethanol, LLC
Loomis, SD
Corn
Prairie Horizon Agri-Energy, LLC
Phillipsburg, KS
Corn
Premier Ethanol
Portland, IN
Corn
Pro-Corn, LLC*
Preston, MN
Corn
Quad-County Corn Processors*
Galva, IA
Corn
Red Trail Energy, LLC
Richardton, ND
Corn
Redfield Energy, LLC *
Redfield, SD
Corn
Reeve Agri-Energy
Garden City, KS
Corn/milo
Renew Energy
Jefferson Junction, WI
Corn
Siouxland Energy & Livestock Coop*
Sioux Center, IA
Corn
Siouxland Ethanol, LLC
Jackson, NE
Corn
Sioux River Ethanol, LLC*
Hudson, SD
Corn
Southwest Iowa Renewable Energy, LLC *
Council Bluffs, IA
Corn
Sterling Ethanol, LLC
Sterling, CO
Corn
Summit Ethanol
Leipsic, OH
Corn
Tall Corn Ethanol, LLC*
Coon Rapids, IA
Corn
Tama Ethanol, LLC
Tama, IA
Corn
Tate & Lyle
Loudon, TN
Corn
Ft. Dodge, IA
Corn
The Andersons Albion Ethanol LLC
Albion, MI
Corn
The Andersons Clymers Ethanol, LLC
Clymers, IN
Corn
The Andersons Marathon Ethanol, LLC
Greenville, OH
Corn
Trenton Agri Products, LLC
Trenton, NE
Corn
United Ethanol
Milton, WI
Corn
United WI Grain Producers, LLC*
Friesland, WI
Corn
US BioEnergy Corp.
Albert City, IA
Corn
Woodbury, MI
Corn
Hankinson, ND
Corn
Ord, NE
Corn
Central City , NE
Corn
Dyersville, IA
Corn
U.S. Energy Partners, LLC (White Energy)
Russell, KS
Milo/wheat starch
Utica Energy, LLC
Oshkosh, WI
Corn
VeraSun Energy Corporation
Aurora, SD
Corn
Ft. Dodge, IA
Corn
Charles City, IA
Corn
Welcome, MN
Corn
Hartely, IA
Corn
Voyager Ethanol, LLC*
Emmetsburg, IA
Corn
Western New York Energy, LLC
Shelby, NY
Corn
Western Plains Energy, LLC*
Campus, KS
Corn
Western Wisconsin Renewable Energy, LLC*
Boyceville, WI
Corn
White Energy
Hereford, TX
Corn/Milo
Wind Gap Farms
Baconton, GA
Brewery waste
0.4
Renova Energy
Torrington, WY
Corn
Xethanol BioFuels, LLC
Blairstown, IA
Corn
Yuma Ethanol
Yuma, CO
Corn
Total Current Capacity at
113 ethanol biorefineries
5,583.4
Total Under Construction
(78)/Expansions (7)
6,243.5
Total Capacity
11,826.9
* locally-owned
February 12, 2007 Renewable Fuels Association
Ethanol production is also expanding internationally. Brazil has long been the world’s largest producer and exporter of ethanol, though since 2005, ethanol production in the United States slightly exceeded Brazilian production. Ethanol is produced more cheaply in Brazil than in the United States because of the use of sugarcane, a less expensive raw material alternative to corn. Because of various tariffs on the importation of ethanol into the United States, the price of ethanol produced in the United States is currently more competitive than ethanol imported from Brazil. In the event that these tariffs are reduced or eliminated, which are scheduled to expire in December 2008, the price of ethanol produced in the United States may become less competitive, which could adversely impact the ability to sell ethanol.
The Caribbean Basin Initiative allows for ethanol produced in participating Caribbean Basin countries to be imported into the United States duty free. Large ethanol producers, like Cargill, have expressed an interest in building ethanol plants in these countries, such as El Salvador. While the Caribbean Basin Initiative caps the amount of duty free ethanol imported into the United States at 7% of the total United States’ production from the previous year, as total production in the United States grows, the amount of ethanol produced from the Caribbean area and sold in the United States will grow accordingly, which could impact the ability to sell ethanol.
Finally, alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. 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. Additionally, the enzymes used to produce cellulose-based ethanol have recently become less expensive. Furthermore, the Department of Energy has recently announced support for the development of cellulose-based ethanol, including a $160 million Department of Energy program for pilot plants producing cellulose-based ethanol. Several large companies, including Iogen Corporation, Abengoa, Royal Dutch Shell Group, Goldman Sachs Group, Dupont and Archer Daniels Midland, have all indicated that they are interested in research and development in this area. In addition, Xethanol Corporation, of Blairstown, Iowa, and Voyager Ethanol of Emmetsburg, Iowa, have stated plans to convert or expand their plants to a cellulose-based ethanol facility after 2007.
Federal and State Government Supports
Various federal and state laws, regulations, and programs have led to an increasing use of ethanol in fuel, including subsidies, tax credits, policies and other forms of financial incentives. Some of these laws provide economic incentives to produce and blend ethanol and others mandate the use of ethanol.
The Renewable Fuels Standard
The most recent ethanol supports are contained in the Energy Policy Act of 2005. This law became effective on August 8, 2005 and is expected to impact favorably the ethanol industry by enhancing both the production and use of ethanol. The provision of the Energy Policy Act of 2005 likely to have the greatest impact on the ethanol industry is the creation of a Renewable Fuels Standard, known as the RFS. The RFS is a national program that imposes requirements with respect to the amount of renewable fuel produced and used. RFS applies to refineries, blenders, distributors and importers, allowing these entities to use renewable fuel blends in those areas where it is most cost effective. The RFS requires that 4.7 billion gallons be sold or dispensed in 2007, increasing to 7.5 billion gallons by 2012.
The Clean Air Act and Oxygenated Gasoline Program
Ethanol sales have been favorably affected by the Clean Air Act amendments of 1990, particularly the Oxygenated Gasoline Program, which became effective November 1, 1992. The Oxygenated Gasoline Program requires the sale of oxygenated motor fuels during the winter months in certain major metropolitan areas to reduce carbon monoxide pollution. Ethanol use has also increased as the result of a second Clean Air Act program, the Reformulated Gasoline Program. This program became effective January 1, 1995 and requires the sale of reformulated gasoline in numerous areas to reduce pollutants, specifically those that contribute to ground level ozone, better known as smog. Reformulated gasoline that meets the performance criteria set by the Clean Air Act can be reformulated in a number of ways, including the addition of oxygenates to the gasoline. The two major oxygenates added to reformulated gasoline pursuant to these programs are MTBE and ethanol. MTBE has been linked to groundwater contamination and has been banned from use in many states. Although the Energy Policy Act of 2005 did not impose a national ban of MTBE, its failure to include liability protection for manufacturers of MTBE is expected to result in refiners and blenders using ethanol rather than MTBE. Prior to the passage of the Energy Policy Act, the reformulated gasoline program included a requirement that reformulated gasoline contain 2% oxygenate. The Energy Policy Act repealed that requirement.
The Volumetric Ethanol Excise Tax Credit
The use of ethanol as an alternative fuel source has been aided by federal tax policy. In October 2004, the president signed a law that contained the Volumetric Ethanol Excise Tax Credit, known as VEETC, and amended the federal excise tax structure effective as of January 1, 2005. Prior to VEETC, ethanol-blended fuel was taxed at a lower rate than regular gasoline (13.2 cents on a 10% blend). Under VEETC, the ethanol excise tax exemption has been eliminated, thereby allowing the full federal excise tax of 18.4 cents per gallon of gasoline to be collected on all gasoline and allocated to the highway trust fund. In place of the exemption, the bill creates a new volumetric ethanol excise tax credit of 51 cents per gallon of ethanol blended at 10%. Based on volume, the VEETC is expected to allow greater refinery flexibility in blending ethanol since it makes the tax credit available on all ethanol blended with all gasoline, diesel and ethyl tertiary
butyl ether, known as ETBE, including ethanol in E85 (an 85% ethanol fuel blend) and E20 (a 20% ethanol fuel blend) in Minnesota. The VEETC is scheduled to expire on December 31, 2010.
Small Ethanol Producer Tax Credit
The Energy Policy Act of 2005 expanded who qualifies for the small ethanol producer tax credit. Historically, small ethanol producers were allowed a 10-cents-per-gallon production income tax credit on up to 15 million gallons of production annually. The size of the plant eligible for the tax credit was limited to 30 million gallons. Under the Energy Policy Act the size limitation on the production capacity for small ethanol producers increased from 30 million to 60 million gallons. The credit can be taken on the first 15 million gallons of production. The tax credit is capped at $1.5 million per year per producer. Upon completion of the plant’s expansion, the plant’s annual production will exceed 60 million gallons per year which will make us ineligible for the credit.
Clean-Fuel Vehicle Refueling Equipment Tax Credit
In addition, the Energy Policy Act creates a new tax credit that permits taxpayers to claim a 30% credit (up to $30,000) for the cost of installing clean-fuel vehicle refueling equipment, such as an E85 fuel pump, to be used in a trade or business of the taxpayer or installed at the principal residence of the taxpayer. Under the provision, clean fuels are any fuel at least 85% of the volume of which consists of ethanol, natural gas, compressed natural gas, liquefied natural gas, liquefied petroleum gas and hydrogen and any mixture of diesel fuel and biodiesel containing at least 20% biodiesel. The provision is effective for equipment placed in service until January 1, 2010. While it is unclear how this credit will affect the demand for ethanol in the short term, it is expected to help raise consumer awareness of alternative sources of fuel and could positively impact future demand for ethanol.
Imported Ethanol Tariffs and Quotas
Currently, there is a $0.54 per gallon tariff on imported ethanol, which is scheduled to expire in 2008. Ethanol imports from 24 countries in Central America and the Caribbean region are exempted from the tariff under the Caribbean Basin Initiative or CBI, which provides that specified nations may export an aggregate of 7.0% of United States ethanol production per year into the United States, with additional exemptions from ethanol produced from feedstock in the Caribbean region over the 7.0% limit. Large ethanol producers, such as Cargill, 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.
State Legislation Banning or Limiting MTBE Use
As of February 2007, 25 states, including California and New York, have banned or significantly limited the use of MTBE due to environmental and public health
concerns. Ethanol has served as a replacement for much of the discontinued volumes of MTBE and is expected to continue to replace future volumes of MTBE that are removed from the fuel supply.
South Dakota
In South Dakota, the state provides an incentive production payment to ethanol producers operating in South Dakota. The production incentive consists of a direct payment to South Dakota ethanol producers of up to $0.20 per gallon, which is divided among producers of fuel ethanol within South Dakota up to a maximum of $1 million per year per plant (a maximum of $83,333 per month in 2006) and a maximum of $10 million over the life of a plant. The program caps the payments that can be distributed to all plants based in South Dakota in a program year to no more than $7 million in payments in 2007 (program year ending June 30, 2007), and every year thereafter. The payments are distributed to each plant in proportion to the total number of gallons of ethanol produced and marketed annually by all the plants in South Dakota. As more plants commence production, or existing plants increase production, each plant will receive a lower proportionate share of the maximum payment under the program. Due to an increase in claims made for payment from new and existing plants during the 2006 program year, the funds were depleted in full midway through the 2006 program year. Based on the number of new plants and currently expanding plants, we believe the funds under the program will be again depleted before the end of the 2007 program year.
The ethanol industry and our business depend upon continuation of the federal and state ethanol supports discussed above. These government incentives have supported a market for ethanol that might disappear without the incentives. Alternatively, the government incentives may be continued at lower levels than those at which they currently exist. The elimination or reduction of such federal ethanol supports would make it more costly for us to sell ethanol.
Environmental Regulation and Costs
We are subject to extensive environmental regulation at the federal and state levels. The federal environmental regulations with which the plant must comply were promulgated by the U.S. Environmental Protection Agency (EPA) pursuant to the Clean Air Act. The state environmental regulations with which the plant must comply, in contrast, were promulgated by the South Dakota Department of Environment and Natural Resources (DENR). The EPA and the DENR regulate the air quality at the plant, particularly the plant’s emissions into the air. The DENR also regulates water collection and discharge. In addition to its own enforcement authority under this law, the EPA has delegated permitting and enforcement authority to the DENR. The plant is required to have the following permits from these and other agencies in order to conduct operations:
• Title Five Operating Permit from the DENR. In South Dakota, the Title Five Operating Permit serves as the air quality and operation permit for the plant. The plant must conduct ongoing emissions testing to verify compliance with the Title Five Operating permit.
• Bureau of Alcohol, Tobacco and Fuel Permit from the United States Department of Treasury. The plant is required to have this permit because of the alcohol content of ethanol. The permit is due for renewal annually.
• A Surface Water Discharge Permit from the DENR. The Surface Water Discharge Permit regulates the terms of any storm water discharges associated with industrial activity. The permit requires the plant to provide ongoing compliance reports to the DENR. This permit is due for renewal in 2008.
While the plant is currently in compliance with all applicable environmental laws, regulations and permits, the plant must continue to comply with the permits and regulatory requirements. To accomplish this, the plant maintains an on-going program to ensure compliance with such requirements. Maintaining compliance may require the plant to incur expenditures for such things as new or upgraded equipment or processes, some of which could be material and costly.
Finally, federal and state government’s regulation of the environment changes constantly. It is possible that more stringent federal or state environmental rules or regulations could be adopted, which could increase the plant’s future operating costs and expenses. It also is possible that federal or state environmental rules or regulations could be adopted that could have an adverse effect on the use of ethanol. For example, changes in the environmental regulations regarding ethanol’s use due to currently unknown effects on the environment could have an adverse effect on the ethanol industry. Furthermore, the plant’s operations are governed by the Occupational Safety and Health Administration (“OSHA”). OSHA regulations may change such that the future costs of the operation of the plant may increase. Any of these regulatory factors may result in higher costs or other materially adverse conditions effecting operations, cash flows and financial performance.
Management and Employees
Broin Management, LLC, a division of the Broin Companies, LLC, manages the day-to-day operations of the plant under a management agreement, that is in effect until June 30, 2015. Under the agreement, Broin Management receives a fixed annual fee and an incentive bonus based on our annual net income. The plant also pays certain expenses incurred with respect to the operation of the plant while other expenses, including, but not limited to, the provision of a full-time technical manager and general manager, are included as part of Broin Management’s fees. Mr. Blaine Gomer, the plant’s general manager, is a Broin Management employee. Mr. Gomer oversees and is responsible for operations and production at the plant on a day-to-day basis. The general manager is a full-time, on-site position, but Mr. Gomer is an employee of Broin Management.
As of March 1, 2007, the plant employed 45 employees, including a commodities manager, a commodities supervisor, an operations manager, a maintenance manager, a microbiologist, a chief mechanical operator, a controller, plant operators, maintenance technicians, grains assistants, accountants, and an administrative assistant. This does not include Mr. Gomer and the technical manager, both of whom are employees of Broin Management.
Available Information
Our website is at www.northernlightsethanol.com, then clicking on “Become a Member.” Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are filed with the SEC. Such reports and other information filed by us with the SEC are available on the SEC website. The public may read and copy any materials filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy, and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov. The contents of these websites are not incorporated into this filing.
Item 1A.
Item 1A. Risk Factors.
Risks Related to Operations
Our financial performance is dependent on market prices for ethanol and distillers grains and corn, and our financial condition and results of operation are directly affected by changes in these market prices. Our results of operations and financial condition is significantly affected by the cost and supply of corn and by the selling price for ethanol and distillers grains. Changes in the price and supply of these commodities are subject to and determined by market forces over which we have no or little control, including overall supply and demand, government programs and policies, weather, availability and price of competing products, and other factors.
Our business is highly sensitive to corn prices, and we generally cannot pass on increases in corn prices to our customers. Corn is the principal raw material we use to produce ethanol and distillers grains. Because ethanol competes with fuels that are not corn-based, we generally are unable to pass along increased corn costs to our customers, and, accordingly, rising corn prices tend to produce lower profit margins. At certain levels, corn prices would make ethanol uneconomical to use in fuel markets. The price of corn is influenced by weather conditions (especially droughts) and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors, including government policies and subsidies with respect to agriculture and international trade, and global and local supply and demand. The price of corn has fluctuated significantly in the past and may fluctuate significantly in the future. For example, over the ten-year period from 1996 through 2006, corn prices (based on
Chicago Board of Trade, or CBOT, daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $5.48 per bushel in 1996. On December 31, 2006, the CBOT price of corn was $3.90 per bushel. In addition, increasing domestic ethanol capacity could boost demand for corn and result in increased corn prices. We may also have difficulty from time to time in purchasing corn on economical terms due to supply shortages. Any supply shortage could require us to suspend operations until corn became available at economical terms. Suspension of operations could have a material adverse effect on our business, results of operations and financial condition.
Fluctuations in the selling price and production cost of gasoline may reduce our profit margins. Ethanol is marketed both as a fuel additive to reduce vehicle emissions from gasoline and as an octane enhancer to improve the octane rating of gasoline with which it is blended. As a result, ethanol prices are influenced by the supply and demand for gasoline and our business, future results of operations and financial condition may be materially adversely affected if gasoline demand or price decreases.
The price of distillers grains is affected by the price of other commodity products, such as soybeans, and decreases in the price of these commodities could decrease the price of distillers grains. Distillers grains compete with other protein-based animal feed products. The price of distillers grains may decrease when the price of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the commodities from which they are derived. Downward pressure on commodity prices, such as soybeans, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers grains. As a result, we may experience lower revenue and income.
Our business is subject to seasonal fluctuations. Our operating results are influenced by seasonal fluctuations in the price of our primary production inputs, namely corn, and the price of our primary product, ethanol. In recent years, the spot price of corn tends to rise during the spring planting season in May and June and tends to decrease during the fall harvest in October and November. The price for natural gas, however, tends to move opposite of corn and tends to be lower in the spring and summer and higher in the fall and winter. In addition, our ethanol prices are substantially correlated with the price of unleaded gasoline. As a result, because the price of unleaded gasoline tends to rise during the summer, the price of ethanol generally rises in the summer.
Hedging transactions involve risks that could harm our profitability. In an attempt to minimize the effects of the volatility of corn and natural gas on operating profits, we engage in hedging activities in the corn and natural gas futures markets. The effectiveness of such hedging activities is dependent, among other things, upon the cost of corn and natural gas and our ability to sell sufficient products to utilize all of the corn and natural gas subject to the futures contracts. There is no assurance that our hedging activities will reduce the risk caused by price fluctuation which may leave us vulnerable to high corn and natural gas prices. In addition, we may choose not to take hedging positions in the future, which may adversely affect our financial condition if corn and natural gas prices increase.
Our hedging activities can themselves result in increased costs because price movements in corn and natural gas are highly volatile and are influenced by many factors that are beyond our control. In 2004, for example, hedging activities relative to the changing price of corn resulted in a material increase to our cost of revenues. We may incur these costs again and they may be significant.
Our business is not diversified because it is limited to the fuel grade ethanol industry, which may limit our ability to adapt to changing business and market conditions. Our sole business is the production and sale of fuel grade ethanol produced from corn and its co-product, distillers grains. The plant does not have the capability of producing industrial or food and beverage grade ethanol, which is used in such products as cosmetics, perfume, paint thinner and vinegar. Our plant is also not equipped to capture carbon dioxide, another co-product of the ethanol production process. The lack of diversification of our business may limit our ability to adapt to changing business and market conditions.
We are heavily dependent upon the Broin Companies, LLC. We have several agreements in place with companies owned and controlled by the Broin Companies, including those related to the purchase or marketing of ethanol and distillers grains, management of the plant, construction of the plant’s expansion, research and technology, and information technology. If any of the agreements were to terminate, we might not be able to secure suitable and timely replacements for those services at a reasonable cost or at all, which would materially harm our business.
We are dependent upon Ethanol Products, LLC to purchase and market all of the ethanol produced at the plant. Ethanol Products is the exclusive purchaser of all of the ethanol produced at the plant which, in turn, markets and transports the ethanol to refineries located throughout the United States. If Ethanol Products breaches the ethanol marketing agreement or is not in the financial position to purchase all of the ethanol produced, we may not have any readily available means to sell the ethanol and our financial condition will be adversely and materially affected. If the ethanol marketing agreement with Ethanol Products were to terminate, we would be forced to seek other arrangements to sell the ethanol produced, but there are no assurances that these arrangements would achieve results comparable to those achieved by Ethanol Products.
Interruptions in energy supplies could delay or halt production at the plant, which will reduce our profitability. Ethanol production requires a constant and consistent supply of energy, including electricity, steam and natural gas. If there is any interruption in the plant’s supply of energy for whatever reason, such as supply, delivery or mechanical problems, we may be required to halt production. If production is halted for any extended period of time, it will reduce our profitability. The plant has agreements with various companies to provide the plant’s needed energy, but we cannot assure you that these companies will continue to be able to supply reliably the necessary energy that the plant needs. If the plant were to suffer interruptions in its energy supply, our business would be harmed.
We are dependent upon Big Stone Plant for steam, and the plant may incur increased operating costs if the steam supply is terminated or interrupted. The production of steam is a necessary energy source in the ethanol production process. Ethanol plants generally rely upon on-site boilers to produce and supply steam in the production process, which are typically powered by natural gas. We, in contrast, rely on the adjacent Big Stone Plant to supply a substantial portion of the required steam to the plant. If Big Stone Plant were to shut down for any considerable length of time or is unable to meet the plant’s steam requirements, the plant must operate with steam energy supplied from two on-site boilers. As a result, we may face increased operating costs because we would need to purchase more costly natural gas to fuel and power these boilers.
To produce ethanol, we need a significant supply of water. Water supply and water quality are important requirements to produce ethanol. The plant’s water requirements are supplied by Big Stone City and Big Stone Plant. We expect that Big Stone City and the Big Stone Plant will continue to provide all of the plant’s water requirement, including following expansion of the plant. If Big Stone City and Big Stone Plant are unable to meet our requirements, the plant will be forced to find other sources and this could require us to spend additional capital which could harm our business. We cannot assure you that the plant would be able to find alternate sources of water at commercially reasonable prices, if at all.
We have restrictive loan covenants with our lender. Our loan agreement with US Bank obligates us to maintain certain amounts of working capital, capital expenditure and cash distribution to member limitations, and fixed coverage ratios. The failure to comply with the various loan covenants may result in penalties, restrict our activities or result in a default which may have an adverse effect on our liquidity.
Risks Related to the Industry
As more ethanol plants are built, ethanol production will increase and, if demand does not sufficiently increase, the price of ethanol and distillers grains may decrease. According to the RFA, domestic ethanol production capacity has increased steadily from 1.7 billion gallons per year in January of 1999 to 5.58 billion gallons per year in February 2007. In addition, there is a significant amount of capacity being added to the ethanol industry. As of February 2007 approximately 6.2 billion gallons per year of production capacity, is currently under construction at new and existing facilities. This capacity is being added to address anticipated increases in demand. However, demand for ethanol may not increase as quickly as expected or to a level that exceeds supply, or at all. If the ethanol industry has excess capacity, it could have a material adverse effect on our business, results of operations and financial condition. Excess ethanol production capacity also may result from decreases in the demand for ethanol or increased imported supply. In addition, because ethanol production produces distillers grains as a co-product, increased ethanol production will lead to increased supplies of distillers grains. An increase in the supply of distillers grains, without corresponding increases in demand, could lead to lower prices or an inability to sell our distillers grain production. A decline
in the price of distillers grain or the distillers grain market generally could have a material adverse effect on our business, results of operations and financial condition.
We operate in an intensely competitive industry and there is no assurance that we will be able to compete effectively. The ethanol business is highly competitive, and other companies presently in the market, or that are about to enter the market, could adversely affect prices for the products we sell. Commodity groups in the Midwest have encouraged the construction of ethanol plants, and there are numerous other entities considering the construction of ethanol plants. Nationally, the ethanol industry may become more competitive given the substantial construction and expansion that is occurring in the industry. We compete with other ethanol producers such as Archer Daniels Midland, Cargill, among others, all of which are capable of producing significantly greater quantities of ethanol than the amount we produce. In light of such competition, there is no assurance that we will be able to compete effectively in the industry.
The effect of the Renewable Fuels Standard, or RFS, in the Energy Policy Act of 2005 on the ethanol industry is uncertain. The use of fuel oxygenates, including ethanol, was mandated through regulation, and much of the forecasted growth in demand for ethanol was expected to result from additional mandated use of oxygenates. Most of this growth was projected to occur in the next few years as the remaining markets switch from MTBE to ethanol. The Energy Policy Act, however, eliminated the mandated use of oxygenates and instead established minimum nationwide levels of renewable fuels (ethanol, biodiesel or any other liquid fuel produced from biomass or biogas) to be included in gasoline. Because biodiesel and other renewable fuels in addition to ethanol are counted toward the minimum usage requirements of the RFS, the elimination of the oxygenate requirement for reformulated gasoline may result in a decline in ethanol consumption, which in turn could have a material adverse effect on our business, results of operations and financial condition.
Competition from the advancement of technology may lessen the demand for ethanol and negatively impact our profitability. Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing more efficient engines, hybrid engines and alternative clean power systems using fuel cells or clean burning gaseous fuels. Vehicle manufacturers are working to develop vehicles that are more fuel efficient and have reduced emissions using conventional gasoline. Vehicle manufacturers have developed and continue to work to improve hybrid technology, which powers vehicles by engines that utilize both electric and conventional gasoline fuel sources. In the future, 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 financial condition.
Corn-based ethanol may compete with cellulose-based ethanol in the future, which could make it more difficult for us to produce ethanol on a cost-effective basis. Most ethanol 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, 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. If we are unable to produce ethanol as cost-effectively as cellulose-based producers, our ability to generate revenue will be negatively impacted.
Consumer resistance to the use of ethanol based on the belief that ethanol is expensive, adds to air pollution, harms engines and takes more energy to produce than it contributes, may affect the demand for ethanol which could affect our ability to market our product. Certain individuals believe that use of ethanol will have a negative impact on retail prices. Many also believe that ethanol adds to air pollution and harms car and truck engines. Still other consumers believe that the process of producing ethanol actually uses more fossil energy, such as oil and natural gas, than the amount of ethanol that is produced. These consumer beliefs could potentially be wide-spread. If consumers choose not to buy ethanol, it would affect the demand for the ethanol that we produce which could lower demand for ethanol and negatively affect our profitability.
Ethanol Plant Expansion Risks
We may need to increase cost estimates for construction of the plant’s expansion, and such increase could reduce our revenue stream and make the expansion unprofitable. Broin and Associates agreed to expand the plant based on a fixed contract price, according to the plans and specifications in a design-build agreement. We have based our capital needs on a design for the plant expansion that will cost approximately $50,000,000. There is no assurance that the final cost of the expansion will not be higher, nor is there any assurance that there will not be design changes or cost overruns associated with the expansion of the plant. In addition, shortages of steel could affect the final cost and final completion date of the project. Any significant increase in the estimated construction cost of the expansion may make the expansion too expensive to complete or unprofitable to operate because our revenue stream may not be able to adequately support the increased cost and expense attributable to increased construction costs.
Construction delays could increase our costs. We anticipate construction of the expansion will be completed in June 2007; however, construction projects often involve delays in obtaining permits, construction delays due to weather conditions, or other events that delay the construction schedule. If it takes longer to construct the expansion than we anticipate, it may substantially increase our costs, which could have a material adverse effect on our results of operations and financial condition.
Delays and defects in construction relating to the plant’s expansion could impair the plant’s ability to operate. Under the terms of the design-build agreement with Broin and Associates, Inc., Broin and Associates warrants that the material and equipment furnished for the plant expansion will be new, of good quality, and free from defects in material or workmanship. Although Broin and Associates will, for a period of one year after substantial completion of the plant’s expansion, correct all defects in material or workmanship at no additional expense to us, any defects in material or workmanship may interrupt or hinder the operation of the plant. These defects may have a material adverse impact on our financial condition.
Government, Regulatory and Other Risks
Government regulation could increase costs and reduce profitability. The operation of the plant is subject to ongoing compliance with applicable federal and state governmental regulations, such as those governing emission control, ethanol production, grain purchasing and other matters. If any of these regulations were to change, it could cost us significantly more to comply with them. Further, other regulations may arise in future years regarding the operation of the plant, including the possibility of additional permits and licenses. We might have difficulty obtaining any such additional permits or licenses, and they could involve significant unanticipated costs. We are subject to all of these regulations without regard to whether the operation of the plant is profitable.
Tariffs effectively limit imported ethanol into the United States, and their reduction or elimination could undermine the ethanol industry in the United States. Imported ethanol is generally subject to a $0.54 per gallon tariff that was designed to offset the $0.51 per gallon ethanol incentive available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. There is, however, a special exemption from this tariff for ethanol imported from 24 countries in Central America and the Caribbean Islands, which is limited to a total of 7% of United States ethanol production per year. Imports from the exempted countries may increase as a result of new plants in development. Since production costs for ethanol in these countries are significantly less than what they are in the United States, the duty-free import of ethanol through the countries exempted from the tariff may negatively affect the demand for domestic ethanol and the price at which we sell our ethanol. We do not know the extent to which the volume of imports would increase or the effect on United States prices for ethanol if the tariff is not renewed beyond its current expiration date in December 2008. Any changes in the tariff or exemption from the tariff could have a material adverse effect on our business, results of operations and financial condition.
Federal and state laws, regulations and tax incentives concerning ethanol could expire or change, which could harm our business. As described in more detail above, ethanol sales have been favorably affected by a variety of federal laws and supports. The Clean Air Act Amendments of 1990 helped spur demand for ethanol by requiring the use of oxygenated motor fuels. The Energy Policy Act of 2005 mandates the use of ethanol in motor vehicles through 2012. The Volumetric Ethanol Excise Tax Credit offers to blenders a volumetric ethanol excise tax credit of $0.51 cents per gallon of any ethanol blend. The modification or elimination of any of the federal and states laws and programs, among others, could have a material adverse impact on us.
If Northern Growers is treated as a corporation for federal income tax purposes, its capital units could decline in value. Northern Growers elected to be treated as a partnership for federal income tax purposes. This means that it does not pay income tax at the company level and that its members pay tax on their proportionate share of the net income. In the event there are changes in the law or IRS interpretations, or that the trading of its capital units results in the classification of Northern Growers as a publicly traded partnership, we may be treated as a corporation rather than a partnership for federal income tax purposes. In that case, we would pay tax on our income at corporate rates and no income, gains, losses, deductions or credits would flow through to its members. Currently, the maximum effective federal corporate rate is 35%. In addition, distributions would generally be taxed to members upon receipt as corporate dividends. Because a tax would be imposed upon Northern Growers at the entity level, the cash available for distribution to members would be reduced by the amount of the tax paid. Reduced distributions could reduce the value of a member’s capital units.
There are significant restrictions on transferring the capital units. To maintain preferential partnership tax status, Northern Growers’ capital units may not be traded on an established securities market or readily tradable on a secondary market. To help ensure that a market does not develop, Northern Growers’ Operating Agreement prohibits transfers other than through the procedures specified in its Capital Units Transfer System. Under this system, all transactions must be approved by Northern Growers’ board of managers. The board generally approves transfers that fall within “safe harbors” contained in the publicly traded partnership rules under the federal tax code. Permitted transfers include transfers by gift and death, sales to qualified family members, and sales through a “qualified matching service.” Transfers through Northern Growers’ qualified matching service are limited annually to no more than the 10% of total capital units outstanding. If a member transfers capital units in violation of the publicly traded partnership rules or without the prior written consent of the board, the transfer is considered null and void and the board has the option to redeem the capital units at a substantial discount. These restrictions on transfer could reduce the value of a member’s capital units.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The plant is located immediately adjacent to Big Stone Plant near the city of Big Stone City in Grant County, South Dakota. The land on which the plant is located is leased from Big Stone-Grant Industrial Development and Transportation, LLC, which is owned by Otter Tail Power Company, Montana-Dakota Utilities, and NorthWestern Corporation. The term of the lease is for 99 years. The rent is $2,520.00 per year until December 31, 2010, after which the rent is increased by 5.0% from the immediately preceding five-year period. In addition, the plant site is served by multiple state highways, is near Interstate Highway 29, and has rail facilities and connections to the Burlington-Northern-Santa Fe Railroad system to transport the ethanol and distillers grains produced at the plant to various markets. All of the plant’s tangible and intangible property, including its leasehold interest, easement rights, improvements, equipment, personal property, and contracts, serve as the collateral for the debt financing with US Bank National Association, of Sioux Falls, South Dakota, which is described below under “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Indebtedness.”
Item 3.
Item 3. Legal Proceedings.
From time to time in the ordinary course of business, we may be named as a defendant in legal proceedings related to various issues, including without limitation, workers’ compensation claims, tort claims, or contractual disputes. We are not currently involved in any material legal proceedings, directly or indirectly, and we are not aware of any potential claims.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
We did not submit any matter to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2006.
PART II Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchaser of Equity Securities.
As of March 1, 2007, Northern Growers had 859 members.
Trading Activity and Restrictions
Northern Growers’ capital units are not traded on an established public trading market such as a stock exchange or The NASDAQ Stock Market. Capital units must be transferred in accordance with Northern Growers’ Operating Agreement and its Capital Units Transfer System. The Capital Units Transfer System provides for transfers to qualified family members, by gift, upon death, and through a “qualified matching
service,” subject to final board of managers’ approval. Since March 8, 2004, our qualified matching service has been operated through Alerus Securities Corporation, a registered broker-dealer operating a registered Alternative Trading System with the SEC. The following table contains historical information by quarter for the past two years regarding the trading of capital units:
(1) Before January 1, 2006, our qualified matching service was operated on a trimester basis, after which it was moved to a quarter based system. Transfer of ownership of all capital units occurs on the first day of the quarter immediately following the quarter(s) in which the trade occurs between the buyer and seller or the next following quarter, depending upon the date of the trade during the quarter. Quarters begin on January 1, April 1, July 1 and October 1.
(2) All unit prices and number of units traded are adjusted to reflect a four-for-one capital unit split made effective on September 1, 2005 and a two-for-one split made effective on July 1, 2006.
There were no issuer purchases of equity securities during the fourth quarter ended December 31, 2006.
As a limited liability company, Northern Growers is required to restrict the transfers of its capital units in order to preserve its preferential single-level tax status. Its capital units may not be traded on any national securities exchange or in any over-the-counter market. Northern Growers’ Capital Unit Transfer System prohibits any transfer that would result in the loss of its partnership tax status.
Pursuant to Northern Growers’ Operating Agreement, a minimum of 2,500 capital units is required to become and remain a member. In addition to the transfer restrictions described above, under certain limited circumstances, the board of managers retains the right to redeem the capital units at $0.20 per capital unit. The board’s right to redeem is available in the event a member breaches the Operating Agreement, upon a member’s failure to fulfill the membership requirements, and with respect to other matters. Under the qualified matching service, the number of capital units traded annually cannot exceed 10% of Northern Growers’ total issued and outstanding capital units.
Distributions
Under the terms of Northern Growers’ Amended and Restated Operating Agreement dated January 1, 2006, the board of managers is required to make annual (or more frequent) distributions to its members and may not retain more than $200,000 of net cash from operations, unless (i) a super majority of the board of managers (75%) decides otherwise, (ii) it would violate or cause a default under the terms of any debt financing or
other credit facilities, or (iii) it is otherwise prohibited by law. For further details of the restrictions under our debt facilities, please see “Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations-Indebtedness.” Distributions are required to be issued to members of record as of the last day of the quarter immediately prior to the quarter in which the distribution was approved by the board of managers.
In 2005, Northern Lights made cash distributions to Northern Growers of approximately $12.5 million and $3.7 million to the minority member of Northern Lights. Northern Growers, in turn, distributed to its members approximately $12.22 million, or $0.241 per capital unit.
In 2006, Northern Lights made cash distributions to Northern Growers of approximately $22.95 million and $6.79 million to the minority member of Northern Lights. Northern Growers, in turn, distributed to its members approximately $22.67 million, or $0.448 per capital unit.
Thus far in 2007, Northern Lights made cash distributions to Northern Growers of approximately $8.49 million and $2.51 to the minority member of Northern Lights. Northern Growers, in turn, distributed to its members approximately $6.78 million, or $0.134 per capital unit. Approximately $1.69 million of the $8.49 million, has been retained by Northern Growers in anticipation of a potential redemption of capital units from a member with the largest holding of units in Northern Growers, though it is uncertain whether any redemption will actually occur.
It is uncertain whether similar distributions will be made in 2007. The ability to issue similar distributions is substantially dependent upon our profitability, the discretion of our board of managers subject to the provisions of the Operating Agreement, and the approval from our lender.
Item 6.
Item 6. Selected Financial Data.
The following table sets forth our selected financial data for the periods indicated. The audited financial statements included in Item 8 of this report have been audited by our independent auditors, Eide Bailly LLP.
(1) The plant commenced operations on July 26, 2002.
(2) Northern Growers reorganized from a cooperative to a limited liability company on April 1, 2003.
(3) Adjusted for a four-for-one capital unit split made effective September 1, 2005 and a two-for-one split effective July 1, 2006.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
You should read the following discussion along with our financial statements and the notes to our financial statements included elsewhere in this report. The following discussion contains forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance and achievements may differ materially from those expressed in, or implied by, such forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Information” at the beginning of this report.
Overview and Executive Summary
Northern Growers, LLC (“Northern Growers”) owns and manages a 77.16% interest in its subsidiary, Northern Lights Ethanol, LLC (“Northern Lights”) (Northern Lights and Northern Growers are also collectively referred to as “we” “us” or “our”). Broin Investments I, LLC owns the remaining minority interest in Northern Lights. Northern Lights owns and operates an ethanol plant (the “plant”) near Big Stone City, South Dakota. The plant produces fuel-grade ethanol and distillers grains through the processing of corn. Corn is supplied to the plant from purchases of corn on the local open market. The ethanol produced at the plant is sold to Ethanol Products, which subsequently markets and sells the ethanol to gasoline blenders and refineries located throughout the continental United States. Distillers grains, a co-product of the production process, are sold through Dakota Gold Marketing, which markets and sells the product to livestock feeders primarily located in the United States.
Our operating and financial performance is largely driven by the prices at which we sell ethanol and distillers grains and the costs related to production. Federal and state government incentive programs, unlike in prior years, are no longer a material source of revenue and income. The price of ethanol is generally influenced by factors such as supply and demand, prices of unleaded gasoline and the petroleum markets, weather, and
government policies and programs. The price of distillers grains is generally influenced by supply and demand, and the price of corn, soybean meal and other protein-based feed products. Our two largest costs of production are corn and natural gas, although the plant’s cost for natural gas is offset by the use of steam supplied from the adjacent Big Stone Plant. The cost of natural gas and corn is generally impacted by factors such as supply and demand, weather, government policies and programs, and our risk management program used to protect against the price volatility of these commodities.
We generated record profits in 2006. Our net income for 2006 was $40.7 million compared to $16.1 million in 2005. The primary factor driving profits was an increase in ethanol revenues during a period of relatively constant cost of revenues. Ethanol revenues rose by 46% due to a 4% increase in production and sales volume and a 41% increase in ethanol prices. Production and, consequently, sales volume rose due to continued improvement in plant efficiencies and less plant shut-down time. Ethanol prices rose significantly during the first three quarters as a result of increased demand from refineries and increases in the price of unleaded gasoline. Demand was spurred by refineries accelerating their phase out of MTBE in the refinery process, switching to ethanol in its place. During the fourth quarter of 2006, however, ethanol prices pulled back significantly due to a reduction in the price of unleaded gasoline, thus halting any further revenue growth. Cost of revenues, on the other hand, were relatively constant, decreasing by about 1% between periods. Despite a sharp rise in corn prices during the fourth quarter, cost of revenues decreased slightly from 2005 to 2006 due to decreased energy costs and gains from our corn price risk management program.
Our prospects in 2007 are not as positive as last year as significant challenges will be faced. Our first challenge is dealing with the potential of excess supply. Nationally, 77 plants are under construction and seven existing plants are undergoing expansion, which is expected to create over three billion gallons of new ethanol production. Additional increases in supply are expected from the import of ethanol from countries like Brazil. Unless new markets for ethanol open up to absorb these gallons, we anticipate that there will be downward pressure on ethanol prices.
New production of ethanol may also translate into an increase in distillers grains production and supply. Like ethanol, unless new markets for distillers grains open up, such as in the hog and poultry industries, or the price of distillers grains does not move correspondingly with an increase in corn prices, there could be downward pressure on distillers grains’ prices and therefore revenue. Consequently, we will depend even more on our marketer to locate new markets, which could include further emphasis on developing markets internationally.
Another challenge is dealing with the potential of rising corn costs, which would translate to a higher cost of revenues. Since the fourth quarter of 2006, corn supplies have significantly tightened due to a poor corn harvest worldwide and increase in demand from the ethanol industry. This resulted in the price of corn reaching close to $4.00 in January 2007, a record high since 1996. While we currently have a risk management program in place against rising corn prices through May 2007, which should partially
mitigate against this risk, we will be subject to the risk of the market and decreased margins after this period.
There may be partial offsets, however, to the rising ethanol supplies and corn costs. One potential offset may be the potential stability of natural gas costs. Natural gas prices are expected to remain low until the summer of 2007 due to adequate storage supplies and a relatively mild winter thus far. Another potential offset is the improvements being made to our plant. Last fall, we completed the incorporation of new technology into the production process called BPX™. This technology is expected to decrease our energy costs. Likewise, we are currently on schedule to complete the expansion of the plant to a 75 million gallon annual capacity, which is expected to increase our efficiencies through economies of scale.
Without significant offsets, however, our revenues and earnings are expected to decrease from 2006, which will mean a decrease in distributions to our members. How much of a decrease will depend on the effects of the current corn and ethanol price trend. Because of a decrease in revenues and earnings, we may be faced with taking sterner fiscal measures in 2007 to cover operating costs. One such measure may be to retain more earnings in lieu of making distributions to members.
Results of Operations Comparison of years ended December 31, 2006 and December 31, 2005.
Revenues- Revenue from the sale of ethanol increased 46% from the year ended December 31, 2005 to the year ended December 31, 2006. The increase was due to a 41% increase in the average price of ethanol per gallon and a 4% increase in sales volume.
Revenue from the sale of distillers grains increased modestly from the year ended December 31, 2005 to the year ended December 31, 2006. The increase was due primarily to a slight increase in sales volume following an increase in production volume.
The incentive revenue from the United States Department of Agriculture’s Commodity Credit Corporation Bioenergy Program decreased $40,000 to $9,000 for the year ended December 31, 2006 from $49,000 for the year ended December 31, 2005. Minimal incentive revenue was earned under this program for the year ended December 31, 2006 because the program ended June 30, 2006. Incentive revenue from the state of South Dakota increased $70,000, or 10%, to $776,000 for the year ended December 31, 2006 from $705,000 for the year ended December 31, 2005.
Cost of Revenues- Cost of revenues decreased $800,000, or 1%, to $62.7 million for the year ended December 31, 2006 from $63.5 million for the year ended December 31, 2005. Cost of revenues decreased slightly between periods as an increase in production volume was offset primarily by a decrease in energy costs. Corn costs between periods remained relatively constant as a 13% rise in the market price of corn, most of which was due to rising prices during the fourth quarter of 2006 and increased competition for corn from a new local storage elevator, was offset by a $2.9 million net gain under our corn price risk management program. Gains and losses that result from a change in value of corn and natural gas hedging and forward contract instruments are recognized in cost of revenues as the changes occur. Gains are recognized as a decrease to cost of revenues, while losses are recognized as an increase to cost of revenues. For the year ended December 31, 2006, cost of revenues includes losses of $2.7 million from the use of corn hedging instruments. This loss was caused by the significant price increase to corn in the fourth quarter of 2006 and the effect it had on the value of the hedging instruments at December 31, 2006. The hedging loss was offset by a $5.6 million gain on our forward contracting for corn during the same period. In August 2006, Chicago Board of Trade (CBOT) prices rose due to a reduction in bushels of corn to be harvested nationwide. Because we had locked in lower prices for corn under our forward contracts during this time, however, the value of forward contracts rose and resulted in a $5.6 million gain at December 31, 2006.
In addition, our energy costs decreased 6% from 2005 to 2006. This decrease was due to an increased use of steam from Big Stone Plant and lower natural gas costs. Our volume usage of steam, the cost of which is less than natural gas, increased 19% from 2005 to 2006 because Big Stone Plant had fewer general maintenance shut-downs in 2006 compared to 2005. During the same period, natural gas costs decreased 4% from 2005 due primarily to an 11% decrease in the cost per unit. This decrease was due to stable prices and high storage capacity in 2006, compared to 2005 when the hurricane season caused the reverse effect.
General and Administrative Expenses- General and administrative expenses increased $2.45 million, or 63%, to $6.36 million for the year ended December 31, 2006 from $3.91 million for the year ended December 31, 2005. The increase was primarily
due to increased management incentive fees and costs during the year, which are based on an increase in our profitability.
Interest Expense- Interest expense decreased $150,000, or 11%, to $1.27 million for the year ended December 31, 2006 from $1.42 million for the year ended December 31, 2005. The decrease in interest expense was due to a $1.9 million reduction in non-construction related debt outstanding from December 31, 2005 to December 31, 2006 as we continued to reduce our debt through principal payments.
Net Income- Net income increased $24.5 million to $40.7 million for the year ended December 31, 2006 from $16.2 million for the year ended December 31, 2005. This change was caused primarily by, as discussed above, an increase in ethanol revenue at a time of relatively constant cost of revenues.
Comparison of years ended December 31, 2005 and December 31, 2004.
Revenues-Revenue from the sale of ethanol increased 6% from the year ended December 31, 2004 to the year ended December 31, 2005. The increase was due to a 5% increase in the average price of ethanol per gallon and a 1% increase in sales volume. Ethanol prices rose between periods due to rising unleaded gasoline prices, while sales volume rose following an increase in production volume.
Revenue from the sale of distillers grains decreased only slightly from the year ended December 31, 2004 to the year ended December 31, 2005. The decrease was due primarily to a 3% decrease in the price of distillers grains, offset by a 2% increase in sales volume. The price of distillers decreased primarily due to a decrease in price of competing protein-based feed products, while volume increased following increased plant production.
The incentive revenue from the United States Department of Agriculture’s Commodity Credit Corporation Bioenergy Program decreased $880,000, or 95%, to $50,000 for the year ended December 31, 2005 from $930,000 for the year ended December 31, 2004. Minimal incentive revenue was earned under this program for the year ended December 31, 2005 because there was an insignificant increase in ethanol production at the plant from the twelve months ended December 31, 2004. Payments under this discontinued program were based in part on a plant’s increase in production from the prior year’s corresponding periods. Incentive revenue from the state of South Dakota increased $38,000, or 6%, to $705,000 for the year ended December 31, 2005 from $667,000 for the year ended December 31, 2004.
Cost of Revenues-Cost of revenues decreased $7.7 million, or 11%, to $63.6 million for the year ended December 31, 2005 from $71.3 million for the year ended December 31, 2004. The decrease in the cost of revenues was primarily due to a 32% decrease in the cost of corn, offset by a 10% increase in energy costs. The decrease in the cost of corn was caused primarily by a 26% decrease in the market price of corn per bushel from 2004 to 2005. The market price decreased because of a large carryout and a plentiful corn harvest in 2005.
In addition to the market price decrease, the decrease in the cost of corn was caused in part by the use and effect of hedging instruments relative to the market price of corn between periods. For the year ended December 31, 2004, cost of revenues includes losses of $3.5 million from the use of corn hedging instruments. These losses were caused by the significant price fluctuation of corn in 2004 and its effect on the value of the hedging instruments. In late 2003, we increased the use of corn hedging instruments and positions to protect against the market price forecasts for corn. The forecasts predicted higher prices for corn because of low world carryout prior to the growing season, decreased production, and drought. As the year progressed, however, and it became apparent that corn production would be much higher than expected, the original market forecasts proved incorrect and the market price of corn actually declined. When the market price declined, the value of the corn hedging instruments fell which led to the $3.5 million loss and a corresponding increase in cost of corn and cost of revenues.
In contrast, there was no material adverse effect on cost of revenues from the use of hedging instruments relative to the corn market for the year ended December 31, 2005. Due to the record carryout of corn into 2005 and the overall stable conditions in the commodities markets, we took fewer hedging positions to protect against potential price volatility. As a result, there was considerably less market risk exposure in 2005 and potential for losses. Accordingly, for the year ended December 31, 2005, a $245,000 gain resulted from the use of corn hedging instruments which, in turn, led to a corresponding decrease in the cost of revenues.
The decrease in cost of revenues between 2004 and 2005 was offset by a 10% increase in energy costs between periods. This increase was due to a 31% increase in cost of natural gas per unit in 2005 and the effect of a settlement credit received by the plant in November 2004. Natural gas costs increased in 2005 because of a decrease in natural
gas production nationwide which was caused primarily by an overly active hurricane season and increased demand. With respect to the settlement credit, Big Stone Plant issued to the plant in 2004 a $1.4 million credit after determining that a metering instrument had been miscalibrated and that the plant had been overcharged for the use of steam. This credit resulted in the cost of steam for the plant being lower in 2004 than in 2005.
General and Administrative Expenses-General and administrative expenses increased $930,000, or 31%, to $3.91 million for the year ended December 31, 2005 from $2.98 million for the year ended December 31, 2004. The increase was primarily due to an increase in management incentive fees and costs during the year, which are based on an increase in our profitability.
Interest Expense-Interest expense decreased $80,000, or 5%, to $1.42 million for the year ended December 31, 2005 from $1.50 million for the year ended December 31, 2004. The decrease in interest expense was due to a $410,000 reduction in total debt outstanding from December 31, 2004 to December 31, 2005, along with the receipt of more favorable interest rates after refinancing our debt in March 2005.
Net Income-Net income increased $7.8 million to $16.2 million for the year ended December 31, 2005 from $8.4 million for the year ended December 31, 2004. This change was caused primarily by, as discussed above, an increase in revenues and a decrease in the cost of corn, offset by an increase in energy costs.
Liquidity and Capital Resources
Our primary sources of liquidity are cash provided by operations and borrowings under our $8.0 million revolving credit facility which is discussed below under Indebtedness. Net working capital as of December 31, 2006 was $15.8 million compared to $9.0 million as of December 31, 2005.
The following table shows the cash flows between the year ended December 31, 2006 and the year ended December 31, 2005:
Cash Flow From Operating Activities-Operating activities generated $39.6 million for the year ended December 31, 2006, compared to $26.1 million for the year ended December 31, 2005. The increase of $13.5 million in net cash flow provided from operating activities was primarily due to the significant increase in net income between periods, offset by an increase in cash used for accounts receivable and inventory.
Cash Flow From Investing Activities-Net cash flow used for investing activities increased $27.9 million between periods due to capital improvement projects. The main project in 2006 was the start of the plant’s expansion and incorporation of BPX™ technology into the production process.
We anticipate that at least $16.2 million in capital expenditures will be made in 2007, most of which will continue to relate to the plant’s expansion. These expenditures will be funded and financed by our construction loan with US Bank.
We are contemplating redeeming in 2007 all or some of the capital units owned by a member with the largest holding of units. The redemption and price at which it occur is uncertain, as we have only held informal discussions with this member to date and we are unsure how receptive this member is to the redemption. For purposes of financing the potential redemption, we retained approximately $1.69 million from the last distribution to members.
Cash Flow From Financing Activities-Net cash used for financing activities decreased $3.7 million between periods, due primarily to the $18.9 million advanced by US Bank under the construction note for expansion and BPX™. This advance was offset by a $13.5 million increase in cash paid to members for distributions during 2006.
We believe that cash flows from operations and our revolving debt will be sufficient to meet our expected capital and liquidity requirements (except for current plant expansion project) for the foreseeable future.
The following table shows the cash flows between the year ended December 31, 2005 and the year ended December 31, 2004:
Cash Flow From Operating Activities- Operating activities generated $26.1 million for the year ended December 31, 2005, compared to $11.1 million for the year ended December 31, 2004. The increase of $15.0 million in net cash flow provided from operating activities was primarily due to the significant increase in net income between periods, along with a decrease in cash used for accounts receivable and inventory.
Cash Flow From Investing Activities- Net cash flow used for investing activities decreased $820,000 between periods due in part to a refund of $200,570 from the State of South Dakota Department of Revenue for sales, use and contractors’ excise taxes paid on the original construction of the plant, and a smaller amount spent on general capital
improvement projects. In 2005, capital improvement projects included improvements for rail expansion, ethanol load-out systems, and buildings, compared to 2004 when improvements were made primarily to the plant’s dryer and electrical systems.
Cash Flow From Financing Activities- Net cash used for financing activities increased $7.9 million between periods, due primarily to an additional $11.2 million in distributions paid to members. The $11.2 million increase in total distributions paid was offset by a decrease in payments made on the long-term fixed and variable-rate notes. The decrease in payments on the long-term notes was due in part to the termination of the excess cash flow payment on the fixed-rate note in connection with a debt refinancing on March 30, 2005. As a result of the refinancing, no excess cash flow payments were made during the year ended December 31, 2005, compared to $925,708 in payments during the year ended December 31, 2004. The decrease in payments on the long-term notes was also caused by the debt refinancing in March 2005, as the principal payments on the fixed rate and variable-rate, revolving notes, which would have been normally due on March 31, 2005, were temporarily suspended until the third quarter of 2005. In addition to the offset from a decrease in payments made on the long-term fixed and variable-rate notes, the increase in cash used for financing activities was offset by an additional $1.03 million borrowed from US Bank on March 30, 2005 to pay for a rail expansion project.
Indebtedness
Our indebtedness comes in the form of five secured notes held by US Bank: 1) $33.0 million construction note; 2) a $15.8 million fixed-rate note; 3) a $3.9 million variable-rate, non-revolving note; 4) a $1.2 million fixed-rate note; and 5) an $8 million variable rate, revolving note.
The $8 million note permits us to borrow, on a revolving basis, the difference between the unpaid principal balance and $8 million. The revolving loan bears a variable-interest rate equal to the prime rate announced by US Bank from time to time, adjusted each time the Prime Rate changes. Quarterly payments of interest on any unpaid balance are due March 31, June 30, September 30, and December 31 of each year. The total unpaid principal balance is due at maturity, or August 31, 2014. The loan is subject to a quarterly unused commitment fee of .0375% and prepayment is without penalty. We had $8.0 million available under this revolver as of December 31, 2006.
The construction note is for a sum of $33 million. Half of the loan is subject to a variable rate of one-month LIBOR plus 2.75% under an interest rate swap agreement, (see Item 7A
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.
We are exposed to the impact of market fluctuations associated with commodity prices and interest rates as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in U.S. Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. Specifically, we use forward, futures and option contracts to hedge changes to the commodity prices of corn and natural gas, as well as interest rate swaps to hedge against changes in interest rates. However, we do not enter into these derivative financial instruments for trading or speculative purposes. The interest rate swap agreement is accounted for as a cash flow hedge pursuant to the requirements of SFAS 133 as amended, Accounting for Derivative Instruments and Hedging Activities.
Commodity Price Risk
We produce ethanol and its co-product, distillers grains, from corn, and, as such, we are sensitive to changes in the price of corn. The price of corn is subject to fluctuations due to unpredictable factors such as weather, total corn planted and harvested acreage, changes in national and global supply and demand, and government programs and policies. We also use natural gas in the production process, and as such are sensitive to changes in the price of natural gas. The price of natural gas is influenced by such weather factors as heat or cold in the summer and winter, in addition to the threat of hurricanes in the spring, summer and fall. Other natural gas price factors include the domestic onshore and offshore rig count, and the amount of natural gas in underground storage during both the injection (April 1st - November 7th) and withdrawal (November 14th - March 31st) seasons. The price of distillers grains is principally influenced by the price of corn and soybean meal, competing protein feed products.
We attempt to reduce the market risk associated with fluctuations in the price of corn and natural gas by employing a variety of risk management strategies. Strategies include the use of derivative financial instruments such as futures and options initiated on the Chicago Board of Trade and/or the New York Mercantile Exchange, as well as the daily cash management of our total corn and natural gas ownership relative to our monthly demand for each commodity, which may incorporate the use of forward cash contracts or basis contracts.
Corn is hedged with derivative instruments including futures and options contracts offered through the Chicago Board of Trade. Forward cash corn and basis contracts are also utilized to minimize future price risk. Likewise, natural gas is hedged with futures and options contracts offered through the New York Mercantile Exchange. Basis contracts are also utilized to minimize future price risk.
Gains and losses on futures and options contracts used as economic hedges of corn inventory, as well as on forward cash corn and basis contracts, are recognized as a component of cost of revenues for financial reporting on a monthly basis using month-end settlement prices for corn futures on the Chicago Board of Trade. Corn inventories are marked to fair value using market based prices so that gains or losses on the
derivative contracts, as well as forward cash corn and basis contracts, are offset by gains or losses on inventories during the same accounting period.
Gains and losses on futures and options contracts used as economic hedges of natural gas, as well as basis contracts, are recognized as a component of cost of revenues for financial reporting on a monthly basis using month-end settlement prices for natural gas futures on the New York Mercantile Exchange. The natural gas inventories hedged with these derivatives or basis contracts are valued at the spot price of natural gas, plus or minus the gain or loss on the futures or options positions relative to the month-end settlement price on the New York Mercantile Exchange.
A sensitivity analysis has been prepared to estimate our exposure to commodity price risk. The table presents the fair value of open futures and option positions for corn, natural gas and distillers grains as of December 31, 2006 and December 31, 2005 and the potential loss in fair value resulting from a hypothetical 10% adverse change in corn, natural gas prices and distillers grains’. The fair value of the positions is a summation of the fair values calculated by valuing each net position at quoted market prices as of the applicable date. The results of this analysis, which may differ from actual results, are as follows:
Interest Rate Risk
Our interest rate risk exposure pertains primarily to our variable rate, long-term debt. Specifically, we had $5.93 million in variable rate, long-term debt as of December 31, 2006, or approximately 16% of our total indebtedness. The interest rate on $3.22 million of the variable rate, long-term debt is US Bank’s prime rate, which was 8.25% as of December 31, 2006. The variable portion of the construction note debt was $2.71 million as of December 31, 2006, and was at 8.1% based on One-Month LIBOR plus 2.75%. We manage our interest rate risk by monitoring the effects of market changes on the interest rates and using fixed-rate debt whenever possible and using the interest rate swap agreement on the construction note.
In order to achieve a fixed interest rate on a portion ($16.252 million) of our total construction loan ($33.0 million), we entered into an interest rate swap agreement with US Bank. This agreement includes the construction period from September 29, 2006 through August 31, 2007 as well as the seven-year term financing period through August 31, 2014. When the construction loan converts to the permanent loan on August 31, 2007, the swap agreement then covers $16.5 million of the total construction loan amount. This agreement assists us in protecting against exposure to increases in interest rates and fixes the interest rate on 50% of the total construction loan at 7.98% until August 31, 2014. The agreement is based on a variable rate of One-Month LIBOR plus 2.75%, and is swapped for a fixed rate of 7.98% with monthly interest settlements. While our exposure is now reduced, there can be no assurance that the interest rate swap will provide us with protection in all scenarios. For example, when One-Month LIBOR plus
2.75% exceeds 7.98%, we receive payments for the difference between the market rate and the swap rate. Conversely, when the One-Month LIBOR plus 2.75% falls below 7.98%, we make payments for the difference. We are exposed to the impact of market fluctuations associated with commodity prices and interest rates as discussed below. We have no exposure to foreign currency risk as all of our business is conducted in U.S. Dollars. We use derivative financial instruments as part of an overall strategy to manage market risk. Specifically, we use forward, futures and option contracts to hedge changes to the commodity prices of corn and natural gas. However, we do not enter into these derivative financial instruments for trading or speculative purposes.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the “Index to Financial Statements” of Northern Growers, LLC located at page of this report, and financial statements for the year ended December 31, 2006 referenced therein, which are hereby incorporated by reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. Our management, including the participation of our Chief Executive Officer/Chief Financial Officer, has concluded that, based on management’s evaluation as of the end of the period covered by this Annual Report on Form 10-K, the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Additionally, based on management’s evaluation, our disclosure controls and procedures were effective in ensuring that information required to be disclosed in our Exchange Act reports is accumulated and communicated to our management, including our Chief Executive Officer/Chief Financial Officer, to allow timely decisions regarding required disclosures.
Management’s report on internal control over financial reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use, or disposition of our assets that could have a material effect on the 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 the policies or procedures may deteriorate.
Management has assessed our internal control over financial reporting in relation to criteria described in Internal Control- Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment using those criteria, we concluded that, as of December 31, 2006, our internal control over financial reporting was effective.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by Eide Bailly LLP, an independent registered public accounting firm, as stated in their report which appears on page of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
/s/ Robert Narem
Robert Narem, Chief Executive Officer
and Chief Financial Officer, Manager
(Principal Executive Officer)
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Compliance with Section 16(a) of the Exchange Act
Information regarding untimely filings pursuant to Section 16 of the Securities Exchange Act of 1934, as amended, is incorporated in this Form 10-K by reference from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Code of Ethics
Information regarding a code of ethics is incorporated in this Form 10-K by reference to Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Directors
Information regarding Northern Growers’ board of managers is incorporated in this Form 10-K by reference from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Executive officers
Information required by this item regarding the business experience of an executive is incorporated in this Form 10-K by reference from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Item 11.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference in this Form 10-K from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference in this Form 10-K from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Directors Independence.
The information required by this item is incorporated by reference in this Form 10-K from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference in this Form 10-K from Northern Growers’ Information Statement for the Annual Meeting of Members to be held in 2007, a copy of which will be filed with the Commission not later than 120 days after December 31, 2006.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following exhibits and financial statements are filed as part of, or are incorporated by reference into, this report:
(1) Financial Statements-Reference is made to the “Index to Financial Statements” of Northern Growers, LLC located at page of this report for a list of the financial statements and schedules for the year ended December 31, 2006 included herein.
(2) All supplemental schedules are omitted because of the absence of conditions under which they are required or because the information is shown in the Consolidated Financial Statements or notes thereto.
(3) The exhibits we have filed herewith or incorporated by reference herein are set forth on the attached Exhibit Index. The following exhibits constitute a management contract: 10.18 and 10.20.
(b) See Item 15(a)(3)
SIGNATURES
Pursuant to the requirement of Section 13 or 15(d) of the Securities Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHERN GROWERS, LLC
Date:
March 16, 2007
/s/ Robert Narem
Robert Narem, Chief Executive
Officer/Chief Financial Officer
(Principal Executive and Financial Officer)
Pursuant to the requirements of the Securities 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.
NORTHERN GROWERS, LLC
Date:
March 16, 2007
/s/ Robert Narem
Robert Narem, Chief Executive Officer
and Chief Financial Officer, Manager
Date:
March 16, 2007
/s/ Ronald Anderson
Ronald Anderson, Manager
Date:
March 16, 2007
/s/ Wendall Falk
Wendell Falk, Manager
Date:
March 16, 2007
/s/ Dennis Flemming
Dennis Flemming, Manager
Date:
March 16, 2007
/s/ Lars Herseth
Lars Herseth, Manager
Date:
March 16, 2007
/s/ Mark Lounsbery
Mark Lounsbery, Manager
Date:
March 16, 2007
/s/ Robert Metz
Robert Metz, Manager
Date:
March 16, 2007
/s/ Jeff Olson
Jeff Olson, Manager
Date:
March 16, 2007
/s/ Ronald Olson
Ronald Olson, Manager
Date:
March 16, 2007
/s/ Heath Peterson
Heath Peterson, Manager
Date:
March 16, 2007
/s/ Delton Strasser
Delton Strasser, Manager
Date:
March 16, 2007
/s/ Steve Street
Steve Street, Manager
Date:
March 16, 2007
/s/ Bill Whipple
Bill Whipple, Manager
Date:
March 16, 2007
/s/ Robert Wittnebel
Robert Wittnebel, Manager
EXHIBIT INDEX
Exhibit
No.
Description
Filed
Herewith
Incorporated by
Reference
2.1
Plan of Organization
Appendix A to Registrant’s Prospectus filed with the Commission on March 17, 2003.
3.1
Articles of Organization
Appendix B to Registrant’s Prospectus filed with the Commission on March 17, 2003.
3.2
Fourth Amended and Restated Operating Agreement dated July 1, 2006.
Exhibit 3.2 to the Registrant’s Form 10-Q filed with the Commission on August 14, 2006.
4.1
Form of Class A Certificate
Exhibit 4.1 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.1
Ethanol Marketing and Services Agreement with Ethanol Products, LLC, dated March 5, 2002.
Exhibit 10.5 to the Registrant’s Form S-4/A filed with the Commission on January 8, 2003.
10.2
DDGS Marketing Agreement with Dakota Commodities (a/k/a Dakota Gold Marketing), dated April 10, 2002.
Exhibit 10.6 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.3
Loan Agreement with US Bank, dated July 11, 2001.
Exhibit 10.7 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.4
Lease Agreement with Big Stone - Grant Industrial Development and Transportation, dated April 18, 2001.
Exhibit 10.9 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.5
Steam Sale Agreement with Otter Tail Power Company, dated April 18, 2001.
Exhibit 10.10 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.6
Water and Fuel Oil Agreement with Otter Tail Power Company, dated August 14, 2001.
Exhibit 10.11 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.7
Electric Service Agreement with Otter Tail Power Company, dated September 26, 2001.
Exhibit 10.12 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.8
Water and Sanitary Sewer Agreement with the City of Big Stone City, dated December 21, 2001.
Exhibit 10.13 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.9
Access and Rail Agreement with Otter Tail Corporation, dated April 18, 2001.
Exhibit 10.14 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.10
Industry Track Agreement with Burlington Northern and Santa Fe Railway Company, dated January 8, 2002.
Exhibit 10.15 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.11
Service Request Form and Extended Service Agreement with NorthWestern Public Service, dated March 19, 2002.
Exhibit 10.17 to the Registrant’s Form S-4 filed with the Commission on July 26, 2002.
10.12
Mortgage in favor of US Bank, dated December 31, 2002.
Exhibit 10.23 to the Registrant’s Form S-4/A filed with the Commission on January 8, 2003.
10.13
$1.2 million Promissory Note with US Bank, dated May 1, 2003.
Exhibit 10.18 to the Registrant’s Form 10-QSB filed with the Commission on August 14, 2003.
10.14
Amendment to US Bank Loan Agreement, dated June 22,
Exhibit 10.1 to the Registrant’s Form 10-Q filed with the Commission on August 16, 2004.
10.15
Second Amendment to US Bank Loan Agreement, dated March 30, 2005.
Exhibit 10.26 to the Registrant’s Form 10-K filed with the Commission on March 31, 2005.
10.16
$15.8 Million Promissory Note with US Bank, dated March 30, 2005.
Exhibit 10.27 to the Registrant’s Form 10-K filed with the Commission on March 31, 2005.
10.17
$3.9 Million Promissory Note with US Bank, dated March 30, 2005.
Exhibit 10.28 to the Registrant’s Form 10-K filed with the Commission on March 31, 2005.
10.18
Management Agreement with Broin Management, LLC, dated April 20, 2005.
Exhibit 10.2 to the Registrant’s Form 10-Q filed with the Commission on May 16, 2005.
10.19
Technology and Patent Rights License Agreement with Broin and Associates, LLC, dated October 25, 2005. *
Exhibit 10.1 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2005.
10.20
Amendment to the Management Agreement with Broin Management, dated October 25, 2005.
Exhibit 10.2 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2005.
10.21
Design Build Agreement with Broin and Associates, Inc., dated October 25, 2005.
Exhibit 10.3 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2005.
10.22
Amended and Restated Loan Agreement dated August 28,
Exhibit 10.1 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
10.23
Expansion Construction Note Agreement dated August 28, 2006
Exhibit 10.2 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
10.24
$8.0 Million Variable Rate, Revolving Note dated August 28, 2006
Exhibit 10.3 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
10.25
Construction Mortgage and Addendum dated August 28,
Exhibit 10.4 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
10.26
Security Agreement dated August 28, 2006
Exhibit 10.5 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
10.27
Corn and Natural Gas Price Risk Management Agreement, dated November 3, 2006
Exhibit 10.6 to the Registrant’s Form 10-Q filed with the Commission on November 14, 2006.
21.1
Subsidiaries of the Registrant.
X
Rule 13a-14(a)/15d-14(a) Certifications
X
Section 1350 Certification
X
*The redacted portions of this exhibit were filed separately with the SEC subject to a request for confidential treatment dated November 14, 2005
NORTHERN GROWERS, LLC
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED FINANCIAL STATEMENTS
Balance Sheets
Statements of Operations
Statements of Changes in Members’ Equity and Comprehensive Income
Statements of Cash Flows
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Audit Committee and Members
Northern Growers, LLC
Big Stone City, South Dakota
We have audited the accompanying consolidated balance sheets of Northern Growers, LLC as of December 31, 2006 and 2005, and the related consolidated statements of operations, members’ equity and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2006. We also have audited management’s assessment, included in the accompanying Form 10-K, that Northern Growers, LLC maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Northern Growers, LLC’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern Growers, LLC as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, management’s assessment that Northern Growers, LLC maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Furthermore, in our opinion, Northern Growers, LLC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Sioux Falls, South Dakota
March 14, 2007
PEOPLE. PRINCIPLES. POSSIBILITIES.
www.eidebailly.com
200 E. 10th Street, Suite 500 · PO Box 5125 · Sioux Falls, South Dakota 57117-5125 · Phone 605.339.1999 · Fax 605.339.1306 · EOE
NORTHERN GROWERS, LLC CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements
NORTHERN GROWERS, LLC CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements
NORTHERN GROWERS, LLC CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
See Notes to Consolidated Financial Statements
NORTHERN GROWERS, LLC CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY AND COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
See Notes to Consolidated Financial Statements
NORTHERN GROWERS, LLC CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
See Notes to Consolidated Financial Statements
(continued on next page)
CONSOLIDATED STATEMENTS OF CASH FLOWS - page 2
See Notes to Consolidated Financial Statements
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS
Principal Business Activity
Northern Growers, LLC or Northern Growers (formerly Northern Growers Cooperative or the “Cooperative”), is a South Dakota limited liability company that was organized to pool investors, provide a portion of the corn supply for a 40 million gallon name-plate annual capacity ethanol plant “the plant” owned by Northern Lights Ethanol, LLC “Northern Lights”, and own a 77.16% interest in Northern Lights. For purposes of the financial statements and notes, the “Company” refers to both Northern Growers and Northern Lights on a consolidated basis. Northern Lights was formed on February 14, 2001. On June 26, 2002, the plant began grinding corn and on July 5, 2002, the plant commenced its principal operations. The Company sells ethanol and related products primarily in the United States.
On April 1, 2002, Whetstone Ethanol, LLC “Whetstone” was formed. The initial member of Whetstone was the Cooperative. Whetstone was formed for the purpose of acquiring the assets and liabilities of the Cooperative. On April 10, 2002, the Board of Directors of the Cooperative approved a plan of reorganization related to an exchange whereby Whetstone would acquire the assets and liabilities of the Cooperative. On March 27, 2003, the members of the Cooperative approved the plan of reorganization to take effect on April l, 2003. The transaction was an exchange of interests whereby the assets and liabilities of the Cooperative were transferred for capital units of Whetstone. For financial statements purposes, no gain or loss was recorded as a result of the exchange transaction.
As a result of the exchange, the Cooperative was dissolved, with Whetstone’s capital units distributed to the members of the Cooperative at a rate of one Whetstone capital unit for each share of equity common stock and all voting common stock of the Cooperative surrendered and retired. In connection with the reorganization, Whetstone subsequently changed its name to Northern Growers, LLC. Under the amended Northern Growers’ Operating Agreement, a minimum of 2,500 capital units is required to become a member. Such units are subject to certain transfer restrictions, including approval by the Board of Managers of Northern Growers. Northern Growers also retains the right to redeem the capital units at $.20 per unit in the event a member attempts to dispose of the units in a manner not in conformity with the Operating Agreement, if a member becomes a holder of less than 2,500 units or if a member becomes bankrupt. The Operating Agreement also includes provisions whereby cash flow in excess of $200,000 will be distributed to unit holders subject to limitations imposed by a super majority vote of the Board of Managers or restrictions imposed by loan covenants.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Northern Growers and its 77.16% owned subsidiary, Northern Lights. All significant inter-company transactions and balances have been eliminated in consolidation.
Cash and Cash Equivalents
Cash and cash equivalents consist of demand accounts and other accounts that provide withdrawal privileges.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Recognition
Revenue from the production of ethanol and related product is recorded upon transfer of title to customers, net of allowances for estimated returns on related products. Generally, ethanol is shipped FOB shipping point and related product is shipped FOB destination. Interest income is recognized as earned.
Revenue from federal and state incentive programs is recorded when the Company has produced or sold the ethanol and satisfied the reporting requirements under each applicable program. When it is uncertain that the Company will receive full allocation and payment due under the incentive programs, it derives an estimate of the incentive revenue for the relevant period based on various factors. The estimate is subject to change as management becomes aware of increases or decreases in the amount of funding available under the incentive programs or other factors that affect funding or allocation of funds under such programs.
Shipping Costs
Freight charges incurred are reported as a component of cost of revenues.
Receivables and Credit Policies
Trade receivables are uncollateralized customer obligations due under normal trade terms requiring payment within 30 days from the invoice date. Customer account balances with invoices dated over 30 days old are considered delinquent. Interest is not charged on any delinquent accounts.
Trade receivables are stated at the amount billed to the customer.
Payments of trade receivables are allocated to the specific invoices identified on the customer’s remittance advice or, if unspecified, are applied to the earliest unpaid invoices.
The carrying amount of trade receivables is reduced by a valuation allowance that reflects management’s best estimate of the amounts that will not be collected. Management reviews all trade receivable balances that exceed 30 days from the invoice date and based on an assessment of current creditworthiness, estimates the portion, if any, of the balance that will not be collected. Management believes that all trade receivables are collectible; therefore, there is no valuation allowance as of December 31, 2006 and 2005.
Inventory
Ethanol and related product inventory is stated at net realizable value. Corn inventory is stated at market value, which approximates net realizable value (local market prices less cost of disposal), based on local market prices determined by grain terminals in the area of the plant. Other raw materials, spare parts and work-in-process inventory are stated at the lower of cost or market on an average cost method.
Inventories at December 31, 2006 and 2005 are as follows:
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Investment in Commodities Contracts, Derivative Instruments and Hedging Activities
SFAS No. 133 requires a company to evaluate its contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS No. 133.
The Company enters into short-term cash, options and futures contracts as a means of securing corn and natural gas for the ethanol plant and managing exposure to changes in commodity prices. All derivatives are designated as non-hedge derivatives. Although the contracts are effective economic hedges of specified risks, they are not designated as and accounted for as hedging instruments.
As part of its trading activity, the Company uses futures and option contracts offered through regulated commodity exchanges to reduce risk and is exposed to risk of loss in the market value of inventories. To reduce that risk, the Company generally takes positions using cash and futures contracts and options.
Unrealized gains and losses related to derivative contracts are included as a component of cost of revenues in the accompanying consolidated financial statements. Inventories are recorded at net realizable value so that gains and losses on derivative contracts are offset by gains and losses on inventories and reflected in current earnings. For the statement of cash flows, such contract transactions are classified as operating activities.
The Company has recorded an increase (decrease) to cost of revenues of $3,181,810, ($211,011) and $3,719,496 related to our derivative contracts for the year ended December 31, 2006, 2005 and 2004, respectively. These derivative contracts can be found on the Balance Sheet under “Investment in commodities contracts”.
During the year ended December 31, 2006, the Company entered into derivative financial instruments to limit its exposure to changes in interest rates. The Company entered into an interest rate swap agreement as part of its interest rate risk management strategy and to effectively convert a portion of its variable rate debt to fixed rate debt. The swap agreement is accounted for as a cash flow hedge under SFAS No. 133, as amended. The Company did not have any derivative instruments designated as cash flow hedges as of December 31, 2005.
Interest Rate Swap Agreement
During the year ended December 31, 2006, the Company entered into an interest rate swap agreement as part of its interest rate risk management strategy and to effectively convert a portion of its variable rate debt to fixed rate debt. The swap agreement, which expires August 31, 2014, is accounted for as a cash flow hedge under SFAS No. 133, as amended. Under the terms of the swap, the Company’s net payment is a fixed interest rate on the notional amount in exchange for receiving a variable rate based on one month LIBOR. The swap transaction qualifies for the shortcut method of recognition under SFAS No. 133; therefore, no portion of the swap is treated as ineffective. The notional amount of the interest rate swap as of December 31, 2006 was $16,252,000. As of December 31, 2006, $187,069 has been recorded as a current derivative liability to record the fair value of the swap, with a corresponding entry of $144,342 to accumulated other comprehensive loss in the members’ equity section of the balance sheet and a decrease of $42,727 to minority interest.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Comprehensive Income (Loss)
The Company has adopted Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income (“SFAS 130”) that establishes standards for reporting comprehensive income. The Statement defines comprehensive income as the changes in equity of an enterprise except those resulting from stockholder transactions. As of December 31, 2006, accumulated other comprehensive loss consists of an unrealized loss from our interest rate swap agreement designated as a cash flow hedge.
Minority Interest
Amounts recorded as minority interest on the balance sheet relate to the investment by Broin Investments I, LLC in Northern Lights, plus or minus any allocation of income or loss of Northern Lights, plus or minus any allocation of accumulated other comprehensive income or loss, less distributions from Northern Lights. Earnings/losses and distributions of Northern Lights are allocated to its members in proportion to the member’s capital accounts.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.
Concentrations of Credit Risk
Cash balances are maintained in bank depositories and periodically exceed federally insured limits.
Property and Equipment
Property and equipment is stated at cost. Significant additions and betterments are capitalized, while expenditures for maintenance, repairs and minor renewals are charged to operations when incurred. Depreciation on assets placed in service is computed using the straight-line method over estimated useful lives as follows:
Land improvements consist of landscaping, additional fencing and improvements to the roads for entering and exiting the plant.
Equipment consists of grain systems, trucks, mechanical and electrical production and process equipment, cooling towers, boilers and a reboiler, field sensors and power supplies.
Buildings consists of administrative offices, sheds, catwalks, platforms, and mechanical and grain buildings.
The Company reviews its property and equipment for impairment whenever events indicate that the carrying amount of the asset may not be recoverable. An impairment loss is recorded when the sum of the future cash flows is less than the carrying amount of the asset. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds its fair value.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A loss on impairment of assets of $450,362 was recognized by the Company’s management during October 2006 and is included in cost of revenues. With the completion and incorporation of BPXTM technology into the plant production process on October 12, 2006, there were multiple tanks, motors and other equipment that were deemed unusable. Two tanks were sold and the balance of the equipment was determined to have no value and that any scrap value the equipment had would approximate the costs of disposal.
A loss on impairment of assets for $355,177 was recognized by the Company’s management during October 2005 and is included in cost of revenues. A subset of the thermal oxidizers was deemed impaired/inoperable and no longer useful due to extreme internal heat damage, although the plant continues to meet all regulatory requirements without the operation of this subset of the thermal oxidizers. Due to the extreme degradation of the equipment, it was determined to have no value and that any scrap value the equipment had would approximate the costs of disposal.
Environmental Liabilities The Company’s operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdiction in which it operates. These laws require the Company to investigate and remediate the effects of the release or disposal of materials at its locations. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, occupational health, and the production, handling, storage and use of hazardous materials to prevent material environmental or other damage, and to limit the financial liability which could result from such events. Environmental liabilities are recorded when the liability is probable and the costs can be reasonably estimated.
Income Taxes
The Company is not a taxpaying entity for federal and state income tax purposes and thus no income tax expense has been recorded in the statements. Income of the Company is taxed to the members in their respective returns.
Cost of Revenues
The primary components of cost of revenues from the production of ethanol and related products are corn expense, energy expense (steam, natural gas and electricity), raw materials expense (chemicals and denaturant), shipping costs on sales and depreciation on process equipment.
All shipping costs incurred with regard to the sale of ethanol and related product inventory are included in the consolidated statements of operations as a component of gross revenues. Accordingly, those shipping costs are deducted and are all classified as a component of cost of revenues. Shipping costs in relation to sales are defined as the cost to transport products to customers. Other shipping costs in the cost of revenues include inbound freight charges on inventory.
General and Administrative Expenses
The primary components of general and administrative expenses are management fees, insurance expense and professional fees (legal and audit).
Recently Issued Accounting Pronouncements
In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements”. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
disclosure about fair value measurement. The implementation of this guidance is not expected to have a material impact on the Company’s financial statements.
In September 2006, the United States Securities and Exchange Commission (“SEC”), adopted SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” This SAB provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 establishes an approach that requires quantification of financial statement errors based on the effects of each of the company’s balance sheets and statements of operations and the related financial statement disclosures. The SAB permits existing public companies to record the cumulative effect of initially applying this approach in the first year ending after November 15, 2006 by recording the necessary correcting adjustments to the carrying values of assets and liabilities as of the beginning of that year with the offsetting adjustment recorded to the opening balance of retained earnings. Additionally, the use of the cumulative effect transition method requires detailed disclosure of the nature and amount of each individual error being corrected through the cumulative adjustment and how and when it arose. The Company expects that the adoption of SAB 108 will not have a material impact on its financial statements.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109.” This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The Interpretation is effective for fiscal years beginning after December 15, 2006 and the Company expects that the adoption of FASB Interpretation No. 48 will not have a material impact on its financial statements.
NOTE 3 - NOTES PAYABLE
Short-Term Notes Payable
Northern Growers received advances of $5,000 from various entities to help establish the Company. The notes are due on demand and do not bear interest. The balance of this non-interest bearing note was $5,000 at December 31, 2006 and 2005.
Long-Term Notes Payable
Prior to entering into a refinancing agreement on March 30, 2005, Northern Lights had four loans outstanding with US Bank National Association, Sioux Falls, South Dakota (Bank): a $15.0 million fixed-rate note; an $11.1 million variable-rate non-revolving note; a $5.0 million variable-rate, revolving note; and a $1.2 million fixed-rate note. The financing arrangements for the fixed rate note required Northern Lights to make additional principal payments equal to 15% of its excess cash flow (as defined by the agreement), not to exceed 20% of the outstanding principal balance. In conjunction with the Northern Lights distributions on February 10, 2004 and November 12, 2004, additional excess cash flow payments of $335,664 and $590,044, respectively, were made on the fixed-rate note.
On March 30, 2005, Northern Lights and the Bank entered into an amended loan agreement. The purpose of the agreement was to refinance existing debt and to finance a planned rail expansion project. Effective March 30, 2005, five loans with the Bank became outstanding: a $15.8 million fixed-rate note; a $3.9 million variable-rate, non-revolving note; the $5 million variable-rate, revolving note; a $3.0 million variable-rate, revolving note; and the $1.2 million note. As part of the refinancing, the $15 million fixed-rate note and the $11.1 million variable-
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
rate, non-revolving note were retired and an additional $1,032,369 was borrowed for the rail expansion project and included in the refinancing.
The $15.8 million fixed-rate note bears an interest rate of 6.38%. This note requires quarterly payments of interest and amortized principal on the basis of a ten-year term and is subject to maturity on March 31, 2012. The first payment was made on June 30, 2005.
The $3.9 million variable-rate, non-revolving note bears interest at the Bank’s prime rate, or 8.25% at December 31, 2006. This note requires quarterly payments of interest and amortized principal on the basis of a ten-year term, the first payment being made on June 30, 2005. The note matures on March 31, 2012.
The $1.2 million fixed rate note bears interest at 4.7%, and requires quarterly payments of principal and interest until maturity on April 30, 2007.
On August 28, 2006, Northern Lights entered into an amended and restated loan agreement with the Bank for the purpose of financing the plant’s expansion and restructuring the $3.0 million and $5.0 million revolving notes into one note. The new construction note is for a sum of $33 million. Half of the loan is subject to the interest rate swap agreement discussed in Note 2 under “Interest Rate Swap Agreement”. On October 16, 2006, the Bank funded to us $16,252,360 in one lump sum under the construction note subject to the interest rate swap agreement. The construction loan will be converted to a term loan no later than August 31, 2007 under the restated loan agreement. The term loan will be subject to two interest rate options at the time of conversion, a variable-interest rate or a fixed interest rate. The variable rate will be subject to the same rate as the prime rate construction loan, while the term loan will be subject to a rate agreed to between the parties. Regardless of the rate, the loan will be amortized over a ten-year period commencing August 31, 2007 and is subject to a maturity no later than August 31, 2014. Payments of principal and interest are due quarterly beginning November 30, 2007.
The restated loan agreement restructures the $3.0 million and $5.0 million notes into a single $8 million revolving note. The new revolving note permits Northern Lights to borrow, on a revolving basis, the difference between the unpaid principal balance and $8 million. The revolving note bears a variable-interest rate equal to the prime rate announced by the Bank from time to time, adjusted each time the Prime Rate changes. Quarterly payments of interest on any unpaid balance are due March 31, June 30, September 30, and December 31 of each year. The total unpaid principal balance is due at maturity, or August 31, 2014. The loan is subject to a quarterly unused commitment fee of .0375% and prepayment is without penalty.
Northern Lights is subject to certain restrictive covenants establishing minimum reporting requirements, ratios, working capital and net worth requirements and is in full compliance at December 31, 2006. Collateral for the notes is multiple mortgages and security agreements, multiple UCC filings on all business assets, and assignments of certain agreements related to the construction and operation of the plant.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The balance of the long-term notes payable as of December 31, 2006 and 2005 is as follows:
At December 31, 2006 and 2005, there were no outstanding borrowings against the variable rate revolving notes and the balance available on these notes was $8,000,000.
Minimum principal payments, through the maturity of the notes, are estimated as follows:
NOTE 4 - RELATED PARTY TRANSACTIONS
Northern Growers and Broin Investments I, LLC, are the members of Northern Lights. Northern Growers invested $12,500,000 and Broin Investments I, LLC invested $3,700,000 in Northern Lights Ethanol, LLC for their respective ownership interests of approximately 77% and 23%. In accordance with the Operating Agreement of Northern Lights, Broin Investments I, LLC, has the right to elect two of seven members of the Board of Managers of Northern Lights.
Additional agreements with related parties are included in Note 6.
NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company believes the carrying amount of cash and cash equivalents approximates fair value due to the short maturity of these instruments.
As of December 31, 2005, and subsequent to the refinancing in March 2005, the Company believed the carrying amount of long-term note payable obligations exceeded fair value. As the following table presents, the carrying
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
amount of long-term note payable obligations exceeds the fair value by approximately $348,000 and $840,000 at December 31, 2006 and 2005, respectively.
The Company believes the carrying amount of short-term notes payable approximates their value due to the short maturity of these instruments.
NOTE 6 - COMMITMENTS, CONTINGENCIES AND AGREEMENTS
Substantially all of the Company’s facilities are subject to federal, state and local regulations relating to the discharge of materials into the environment. Management believes that the current practices and procedures for the control and disposition of such wastes comply with the applicable federal, state and local requirements.
The Company has entered into contracts and agreements regarding the construction, operation and management of the ethanol plant. Agreements with Broin Investments I, LLC, the minority member of Northern Lights, or parties related to the minority member through common ownership, are as follows:
Original Construction Agreement - The Company had a construction agreement with Broin and Associates, Inc., an affiliate of the minority member of Northern Lights. The agreement, with change orders, totals $47,615,981, all of which was complete as of December 31, 2006.
Expansion Construction Agreement - The Company entered into a Design/Build Agreement with Broin and Associates on October 25, 2005. The purpose of this agreement is to expand the name-plate production capacity of the plant from 40 million gallons of ethanol annually to 75 million gallons of ethanol annually, as well as to make certain capital improvements to the plant for the incorporation of new raw starch technology. The estimated cost of construction and improvements for both projects is $42.4 million, with a remaining commitment of $14.0 million to be met with the balance of the US Bank construction note. The liability incurred on this construction contract was $2,173,905 and $0 at December 31, 2006 and 2005, respectively.
Ethanol Marketing Agreement - The Company has an agreement with Ethanol Products, LLC, for the sale, marketing, billing and receipt of payment and other administrative services for all ethanol produced by the plant. The agreement expires on July 5, 2007, and is automatically renewed for successive five-year terms unless terminated three months prior to expiration. The Company has sales commitments of approximately 24 million gallons over the next twelve months.
Management Agreement - On April 20, 2005, the Company renewed its agreement with Broin Management, LLC for the management and operation of the plant. The original agreement was executed on November 2, 2000 and remained in effect until July 1, 2005. The term of the new management agreement, as amended, continues through June 30, 2015. In exchange for these services, Broin Management receives an annual fee of $450,000, payable in equal monthly installments, plus an incentive bonus based on a percentage of net income, payable quarterly. The annual fee is adjusted each year on March 1st for changes in the consumer price index. The fees and bonus paid to Broin Management include the salary and benefits of the general manager and technical manager and certain other services related to operation of the plant.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Technology and Patent Rights License Agreement - On October 25, 2005, the Company entered into a Technology and Patent Rights License Agreement with Broin and Associates, Inc. Under this agreement, Broin and Associates granted the Company a non-exclusive license to use certain technology and patents owned, developed, or obtained by Broin and Associates relating to the ethanol and related product production processes. The Company is required to pay an annual licensing fee for the right to use such technology and patents. The term of this agreement continues until June 30, 2015.
Risk Management Agreement - During October 2006, the Company renewed its agreement with Broin Management, LLC for corn and natural gas price risk management for the plant. The original agreement was executed on August 1, 2003 and remains in effect until January 1, 2007, the effective date of the new agreement. The term of the new risk management agreement continues through December 31, 2011 and will be automatically extended for an additional five (5) year term unless either party gives written notice ninety (90) days prior to expiration. In exchange for services relating to hedging and price risk management for corn and natural gas for the plant, Broin Management receives an annual fee of $55,920, payable in equal quarterly installments, subject to modification in the case of plant expansions or increases in corn usage.
Distillers Grains Marketing Agreement - The Company has an agreement with Dakota Gold Marketing, a related party through ownership by entities related to the minority member, to provide marketing and administrative services for the sale of distillers grains. The agreement commenced on March 8, 2002 and has a term of five years, renewing for five-year terms unless terminated by either party with 90 days notice prior to expiration. The agreement provides for an agency relationship in that Dakota Gold Marketing does not take title to the distillers grains but acts as a broker on behalf of the Company.
Revenues and expenses related to agreements with related parties for the years ended December 31, 2006, 2005 and 2004 are as follows:
Agreements with unrelated parties are as follows:
Property Lease - The Company has a ninety-nine-year property lease (an operating lease) with Big Stone-Grant Industrial Development and Transportation, LLC. Rent was $2,400 annually for each of the first five years beginning in 2001. Beginning on May 1, 2006, and every five years thereafter, rent is increased 5% over the immediately preceding five-year period.
Steam - The Company has an agreement with the co-owners of the Big Stone Plant “Big Stone Plant”; Otter Tail Corporation, Montana-Dakota Utilities Co. and Northwestern Public Service, for steam in a specified amount for use in its ethanol manufacturing process at a base rate, adjusted annually for changes in the cost of energy. The agreement commenced on June 1, 2002 and has a term of ten years, renewable for two five-year periods, after which the agreement is renewable from year to year. Either party may terminate the agreement by providing notice one year prior to a renewal or expiration date. Please see Note 12 - Cost of Revenues - Settlement Credit, for further details on the steam agreement with the Big Stone Plant.
Expenses related to the property lease and steam agreements for the years ended December 31, 2006, 2005 and 2004 were $3,052,843, $2,361,367 and $3,378,906, respectively.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Minimum payments related to the above agreements are summarized in the following table:
Corn Delivery - On August 9, 2005, Northern Lights agreed to release Northern Growers and, accordingly, all of its members from delivering corn to the plant starting on January 1, 2006. Prior to January 1, 2006, Northern Growers’ members were obligated to deliver corn to the plant unless the plant released the member from the member’s corn delivery obligation. Effective January 1, 2006, however, Northern Growers’ members are no longer obligated to deliver corn to the plant. Instead, the plant purchases all of its corn from local corn producers and the open market. In addition, Northern Lights agreed to honor all member forward contracts for 2006 delivery if the contract was written by September 15, 2005. Purchases of corn from corn delivery agreements and cash contracts from the Northern Growers’ members totaled approximately $26,346,000, $22,016,000 and $33,300,000 for the years ending December 31, 2006, 2005 and 2004, respectively, of which $1,505,428 and $1,810,245 was recorded as a liability at December 31, 2006 and 2005, respectively.
Incentive Revenue - The Company received an incentive payment from the United States Department of Agriculture (USDA) for the use of corn to produce ethanol. The program ended June 30, 2006. In accordance with the terms of this arrangement, revenue is recorded based on incremental production of ethanol compared to the prior year. The USDA has set the annual maximum not to exceed $7,500,000 for each eligible producer. The incentive is calculated on the USDA fiscal year of October 1 to September 30. Revenue of $31,385, $26,835 and $1,064,644 has been earned for the USDA program years ended September 30, 2006, 2005 and 2004, respectively. Incentive revenue of $8,551, $48,681 and $932,477 was recorded for the years ended December 31, 2006, 2005 and 2004, respectively, for this program.
The Company also receives an incentive payment from the State of South Dakota to produce ethanol. In accordance with the terms of this arrangement, revenue is recorded based on ethanol sold. The State of South Dakota has set a maximum of up to $1,000,000 per year for this program per qualifying producer. The Company has earned $500,000, $776,333 and $705,404 for the program years ended June 30, 2007, 2006 and 2005, respectively. Incentive revenue of $776,333, $705,404 and $666,667 was recorded for the years ended December 31, 2006, 2005 and 2004, respectively, for this program.
Legal Proceedings - The Company is involved in various legal actions arising in the normal course of business. Management is of the opinion that their outcome will not have a significant effect on the Company’s consolidated financial statements.
Capital Unit Trading - On March 8, 2004, Northern Growers’ members and non-members began trading Northern Growers capital units on an alternative trading system operated by Alerus Securities Corporation of West Fargo, North Dakota.
NORTHERN GROWERS, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Contingency - In January 2003, the Environmental Protection Agency (EPA) issued formal information requests to, among others, plants designed, constructed, and/or managed by Broin and Associates and Broin Management. By virtue of the nature and timing of these requests, the Company’s plant became subject to these requests. The requests required that the subject plants provide the EPA with certain data regarding emissions, presumably to determine whether the applicable plants were in compliance with the Clean Air Act. After this information was provided to the EPA, Broin and Associates, on behalf of the Company and the subject plants managed by Broin Management, initiated discussions with the EPA regarding the application and use of testing methods for quantifying certain types of emissions emanating from these plants.
To date, no legal proceeding is pending with or threatened by the EPA, nor has Broin and Associates resolved with the EPA the application and use of the proper testing method for quantifying emissions. If a proceeding were initiated or settlement reached with the EPA, fines and/or other penalties against the Company could result, the nature and scope of which is uncertain. While there is a reasonable possibility of fines and/or other penalties in the event of any proceeding or settlement, until the EPA and Broin and Associates resolve what the proper testing method will be for measuring emissions, the Company is unable to estimate the scope and magnitude of any possible fine or other penalty. Accordingly, the Company has not accrued any amount to its consolidated statement of operations relating to any potential claim.
NOTE 7 - DISTRIBUTIONS
During November 2004, Northern Lights approved a $3,000,000 distribution, which it paid on November 12, 2004. Northern Growers received $2,314,800 and the minority member received $685,200. In conjunction with this cash distribution, Northern Growers paid a distribution to its members of $2,214,975.
During January 2005, Northern Lights approved a $5,000,000 distribution, which it paid on February 1, 2005. Northern Growers received $3,858,000 and the minority member received $1,142,000. In conjunction with this cash distribution, on February 7, 2005, Northern Growers paid a distribution of $3,778,051 to its members of record as of December 31, 2004.
During July 2005, Northern Lights approved an $8,000,000 distribution, which it paid on July 28, 2005. Northern Growers received $6,172,800 and the minority member received $1,827,200. In conjunction with this cash distribution, on July 29, 2005, Northern Growers paid a distribution of $5,972,839 to its members of record as of April 30, 2005.
During October 2005, Northern Lights approved a $3,200,000 distribution, which it paid on October 28, 2005. Northern Growers received $2,469,120 and the minority member received $730,880. In conjunction with this cash distribution, on October 31, 2005 Northern Growers paid a distribution of $2,469,064 to its members of record as of August 31, 2005.
During January 2006, Northern Lights approved a $4,162,763 distribution, which it paid on January 24, 2006. Northern Growers received $3,211,988 and the minority member received $950,775. In conjunction with this cash distribution, on January 30, 2006, Northern Growers paid a distribution of $3,212,093 to its members of record as of December 31, 2005. The above distributions are recorded as a liability as of December 31, 2005.
During April 2006, Northern Lights approved a $3,675,448 distribution, which it paid on May 1, 2006. Northern Growers received $2,835,976 and the minority member received $839,472. In conjunction with this cash distribution, on May 8, 2006, Northern Growers paid a distribution of $2,760,998 to its members of record as of March 31, 2006.
NORTHERN GROWERS, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During July 2006, Northern Lights approved a $10,899,284 distribution, which it paid on August 2, 2006. Northern Growers received $8,409,888 and the minority member received $2,489,396. In conjunction with this cash distribution, on August 7, 2006, Northern Growers paid a distribution of $8,359,696 to its members of record as of June 30, 2006.
During October 2006, Northern Lights approved an $11,000,000 distribution, which it paid on October 30, 2006. Northern Growers received $8,487,600 and the minority member received $2,512,400. In conjunction with this cash distribution, on November 6, 2006, Northern Growers paid a distribution of $8,337,419 to its members of record as of September 30, 2006.
During January 2007, Northern Lights approved an $11,000,000 distribution, which it paid on January 26, 2007. Northern Growers received $8,487,600 and the minority member received $2,512,400. In conjunction with this cash distribution, on January 29, 2007, Northern Growers retained $1,699,904 by a super majority vote of the Board of Managers, and paid a distribution of $6,787,696 to its members of record as of December 31, 2006. The above distributions are recorded as a liability as of December 31, 2006.
NOTE 8 - CAPITAL UNITS
On June 20, 2005, Northern Growers approved a four-for-one (4-for-1) capital unit split of its Class A capital units, effective for September 1, 2005. Under the terms of the Class A capital units’ split, members of record as of September 1, 2005 received four capital units for each one capital unit held in Northern Growers.
On June 2, 2006, Northern Growers approved a two-for-one (2-for-1) capital unit split of its Class A capital units, effective for July 1, 2006. Under the terms of the Class A capital units’ split, members of record as of July 1, 2006 received two capital units for each one capital unit held in Northern Growers.
Prior period financial statements have been restated to reflect the capital unit splits stated above.
NOTE 9 - INCOME TAXES
As of December 31, 2006 and 2005, the Company’s book basis of assets exceeded their tax basis by approximately $30,100,000 and $22,900,000, respectively. There were no significant differences between the book basis and tax basis of liabilities as of December 31, 2006 or 2005.
NOTE 10 - 401(K) PLAN
On February 1, 2003, the Company set up a 401(k) plan for substantially all employees who work more than 1,000 hours per year. Employees can make voluntary contributions up to federally designated limits. The Company matches employee voluntary contributions at a 50% level up to an effective maximum of 2% of gross employee pay. Eligible employees are always fully vested in their account balances resulting from employee voluntary contributions. The Company 401(k) expense for the years ended December 31, 2006, 2005 and 2004 was $33,646, $25,192 and $21,762, respectively.
NORTHERN GROWERS, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Summary quarterly results are as follows:
The above quarterly financial data is unaudited, but in teh opinion of management, all adjustments necessary for a fair presentation of the selected data for these interim periods presented have been included. Basic earnings or loss per unit are presented on the 50,628,000 unites currently issued and outstanding.
Note 12 - COST OF REVENUES - SETTLEMENT CREDIT
In November 2004, the Company recieved a credit from Big Stone Plant for approximately $1,450,000. Big Stone Plant is located adjacent to the plant and supplies stream to the plant for production process. This credit was issued after an informal dispute between the Company and Big Stone Plant regarding the report volume of steam supplied from Big Stone Plant to the plant. In March 2003, management at the plant questioned Big Stone Plant about the reported volume of steam supplied to the plant from Big Stone Plant. Management believed the reported volume of steam supplied to the plant was excessive, compared to the volume of steam required for the
NORTHERN GROWERS, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
production process. After initial testing and analysis, Big Stone Plant concluded the reported volume of steam was accurate. After further testing and analysis in 2004, however, Big Stone Plant determined that the reported volume of steam was erroncous due to an error caused by the miscalibration of a metering instrument. As a result of this error, Big Stone Plant overcharged the Company for the use of steam in 2003 and 2004. In November 2004, in an effort to resolve the dispute, Big Stone Plant notifed the Company that a settlement credit would be issued, which the Company agreed to accept. At December 31, 2005, there was no balance outstanding as the credit had been depleted in full.