Natural Resources Canada Office of Energy Efficiency 580 Booth Street Ottawa, Ontario K1A 0E4

Transcription

1 PUBLIC POLICIES FOR FUEL ETHANOL PHASE 1 Prepared For: Natural Resources Canada Office of Energy Efficiency 580 Booth Street Ottawa, Ontario K1A 0E4 Prepared By Consultants Inc Summit Crescent Delta, BC Canada, V4E 2Z2 And Meyers Norris Penny LLP 366-3rd Ave. S. Saskatoon, SK S7K 1M5 Date: November 22, 2004

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3 EXECUTIVE SUMMARY The transportation sector represents the single largest source of Canada's greenhouse gas (GHG) emissions, accounting for about 27% of the total. Emissions from transportation are growing faster than the national average and are forecast to exceed the 1990 levels by over 25% in 2010 and 40% by Two transportation fuels that are manufactured from biomass feedstocks have been gaining momentum as suitable fuels for use in gasoline and diesel engines, either as neat fuels or in various blends. These fuels are ethanol, manufactured from grains and lignocellulosic feedstocks, and bio-diesel (methyl esters) manufactured from virgin vegetable oils, re-cycled oils, and animal fat. The 2003 Climate Change Plan for Canada included $154 million to be invested in measures to support Canada's efforts to reduce GHG emissions from transportation. The funds will support the industry to increase the supply of renewable alternative fuels, such as ethanol and bio-diesel, and the commercial transportation sector to make greater use of these fuels. The Federal Government included a production goal of 35% of Canadian gasoline to be blended with 10% ethanol by 2010 in its Climate Change Action plan. In 2010, this will likely require 1.5 billion litres of ethanol. The government has also established a $100 million Ethanol Expansion Program to assist with the construction of new ethanol plants in Canada. The funding under the Ethanol Expansion Program is part of a larger bio-fuels strategy that also includes the extension of the National Biomass Ethanol Program, research and development under the biotechnology component of the Technology and Innovation Strategy and an investment in bio-diesel. In addition to encouraging increased production, the Government of Canada is also promoting greater use of ethanol. In partnership with several gasoline retailers, the Government of Canada is launching a consumer awareness campaign that will promote the benefits of ethanol-blended gasoline to Canadian drivers. In Canada the fuel ethanol production capacity of the five production facilities is about 190 million litres per year. Ethanol demand is about 280 million litres per year with imports from the United States making up the production shortfall. Ethanol use as a blending component of gasoline in Canada began in the Province of Manitoba in 1981 with a 10% ethanol blend being marketed. In 1987, ethanol blended gasolines with 5% ethanol were offered in the four Western Canadian provinces with about 250 service stations offering the fuel. In 1992, ethanol blends were introduced into Ontario and in 1995 in Quebec. Today there are approximately 1400 services stations in six Provinces offering 5% or 10% blends of ethanol and gasoline. Fuel ethanol as a gasoline blending component has been used sporadically in the United States from the 1920 s. The modern era began in 1979 in response to the second oil embargo of that decade. The fuel ethanol market is dominated by the use of the product in low level blends (less than 10%) but there is growing availability and use of E85, a high-level ethanol blend. The production of fuel ethanol in the United States has grown to over 12 billion litres per year. The more or less continuous rise in the annual ethanol production is somewhat deceiving in that the industry went through many changes, particularly in the 1980 s. By the beginning of 1985 there were 163 fuel ethanol plants operating in the United States. Many of these were small plants producing 5 to 20 million litres per year. By the end of 1985, 85 of these plants had ceased operations and by 1990, only 21 plants were still in operation and even some of these survivors have subsequently been closed. i

4 The second phase of the industry started in the late 1980 s and lasted through the early to mid 1990 s. These plants were generally better designed by process engineering firms that had ethanol experience; the capital costs were somewhat lower but still high by modern standards. Ethanol yields were improved; operating conditions were better with less energy being consumed. These plants generally started up in a reasonable period of time and were usually able to operate at 10 to 20% above their design capacity. The third phase of the development of the industry began in the early to mid 1990 s and can be characterized by the establishment of a competitive market for ethanol plant design and build contractors. For the first time the process developers were also providing all of the engineering services required and were either building the facility or supervising the construction. In some cases, the companies also took a position in the operation of the facility after it was completed. Capital costs were reduced even further, operating performance improved, ethanol yields were higher, energy consumption lower and plants were able to routinely operated at 20 to 25% above design capacity within weeks of starting up. These efficient low cost plants set the stage for the rapid development of the ethanol industry. Brazil has been the world s largest producer and consumer of fuel ethanol although the US may surpass them in All Brazilian ethanol is produced either directly from sugar cane or indirectly from sugar cane molasses and the country uses swing production of ethanol in part to manage its sugar production and sugar exports. Brazil is the world s second largest sugar producer after India and the world s largest sugar exporter. Ethanol is produced in more than 300 facilities in Brazil, 200 of them tied to sugar mills. This would suggest that the average output per facility is about 42 million litres per year. Ethanol is produced both from sugar molasses and from sugar cane. Production peaked at about 15.4 billion litres in 97/98 and has declined until 00/01 when only 10.6 billion litres were produced. Production increased to 12.5 billion litres in 02/03 and again to 14.6 billion litres in 2003/04. Fuel ethanol is also produced and used in Sweden, France and Spain today but the EU has introduced targets for biofuel consumption that could see a very dramatic increase in ethanol use over the next ten years. There have been plans announced to produce ethanol in Germany and there is interest in ethanol production in the UK, the Netherlands, Poland and other regions as well. Ethanol production in the United States and Canada has been mostly profitable but the production margins are very volatile. The revenue streams from the plants and the costs of the major inputs are all based on commodities, which results in the potential for very volatile earnings. A number of successful US ethanol plants have been profiled and analyzed in an effort to determine their success factors. The successful plants had these common characteristics: Low capital costs, Significant amount of equity investment. Proven expertise with design/build engineers and contractors, Efficient operations capable of operating at 20% above the nameplate capacity, The use of professional management to supplement local skills, Co-operative marketing of ethanol and DDG, Continuous improvement programs, in some cases driven by co-operative R&D programs. ii

5 The dominant feedstock for fuel ethanol production in North America is corn but almost any material containing cellulose, starch or sugar can be used to produce ethanol with existing technology. Four feedstocks are produced in large enough quantities in Canada to be considered for commercial ethanol production with commercial technology, corn, wheat, barley, and in some regions potatoes. There are other starch and sugar containing crops such as rye, triticale, oats, and sugar beets that can theoretically be converted to ethanol but the production volumes of these crops in Canada is generally low and not sufficient to use as a base on which to build an ethanol industry on. Technology is being developed that will be able to produce ethanol from cellulosic materials. In light of this, the potential ethanol feedstocks of corn stover, wheat and barley straw, hay and wood residues are identified as well. The potential starch ethanol feedstocks are summarized and compared to the potential demand for ethanol on a regional basis. The potential regional demand for ethanol is calculated from the gasoline demand and the assumption that 35% of the gasoline contains 10% ethanol. The results are shown in the following table. Even with the relatively conservative assumptions for wheat and barley export diversions there is 50% more feedstock available that is required to meet the target of 1.5 billion litres. As an ethanol market develops, more feedstock may be diverted from exports, particularly if there is some variety switching that occurs resulting in the capacity to produce even more ethanol. In regions that are heavily dependent on a single crop, such as potatoes in the Maritimes an increased demand for cereal grains may provide more opportunities for crop rotation and increase the diversity of agriculture. Note that in the following table the supply and potential demand are rarely in balance within single provinces. This highlights the important role that inter-provincial trade will play in achieving the targeted volumes. Table ES-1 Comparison of Feedstock Supply and Ethanol Demand Ethanol Demand Corn Wheat Barley Potatoes Total Supply million L million L million L million L million L million L British Columbia Alberta Saskatchewan Manitoba Ontario Quebec New Brunswick Nova Scotia Prince Edward Island Newfoundland Yukon North-West Territories Nunavut Canada 1, , ,025.5 iii

6 The potential availability of lignocellulosic feedstocks for ethanol production is summarized in the following table. The raw data on lignocellulosic feedstocks has been filtered so that only those provinces with more than 500,000 tonnes of a particular feedstock have been carried through to the summary table. Volumes of feedstock less than this are not likely to be economic. The low end of the range of straw availability is used for the summary. Table ES-2 Comparison of Lignocellulosic Feedstock Supply and Ethanol Demand Ethanol Demand Corn Stover Straw Wood Residues Forest Residues Total Supply million L million L million L million L million L million L British Columbia ,024 2,704 Alberta ,010 Saskatchewan Manitoba Ontario ,312 1,952 Quebec ,789 2,713 New Brunswick Nova Scotia Prince Edward Island Newfoundland Yukon North-West 0 Territories Nunavut Canada 1,473 1,024 1,130 1,520 6,340 11,487 An ethanol financial model has been prepared for this study. The model includes income statements, balance sheets, statements of cash flow and all necessary supporting schedules. The model is flexible in that different corporate structures can be modelled, different debt structures are feasible and it is adaptable to the tax structures in all of the provinces. The following tornado diagram highlights the sensitivity of ethanol operations to feedstock costs and selling prices. In the diagram, an Ontario ethanol plant processing corn is used as the base case. The feedstock price is varied from a low of $110/tonne to a high of $200/tonne, with the base of $147/tonne. The ethanol selling price is moved from the base of 54.2 cpl to a low of 45 cpl and a high of 65 cpl. The plant size is changed from a low of 80 million litres per year to a high of 200 million litres per year and finally the impact of capital costs that range from a low of $50 million to a high of $90 million with the base case being $59.7 million. The base case produces a Net Income of $10,050,031 in the second year of operation (the first at full capacity). Note that the upper and lower estimates are not symmetrical for several of the variables. This figure has been prepared by altering a single variable. In reality two of the variables, feedstock cost and selling price probably have secondary offsetting variables that are important. The DDG selling prices are correlated with feedstock costs but not perfectly. Higher feedstock costs would be partially offset by higher DDG selling prices. Similarly, the natural gas costs and the ethanol selling prices have some correlation, which has not been considered in this single variable analysis. iv

7 Figure ES-1 Sensitivity to Key Variables Feedstock Cost Selling Price Plant Size "+$53 to -$37"/t "+/-" 10cpl "+80 to-40" million L Capital Cost "+$30 to- $10" million -5,000, ,000,000 10,000,000 15,000,000 20,000,000 Net Income Low Base High The level of price support that is required to make ethanol attractive in the market place is strongly influenced by the price of crude oil. With the base case built on an oil price of $28 US/bbl and a combined incentive level of 24.2 cpl, and considering that production costs will increase as the oil price rises, then the cross over point for not requiring an incentive and producing the same 20% IRR as the base case is approximately $64 US/bbl. The intermediate points can be estimated from the following figure. Note that the oil price as it is used here is the long term average price and not a temporary peak price. The oil industry is generally using a crude oil forecast price of $20 to $25/bbl for their capital decision making process. Oil prices need to have sustained periods of high prices before the long term forecasts can be increased. Investments in either new oil production fields or bioenergy facilities will have operating lives of 20 or more years and a long term view must be taken when deciding to make investments. v

8 Figure ES-2 Oil Price Sensitivity Combined Incentive, cpl Crude Oil, US$/bbl A common set of assumptions is required to develop the supply costs for ethanol. It will be assumed that grain ethanol plants of 120 million litres per year of capacity are employed. The feedstock costs will be the ten year average prices. Natural cost gas costs will be based on a five year average price. The cellulose ethanol plants will be 170 million litres in size. Since we are interested in the supply cost, a set of assumptions are required with respect to the financial structure. The plants will be financed with 50% equity and 50% debt with an interest rate of 6%. The ethanol selling price will be varied to provide an after tax rate of return on the shareholders initial investment of 10%. This rate of return is not likely high enough to attract the required equity and debt. The tax incentives provided by the Federal Government and some of the provinces are not a factor in the calculations since we are interested in the cost of ethanol production and not necessarily the ethanol selling prices. Using the financial models developed for the project and combining that information with the feedstock volumes identified earlier allows for the development of an ethanol supply curve. This information is shown graphically in the following figure. vi

9 Figure ES-3 Ethanol Supply Curve Ethanol Supply Cost, cpl ,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Ethanol Volume, million litres There are basically three portions to this curve. The initial low cost portion is ethanol produced from wheat in Western Canada, the middle portion is ethanol produced from barley or corn and the final portion is ethanol produced from cellulose. The cellulose portion costs can be expected to decline over time as more experience is gained with technology. The peak costs shown above represent the capital costs of the first plant and estimates of the operating costs obtained from the literature. The projected decline in costs as the volume increase only reflects the expected reductions in capital costs for cellulose plants as experience is gained from building and operating the plants. There may also be improvements in operating costs that are not considered here. The quality of the data used for estimating the cellulose ethanol costs is not as good as the quality of the data used to estimate the ethanol from starch costs. Costs could be higher or lower than shown here. The target of 1.5 billion litres requires a long term average supply price of about 46 cents per litre. Due to the regional nature of the demand and the supply, a higher price of about 50 cents per litre would be required to account for transportation to market and regional production. It must also be noted that projects with a 10% after tax return in investors capital would likely have a difficult time raising debt finance. Due to the inherent volatility of commodity prices, investors and lenders are likely to require higher returns. The issue of creating markets for energy technologies has been the subject of considerable focus at the International Energy Agency over the past five years. In 2003, the IEA published a report Creating Markets for Energy Technologies that considered the process of market development. The technological and market developments required to transform the energy system will be conceived and implemented largely in the private sector. But success in this endeavour will not be determined exclusively by market forces. Governments that value the wider benefits of cleaner and more efficient energy technologies will work in partnership with market actors to ensure there are real opportunities for vii

10 technologies to make the difficult transition from laboratory to market. This book is about the design and implementation of policies and programs for that purpose. Governments are motivated to assist not only because they have a responsibility for the pursuit of long-term societal goals and stewardship of the planet, but also because they understand that their policy settings help to determine whether markets develop and operate efficiently. Policymakers must therefore understand the markets concerned and they must have a highly developed capacity to mount effective programs. In both cases, experience is the best teacher. The IEA reviewed 22 case studies of what they determined where successful energy market developments in IEA countries over the past twenty years. In studying the cases, the IEA considered three perspectives on deployment policymaking. These three perspectives have developed over the last quarter of a century. The Research, Development and Deployment Perspective, which focuses on the innovation process, industry strategies and the learning that is associated with new technologies; The Market Barriers Perspective, which characterizes the adoption of a new technology as a market process, focuses on decisions made by investors and consumers, and applies the analytical tools of the economist; The Market Transformation Perspective, which considers the distribution chain from producer to user, focuses on the role of the actors in this chain in developing markets for new energy technologies, and applies the tools of the management sciences. The IEA concluded that the adoption of clean energy technologies would not be likely to succeed unless all three perspective were considered and that it is necessary to: Invest in niche markets and learning in order to improve technology cost and performance; Remove or reduce barriers to market development that are based on instances of market failure; and Use market transformation techniques that address stakeholders' concerns in adopting new technologies and help to overcome market inertia that can unduly prolong the use of less effective technologies. The ethanol industry has been analyzed from all three perspectives. In the case of the Market Barriers perspective it has been determined that there are four primary and two secondary barriers to the development of an ethanol market in Canada. The primary market barriers are: 1. High ethanol price. In some regions of the country, this has been offset by a combination of federal and provincial tax incentives. Some of these incentives are creating a secondary problem with respect to inter-provincial trade in ethanol. 2. Inefficient market organization. The major petroleum companies are not the end users of ethanol blended gasoline but they do provide the distribution system by which ethanol reaches the end consumer. Some oil companies have made commitments to ethanol use but others are resisting. 3. Finance risk. Raising the debt portion of the required capital can be difficult. There has been some significant consolidation in the finance sector in viii

11 Canada over the past decade and there are now fewer institutions that are willing to invest in new agricultural enterprises. Unlike the United States, there are no lenders in Canada who focus on the needs of large agricultural processors. 4. Business risk. Successful new businesses must raise equity and debt financing, have plants designed and built, operate the new facilities and adapt to changing market conditions. This is difficult to do the first time but becomes easier with each new successful operation as can be seen in the US. The secondary barriers are: 1. Price distortion. The marketplace does not place a monetary value on environmental impacts. Fuels that reduce greenhouse gases or exhaust emissions sell for the same price as fuels that don t impact emissions. In most cases, this price distortion is offset by the tax incentives offered by the federal government and some of the provinces. 2. Excessive/inefficient regulation. Ethanol has some unique physical properties when blended with gasoline. The regulations for ethanol gasoline blends are mostly the same as the gasoline regulations without fully considering the impact of the different properties. In many cases, this increases the costs associated with blending and handling ethanol blends. When ethanol market development is considered from the perspective of R&D + D there are several issues that were identified. 1. There has been considerable learning that has occurred in the United States over the past twenty years that has driven down the cost of ethanol plant construction and ethanol production costs. The capital cost aspect does not appear to have been transferred to Canada. Many of the ethanol plants that have been built or are proposed to be built in Canada suffer from high capital costs. 2. There may be research and development opportunities for the development of wheat varieties that could be better suited to ethanol production. These varieties would have lower protein contents (and higher starch contents) and provide higher yields for the producers. Similar development work using corn has occurred in the United States over the past five years and ethanol plants are now using the new varieties and experiencing enhanced ethanol yields. 3. Canada is clearly a leader in the development of technology to convert cellulosic materials to ethanol. There has been significant public and private sector money invested in the R&D. The time is coming for the deployment of the technology but there are no public programs designed to assist with the deployment of the technology. Without public support for technology deployment the public investment in R&D risks becoming stranded with no potential for payback. The Market Transformation approach to market development would appear to offer little opportunity for market development at this time. The combination of the market size and the required production volumes to reach the economies of scale provides little potential for procurement actions and strategic niche management. In order for the ethanol industry to develop, there have to be solutions to address each of the primary market barriers. There are a variety of solutions to the issues that have been ix

12 discussed along with the advantages and disadvantages of each solution. The leading candidates are summarized here. The ethanol cost derived from the supply curve at the 1.5 billion litre per year production level is 46.7 cpl. This cost provided a 10% return on a shareholders initial investment but this rate of return is too low to attract capital considering the volatility inherent in the business and early stage (and hence high risk) of the industry. The marginal ethanol producer at the 1.5 billion litre level will require a selling price of 54.2 cpl to achieve a more realistic leveraged IRR of 20%. Using the five year average gasoline price this requires support of 24.2 cpl. With respect to the quantification of the impact of direct ethanol incentives, there is often some confusion about how these should be calculated. It is not correct to multiple the ethanol volume by the level of incentive, this overestimates the cost. The cost of the incentive arises because there is less gasoline tax collected. A litre of ethanol contains about one third less energy than a litre of gasoline so it only replaces 0.65 to 0.75 litres of gasoline, depending on the degree to which the combustion efficiency increases. The forgone tax revenue from the target of 1.47 billion litres of ethanol to the federal government is therefore about $100 million per year rather than $147 million per year. There are similar savings with the provincial incentives. Foe the 15 cpl typical provincial incentive, there is $150 million per year of lost provincial revenue. This lost fuel tax revenue is partially offset by increased economic activity and the personal and corporate taxes generated by the ethanol production. In five provinces representing approximately 75% of the gasoline demand in the country the existing programs of commodity tax incentives for ethanol production and use are sufficient to address the price barrier. There are some problems such as inter-provincial trade in ethanol and restrictions on the incentives that remains with the existing system and these could prevent the federal target of 1.5 billion litres from being achieved. It may be possible to reach the 2010 target just with the provinces that have implemented or are considering mandates but this will not result in a national market for ethanol and there exists the problem of the imbalance between the location of the feedstock and the location of the demand. Some of the disadvantages of the existing incentives are that they are not all targeted to domestic production, some introduce inter-provincial trade barriers, some provinces do not provide incentives and none of them offer any flexibility in periods of high feedstock prices or high ethanol selling prices. More cost effective but complicated financial packages could be developed that would address the disadvantages to the current system. These systems would target domestic production and make the incentive subject to gasoline and feedstock prices. A well designed system could also help to address the commodity volatility concerns of lenders. The options for addressing the market access barrier are limited. Some form of market intervention has been used in the United States and Brazil to develop their markets to the size they are today. Of the three options identified only market mandates and financial incentives have been used successfully for ethanol markets. Three provinces are moving towards ethanol mandates and those three provinces could result in a market for 1.5 billion litres by It will not be a national market and there are real risks to increased interprovincial trade barriers. Perhaps a larger issue with respect to the price and market barriers is the lack of a national approach to ethanol market development. A number of the provinces have attached conditions to their financial assistance for the industry. While these conditions may provide some degree of protection for the industry during its start-up in a specific province in the longer term the conditions themselves will become barriers to the development of an efficient industry. x

13 There is a need for a more national approach to addressing the price and market barriers. A national approach can still have some flexibility for different approaches (mandates and voluntary markets, tax incentives and producer payments) in different regions but it would see more co-operation and joint efforts between the provinces and the federal government and between the provinces themselves. In the long term the cost to governments and consumers should be minimized with this national approach rather than a series of provincial efforts as the industry will be able to develop cost effective solutions rather than solutions developed with constraints imposed by trade barriers and government regulations. Even in those provinces that have a market mandate, ethanol proponents are facing a finance barrier. Until recently, large companies have shown little interest in becoming ethanol producers in Canada. Large companies have the capability of building ethanol production facilities without facing the finance barriers that face new organizations or facilities that are financed on a project basis. It is not yet clear that all of the large companies that have shown some interest will actually build plants. Most of the interest in ethanol production has come from smaller organizations or those that wish to finance the facilities on a project finance basis. These are also the types of organizations that are driving the expansion of the US ethanol industry. The smaller organizations face significant barriers in raising the debt portion of a project s capital. The finance barriers are largely related to uncertainty. The fact that there are few successful Canadian operations, the finance community has little experience with projects of this type, the commodity nature of the business and the lack of experience that the proponents have managing ethanol projects all lead to the creation of a finance barrier. Provided that the first new ethanol projects are well done and lead to financially successful operations then over time this barrier should be reduced as the finance sector gains knowledge of the sector and the level of uncertainty is reduced. In addition to capital programs such as the Ethanol Expansion Program there are a number of actions that governments can take to lower or remove the finance barriers. These could be considered if the finance barrier is not eliminated over the next few years. These include the following: Loan guarantees for projects that involve large amounts of technical risk. Commodity price support programs that will reduce the volatility and result in more stable margins. These could be integrated with a producer payment program to address the price barrier and over the long term should offer a lower cost to government. Contractual undertakings that provide commercial certainty to government policies. Industry awareness programs to assist with raising the level of understanding that lenders have with the industry. These programs can and should be funded by their users. There are designed to address the financing barrier and not the price barrier. The finance barrier is a normal market barrier and it should disappear over time if the industry has some success. It is extremely important for the next ethanol plants that are built to be successful. Success will require multiple plants being built with some evidence that lessons learned are incorporated in successive plants. Plant operators need to be competitive but at the same time co-operative so that advances in processing technology can be quickly adopted by the rest of the industry. If these conditions can be achieved then raising finance for additional plants will become much easier. xi

14 Most of the business risk associated with the producing ethanol can be addressed through existing private sector options. There is a role for governments to ensure that the tax system does not favour fossil fuels over renewable fuels as it does now through the ability to use flow through shares. Expanding the availability of flow through shares to biofuel producers and allowing certain expenditures to be considered as a tax deductible expense rather than a capital asset expenditure would level the playing field and allow biofuel producers to compete with fossil fuel producers for equity on a equal basis. The advantage of flow through shares is relatively small as was shown earlier in the report but this small advantage has assisted in raising several hundred million dollars a year over the past few years. A renewable energy flow through share fund may not be as attractive as the fossil energy funds as it will likely require a longer time horizon before the investor can exit but that possibility can not be definitively determined until the tax regulations are changed. The secondary barriers of price distortion and inefficient regulation are not barriers that absolutely need to be addressed. The price distortion barriers will be the subject of further analysis in Phase 2 of the work and the issue of inefficient regulation would be nice to fix but it is not impeding the development of the industry. There is significant international trade in ethanol. Historically much of this trade has been in industrial grades of ethanol but in recent years there has been some trade in fuel ethanol. The key country in the development of an international market is Brazil. They have been producing more ethanol than they consumed domestically over the past several years and have been looking for additional world markets. Prior to 2004, Brazilian exports had never exceeded one billion litres per year and there was little infrastructure available in Brazil to facilitate large scale exports. In 2004, Brazilian exports have approached two billion litres and there have been investments made in Brazil to facilitate exports of larger volume cargoes. However late in 2004 the price of sugar in the world market has increased and with it the price of Brazilian ethanol. Exports of ethanol have dropped dramatically as a result. The availability of surplus Brazilian ethanol in the future will be a function of supply and demand in Brazil. There are many factors that could influence this situation both economical and political. Sugar cane supply in Brazil continues to expand but the diversion of sugar from world markets to domestic ethanol production will depend on the relative financial returns from the two markets. Sugar reform in the European Union is expected to decrease production there and increase demand and thus price for Brazilian sugar. This could potentially reduce the supply of ethanol available for export. Domestic demand for ethanol would appear to be increasing with the popularity of the new flexible fuel vehicles being sold in Brazil. Some have forecast that domestic demand could increase by 50% through the end of this decade. This increase in demand could be reduced if the government moves to lower the ethanol content of gasoline or if they move to increase the price of hydrous ethanol. Brazilian ethanol has been imported into Canada in There is a small duty applicable but this is much lower than the duty rate that the product would face if it were imported into the US. The attractiveness of Brazilian ethanol in Canada will be a function of the world sugar price and the world oil prices. Ethanol production costs in Brazil benefit from low energy costs, low labour costs, a low exchange rate and a massive amount of government money invested in the sector between 1975 and In spite of these advantages, if world sugar prices returned to the levels of the 1990 s Brazilian ethanol costs in Canada would be between 60 and 65 cpl after duty and transportation costs are included. The other large ethanol producer, the United States, also is involved in international trade in ethanol but at a much smaller scale than Brazil. Their largest trading partner is Canada. Canada imports and exports ethanol with the US. The ethanol production costs in Canada and the US both vary with location. In Western Canada ethanol production costs are lower xii

15 than they are in most of the US and in eastern Canada production costs are slightly higher than they are in the US mid west. Ethanol selling prices in the US are usually lower than what a rack price formula would produce in most areas of Canada and this makes US ethanol imports attractive. The difference results from both differences in the ethanol tax incentives between the two countries and the US industry practice of offering ethanol at a discount to its fair market value in order to encourage production. xiii

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17 TABLE OF CONTENTS EXECUTIVE SUMMARY... I Stage 1 1. INTRODUCTION FUEL ETHANOL INDUSTRY STATUS CANADA UNITED STATES BRAZIL EUROPE Sweden France Spain Germany INDUSTRY FINANCIAL PERFORMANCE UNITED STATES Non-Feedstock Costs Feedstock Costs Ethanol Selling Prices Operating Margins CANADA SUCCESSFUL FUEL ETHANOL OPERATIONS DEFINITION OF SUCCESSFUL Customer Perspective Lenders Perspective Investors Perspective Community Perspective CANADA Pound-Maker Agventures Ltd Commercial Alcohols Inc UNITED STATES Chippewa Valley Ethanol Company Dakota Ethanol Badger State Ethanol Northern Lights Ethanol Summary US Ethanol Plants ETHANOL FEEDSTOCKS CORN Corn Production Corn Prices WHEAT Wheat Production Wheat Grades Wheat Classes xv

18 Wheat Availability for Ethanol Production Wheat Prices BARLEY Barley Production Barley Prices POTATOES Potato Production Potato Prices STARCH ETHANOL FEEDSTOCK SUMMARY CORN STOVER Corn Stover Production Corn Stover Price WHEAT AND BARLEY STRAW Straw Supply Straw Price HAY Hay Production Hay Price WOOD RESIDUES Wood Residue Production Wood Residue Prices LIGNOCELLULOSIC ETHANOL FEEDSTOCK SUMMARY FINANCIAL MODEL INPUT DATA CAPITAL COSTS Starch Ethanol Cellulosic Ethanol OPERATING COSTS STARCH ETHANOL Feedstock Energy Labour Chemicals Maintenance Other Administrative OPERATING COSTS CELLULOSE ETHANOL Feedstock Energy Labour Chemicals Maintenance Other Administrative REVENUES Ethanol Co-Products Distillers Grains Carbon Dioxide Electricity Other Products BUSINESS STRUCTURES AND INCOME TAXES xvi

19 7.1 OVERVIEW BUSINESS STRUCTURES Corporations Public & Canadian Controlled Private Corporations Partnerships & Limited Partnerships Joint Ventures Co-operative Corporations New Generation Co-operatives Limited Liability Corporations Income Trusts Nova Scotia Unlimited Liability Companies INCOME, CAPITAL AND SALES TAXES Federal and Provincial Income Taxes Provincial Manufacturing and Processing Incentives and Sales Taxes British Columbia Alberta Saskatchewan Manitoba Ontario Quebec New Brunswick, Nova Scotia and Newfoundland Prince Edward Island Federal Investment Tax Credits Large Corporations Tax Federal Saskatchewan Manitoba Ontario Quebec New Brunswick Nova Scotia Personal Income Tax Rates SOURCES OF CAPITAL OVERVIEW INSTITUTIONAL LENDERS Senior Debt Financing Line of Credit SUBORDINATED DEBT FINANCING EQUITY FINANCING Venture Capital TAX EFFECTIVE INVESTMENT VEHICLES Flow Through Shares Limited Partnership Units TYPICAL CAPITAL STRUCTURES ETHANOL FINANCIAL MODEL OVERVIEW PROFITABILITY ANALYSIS Corn Ethanol Wheat Ethanol Barley Ethanol Cellulosic Ethanol xvii

20 9.2.5 Other Feedstocks SENSITIVITY ANALYSIS Location Plant Size Capital Costs Ownership Structures, Capital Structures and Income Taxes Selling Prices Sensitivity Summary FUEL ETHANOL SUPPLY COSTS GOVERNMENT TARGETS SUPPLY COSTS Ethanol Supply Curve Stage MARKET DEVELOPMENT APPROACHES TO MARKET DEVELOPMENT RESEARCH AND DEVELOPMENT + DEPLOYMENT Experience Curves Technology Diffusion Ethanol Market Development from a R&D + D Perspective Experience Curves Technology Diffusion MARKET BARRIERS PERSPECTIVE Ethanol Development from a Market Barriers Perspective Normal Market Barriers Market Failure Barriers Summary Market Barriers MARKET TRANSFORMATION Procurement Actions Strategic Niche Management Business Concept Innovation Ethanol Development from a Market Transformation Perspective MARKET DEVELOPMENT SUMMARY IDENTIFICATION AND ASSESSMENT OF POLICY TOOLS MARKET BARRIERS Ethanol Price Direct Financial Incentives Indirect Financial Incentives Capital Investment Programs Emission Taxes Infrastructure Investment Income Tax System Summary of Measures to Address Ethanol Price Market Access Renewable Fuel Mandates Financial Incentives Restructure Markets Summary Market Barriers Finance Risk xviii

21 Loan Guarantees Contractual Undertakings Commodity Price Support Programs Capital Incentives Industry Awareness Programs Summary Finance Barriers Business Risk Project Equity Capital Incentives Summary Business Risk Barriers Price Distortion Emission Taxes Removal of Subsidies Summary Price Distortion Barriers Inefficient Regulation RESEARCH AND DEVELOPMENT + DEPLOYMENT Feedstock Processing Co-products Deployment Programs MARKET TRANSFORMATION SUMMARY OF POLICY TOOLS Stage INTERNATIONAL COMPETITIVENESS INTERNATIONAL ETHANOL PRODUCTION United States Brazil International Ethanol Trade Brazil United States Summary International Trade PRODUCTION COST COMPARISONS Feedstock Costs Starch Feedstocks Sugar Feedstocks Cellulose Feedstocks IMPORT ALTERNATIVES Price Tariffs Canadian Import Tariffs Other Countries Import Tariffs Quality Logistics IMPACTS ON CANADIAN PRODUCERS Regional Impact Feedstock Specific Impact Mitigation Measures OPPORTUNITIES FOR CANADIAN PRODUCERS TRADE AGREEMENTS World Trade Organization xix

22 GATT Article III Agreement on Trade Related Investment Measures Agreement on Subsidies and Countervailing Measures Agreement on Government Procurement North American Free Trade Agreement Trade Observations SUMMARY INTERNATIONAL COMPETITIVENESS REFERENCES LIST OF TABLES TABLE ES-1 COMPARISON OF FEEDSTOCK SUPPLY AND ETHANOL DEMAND... III TABLE ES-2 COMPARISON OF LIGNOCELLULOSIC FEEDSTOCK SUPPLY AND ETHANOL DEMAND...IV TABLE 2-1 ETHANOL PRODUCTION IN CANADA... 5 TABLE 2-2 CLOSED US ETHANOL PLANTS... 9 TABLE 2-3 EXPANDED US ETHANOL PLANTS... 9 TABLE 2-4 NEW US ETHANOL PLANTS TABLE 2-5 US ETHANOL PLANTS UNDER CONSTRUCTION TABLE 2-6 CCC BIOENERGY PROGRAM PAYMENTS TABLE 3-1 NON-FEEDSTOCK PRODUCTION COSTS TABLE 3-2 VARIATION IN CORN PRICE BASIS TABLE 3-3 ANNUAL AVERAGE OPERATING MARGINS TABLE 3-4 COMPARISON OF ANNUAL AVERAGE OPERATING MARGINS TABLE 4-1 KEY OPERATING DATA FOR POUND-MAKER AGVENTURES TABLE 4-2 CVEC KEY FINANCIAL PERFORMANCE INDICATORS TABLE 4-3 CVEC KEY OPERATIONAL PERFORMANCE INDICATORS TABLE 4-4 DAKOTA KEY FINANCIAL PERFORMANCE INDICATORS TABLE 4-5 BADGER STATE ETHANOL KEY FINANCIAL PERFORMANCE INDICATORS40 TABLE 4-6 NORTHERN LIGHTS ETHANOL KEY FINANCIAL PERFORMANCE INDICATORS TABLE 4-7 SUMMARY OF US ETHANOL PLANT EBITDA RESULTS xx

23 TABLE 5-1 CORN PRODUCTION TABLE 5-2 ONTARIO CORN SUPPLY AND DISPOSITION TABLE 5-3 QUEBEC CORN SUPPLY AND DISPOSITION TABLE 5-4 LIVESTOCK DEMAND FOR CORN TABLE 5-5 LIVESTOCK DEMAND FOR SOYBEAN MEAL TABLE 5-6 AVERAGE CORN PRICES 1993 TO TABLE 5-7 WHEAT PRODUCTION TABLE 5-8 WHEAT SUPPLY AND DISPOSITION TABLE 5-9 WHEAT PRODUCTION BY GRADE TABLE 5-10 CANADIAN WHEAT PRODUCTION BY VARIETY TABLE 5-11 YIELD-PRICE SPREADS BETWEEN WESTERN CANADIAN WHEAT CLASSES TABLE 5-12 AVERAGE FEED WHEAT PRICES 1993 TO TABLE 5-13 BARLEY PRODUCTION TABLE 5-14 BARLEY SUPPLY AND DISPOSITION TABLE 5-15 AVERAGE BARLEY PRICES 1993 TO TABLE 5-16 POTATO PRODUCTION TABLE 5-17 PEI POTATO PRODUCTION AND CULLAGE TABLE 5-18 POTATO PRICES TABLE 5-19 COMPARISON OF FEEDSTOCK SUPPLY AND ETHANOL DEMAND TABLE 5-20 STRAW SUMMARY TABLE 5-21 STRAW COST BUILD-UP TABLE 5-22 TAME HAY PRODUCTION TABLE 5-23 HAY CHARACTERISTICS TABLE 5-24 FORAGE EXPORTS TABLE 5-25 WOOD RESIDUE PRODUCTION AND SURPLUSES TABLE 5-26 FOREST BASED BIOMASS RESIDUES xxi

24 TABLE 5-27 COMPARISON OF LIGNOCELLULOSIC FEEDSTOCK SUPPLY AND ETHANOL DEMAND TABLE 6-1 CAPITAL COST ESTIMATES FOR 95 MILLION LITRE/YEAR PLANTS BY PROCESS AREA TABLE 6-2 CAPITAL COSTS OF RECENT US CORN ETHANOL PLANTS TABLE 6-3 EXPECTED CORN ETHANOL PLANT COSTS TABLE 6-4 EXPECTED WHEAT ETHANOL PLANT COSTS TABLE 6-5 CELLULOSIC PLANT FACTORS FOR SUBSEQUENT PLANTS TABLE 6-6 FEEDSTOCK INPUT DATA TABLE 6-7 ENERGY CONSUMPTION RECOMMENDATIONS TABLE 6-8 NATURAL GAS DISTRIBUTION COSTS TABLE 6-9 POWER COSTS TABLE 6-10 DDG ASSUMPTIONS TABLE 6-11 DDG INPUT DATA TABLE 6-12 NET FEEDSTOCK COSTS TABLE 7-1 MANUFACTURING AND PROCESSING INCOME TAX RATES TABLE 7-2 PERSONAL TAX RATES TABLE 8-1 SOURCES OF CAPITAL TABLE 8-2 US ETHANOL PLANT CAPITAL STRUCTURES TABLE 8-3 SUBORDINATED DEBT SCENARIOS TABLE 9-1 PRODUCTION ASSUMPTIONS CORN ETHANOL TABLE 9-2 STATEMENT OF EARNINGS CORN ETHANOL TABLE 9-3 PRODUCTION ASSUMPTIONS WHEAT ETHANOL TABLE 9-4 STATEMENT OF EARNINGS WHEAT ETHANOL TABLE 9-5 PRODUCTION ASSUMPTIONS - BARLEY ETHANOL TABLE 9-6 STATEMENT OF EARNINGS- BARLEY ETHANOL TABLE 9-7 PRODUCTION ASSUMPTIONS- CELLULOSIC ETHANOL xxii

25 TABLE 9-8 STATEMENT OF EARNINGS- CELLULOSIC ETHANOL TABLE 9-9 CORN ETHANOL LOCATION SENSITIVITY TABLE 9-10 WHEAT ETHANOL LOCATION SENSITIVITY TABLE 9-11 IMPACT OF PLANT SIZE TABLE 9-12 IMPACT OF CAPITAL COST TABLE 9-13 SCENARIO 1 FLOW THROUGH OF TAX DEDUCTIONS/LOSSES TO INVESTORS/OWNERS TABLE 9-14 SCENARIO 2 FLOW THROUGH OF TAX DEDUCTIONS/LOSSES AND INVESTMENT TAX CREDITS TO INVESTORS TABLE 9-15 SCENARIO 3 FLOW THROUGH OF TAX DEDUCTIONS/LOSSES TO INVESTORS AND NON-ASSESSMENT OF CAPITAL TAXES TABLE 9-16 SCENARIO 4 FLOW THROUGH OF TAX DEDUCTIONS/LOSSES AND INVESTMENT TAX CREDITS TO INVESTORS AND NON-ASSESSMENT OF CAPITAL TAXES TABLE 10-1 GASOLINE DEMAND AND PROJECTED ETHANOL DEMAND TABLE 10-2 ETHANOL SUPPLY DATA TABLE 11-1 CONSUMER CHARACTERISTICS TABLE 11-2 CANADIAN ETHANOL PROJECT COSTS TABLE 11-3 TYPES OF MARKET BARRIERS TABLE 11-4 SUMMARY OF MARKET BARRIERS BY TECHNOLOGY TABLE 11-5 CLASSIFICATION OF MARKET BARRIERS TABLE 11-6 ETHANOL TAX INCENTIVES IN CANADA TABLE 11-7 REGIONAL NATURE OF IMPORTS AND EXPORTS TABLE 11-8 SUMMARY MARKET BARRIERS - BIOFUELS TABLE 11-9 TYPES OF MARKET ACTORS INVOLVED IN CASE STUDY PROJECTS TABLE 12-1 DIRECT ETHANOL INCENTIVES TABLE 12-2 STATE FUEL TAX EXEMPTIONS TABLE 12-3 STATE SALES TAXES ON MOTOR FUELS TABLE 12-4 ETHANOL PRODUCER INCENTIVES xxiii

26 TABLE BRAZILIAN ETHANOL EXPORTS TABLE 13-2 ETHANOL PRODUCTION COST COMPARISON TABLE 13-3 BRAZILIAN ETHANOL COSTS TABLE 13-4 COMPARISON OF QUALITY STANDARDS LIST OF FIGURES FIGURE ES-1 SENSITIVITY TO KEY VARIABLES...V FIGURE ES-2 OIL PRICE SENSITIVITY...VI FIGURE ES-3 ETHANOL SUPPLY CURVE...VII FIGURE 1-1 ETHANOL PROCESS FLOW SCHEMATIC... 4 FIGURE 2-1 CANADIAN FUEL ETHANOL CONSUMPTION... 6 FIGURE 2-2 US FUEL ETHANOL PRODUCTION... 7 FIGURE 2-3 BRAZILIAN ETHANOL PRODUCTION FIGURE 2-4 ETHANOL USE IN BRAZIL FIGURE 2-5 ETHANOL CONSUMPTION IN FRANCE FIGURE 3-1 CORN PRICE FIGURE 3-2 HISTORICAL DDG PRICING FIGURE 3-3 NET FEEDSTOCK COST FIGURE 3-4 ETHANOL AND GASOLINE SELLING PRICES FIGURE 3-5 HISTORICAL OPERATING MARGIN FIGURE 3-6 RECENT OPERATING MARGINS FIGURE 3-7 COMPARISON OF US AND CANADIAN ETHANOL PRICES FIGURE 3-8 US VS. ONTARIO CORN PRICE FIGURE 3-9 ONTARIO DDG PRICES VS. ILLINOIS DDG FIGURE 3-10 OPERATING MARGINS ONTARIO ETHANOL PLANT FIGURE 5-1 CANADIAN CORN AREA xxiv

27 FIGURE 5-2 ONTARIO CORN YIELD FIGURE 5-3 CORN PRICES FIGURE 5-4 HISTORICAL WHEAT PRODUCTION FIGURE 5-5 WHEAT ACREAGE FIGURE 5-6 HISTORICAL WHEAT EXPORTS FIGURE 5-7 HISTORICAL FEED WHEAT PRICES FIGURE 5-8 CANADIAN FEED WHEAT PRICES VS. US WHEAT AND CORN PRICES FIGURE 5-9 HISTORICAL BARLEY PRODUCTION FIGURE 5-10 HISTORICAL BARLEY EXPORTS FIGURE 5-11 BARLEY ACREAGE FIGURE 5-12 BARLEY PRICES FIGURE 5-13 SOIL CARBON CONTENT VS. CORN STOVER REMOVAL RATES FIGURE 5-14 MANITOBA TAME HAY PRICES FIGURE 6-1 RENEWABLE ENERGY LEARNING CURVES FIGURE 6-2 IMPACT OF PLANT SIZE ON CAPITAL COSTS FIGURE 6-3 NATURAL GAS PRICES FIGURE 6-4 GASOLINE RACK PRICES FIGURE 6-5 US ETHANOL PRICES RELATIVE TO BENCHMARK PRICES FIGURE 6-6 CO-PRODUCT PRODUCTION FIGURE 6-7 US SOYMEAL SUPPLY AND DISPOSITION FIGURE 6-8 DDG EXPORTS FIGURE 6-9 CORN GLUTEN FEED AND MEAL EXPORTS FIGURE 6-10 US EXPORTS TO CANADA FIGURE 6-11 CANADIAN EXPORTS TO THE UNITED STATES FIGURE 6-12 NET CANADIAN DDG EXPORTS FIGURE 6-13 CANADIAN IMPORTS OF US SOYBEAN MEAL xxv

28 FIGURE 9-1 RACK BACK MARGIN TORONTO FIGURE 9-2 CRUDE OIL VS. FEEDSTOCK COSTS FIGURE 9-3 OIL PRICE SENSITIVITY FIGURE 9-4 SENSITIVITY TO KEY VARIABLES FIGURE 10-1 ETHANOL SUPPLY CURVE FIGURE 11-1 OVERALL PERSPECTIVE ON TECHNOLOGY MARKET DEVELOPMENT. 144 FIGURE 11-2 STAGES OF DEVELOPMENT FIGURE 11-3 INFLUENCES ON THE LEARNING PROCESS FROM PUBLIC POLICIES FIGURE 11-4 PHOTOVOLTAIC EXPERIENCE CURVE FIGURE 11-5 DISTRIBUTION OF PROGRESS RATIOS FOR 108 CASE STUDIES IN THE MANUFACTURING SECTOR FIGURE 11-6 ELECTRIC TECHNOLOGIES IN THE EU, FIGURE 11-7 PROJECTION OF BREAK EVEN POINTS FIGURE 11-8 S CURVES FIGURE 11-9 EXPERIENCE CURVES AND NICHE MARKETS FIGURE US ETHANOL EXPERIENCE CURVE FIGURE BRAZILIAN ETHANOL EXPERIENCE CURVE FIGURE BRAZILIAN ETHANOL AND GASOLINE PRICES FIGURE CRUDE OIL PROCESSED AT CANADIAN REFINERIES FIGURE GASOLINE IMPORTS FIGURE 13-1 BRAZILIAN SUGAR MARKETS FIGURE 13-2 BRAZILIAN VEHICLE SALE FORECAST FIGURE 13-3 FORECAST ETHANOL DEMAND IN BRAZIL FIGURE 13-4 WORLD RAW SUGAR PRICE FIGURE 13-5 PROFITABILITY OF SUGAR EXPORTS VS ETHANOL FIGURE 13-6 WORLD SUGAR SUPPLY CURVE FIGURE 13-7 BRAZILIAN CURRENCY EXCHANGE RATES xxvi

29 FIGURE 13-8 WORLD VS. US ETHANOL PRICES FIGURE 13-9 BRAZILIAN ETHANOL TRADE FIGURE BRAZILIAN ETHANOL EXPORT PRICES FIGURE US FUEL ETHANOL EXPORTS FIGURE US FUEL ETHANOL IMPORTS FIGURE DEVIATION FROM US ETHANOL FAIR VALUE FIGURE BRAZILIAN ETHANOL PRICES xxvii

30 xxviii

31 1. INTRODUCTION The transportation sector represents the single largest source of Canada's greenhouse gas (GHG) emissions, accounting for about 27% of the total. Emissions from transportation are growing faster than the national average and are forecast to exceed the 1990 levels by over 25% in 2010 and 40% by Two transportation fuels that are manufactured from biomass feedstocks have been gaining momentum as suitable fuels for use in gasoline and diesel engines, either as neat fuels or in various blends. These fuels are ethanol, manufactured from grains and lignocellulosic feedstocks, and bio-diesel (methyl esters) manufactured from virgin vegetable oils, re-cycled oils, and animal fat. The 2003 Climate Change Plan for Canada included $154 million to be invested in measures to support Canada's efforts to reduce GHG emissions from transportation. The funds will support the industry to increase the supply of renewable alternative fuels, such as ethanol and bio-diesel, and the commercial transportation sector to make greater use of these fuels. The Federal Government included a production goal of 35% of Canadian gasoline to be blended with 10% ethanol by 2010 in its Climate Change Action plan. In 2010, this will likely require 1.5 billion litres of ethanol. They have also established a $100 million Ethanol Expansion Program to assist with the construction of new ethanol plants in Canada. The funding under the Ethanol Expansion Program is part of a larger bio-fuels strategy that also includes the extension of the National Biomass Ethanol Program, research and development under the biotechnology component of the Technology and Innovation Strategy and an investment in bio-diesel. In addition to encouraging increased production, the Government of Canada is also promoting greater use of ethanol. In partnership with several gasoline retailers, the Government of Canada is launching a consumer awareness campaign that will promote the benefits of ethanol-blended gasoline to Canadian drivers. There are currently more than 1,000 retail locations selling ethanol-blended gasoline in Canada. There has been little economic and financial analysis of these fuels within a Canadian context. The few published and unpublished studies carried-out so far for the public sectors have dealt mostly with potential socio-economic impacts and have attracted little interest from the investment community due to their lack of focus on profitability, both short and long term. More detailed feasibility studies have been performed for individual private sector clients but these have not been widely disseminated. Policy and decision makers, financial institutions, and other economic players need the more detailed, formal analysis framework in order to make investment decisions regarding the development of these fuels. Some essential topics that will be addressed in this work are: The appropriate policy and regulatory environment under which investments will flow into ethanol plants; The likely source of these investments; And the industry structure that will lead to a viable and competitive industry in the longer term. Much work remains to be done in this area to establish a purely Canadian perspective, if Canada is to entertain the notion of building a bio-based economy as part of its future. The development of a biofuel industry will require a great deal of investment on behalf of fuel suppliers, fuel marketers, and many levels of governments. The federal government's role will be to encourage the development of the biofuel industry through the implementation of 1

32 sensible regulatory and policy tools based on sound analytical work. This work will form a foundation for the development of those tools. Objective and Approach The primary objective of this study is to assess the current and future economics of ethanol plants in Canada and to develop estimates of demand, supply, and prices (costs and selling) of this fuel. The results are then used to develop a template-like analytical tool for various models of ownership structure, to help assess the financial performance of various types of fuel ethanol (regional and feedstock specific) plants across Canada. The work was carried out in Phases and stages. This report covers Phase 1, for fuel ethanol. A similar report has been prepared for biodiesel. There were presentations of the findings and draft reports for Stage 1 and 2 made to interested parties from Federal and Provincial governments, academia, and industry. The feedback and suggestions from the meetings have been evaluated and incorporated into the final report where appropriate. Section 12 of the report, Identification and Assessment of Policy Tools has become more focussed and specific in response to the comments received. Phase 1, Stage 1 of the work was designed to assess the status of the ethanol industry in Canada and elsewhere in the world, to identify the feedstock resources available and to determine the economics of using those feedstocks. This information is covered in sections 1 to 10 of this report. Stage 2 of this Phase considered the policy options available to governments to address the specific issues that a developing fuel ethanol industry in Canada faces. Sections 11 and 12 of the report covers Stage 2. Stage 3 of the work investigated international competitiveness aspects of a Canadian ethanol industry. Section 13 of the report deals with the Stage 3 findings. The specific objectives of Phase 1, Stage 1 were to: Review literature on economic and financial performance of ethanol plants. Identify successful plants and reasons for success. Quantify feedstock resources and production costs. Develop a comprehensive financial model. Develop a supply curve. The objectives of Phase 1, Stage 2 were to: Identification of market barriers. Evaluate policy tools including. o Government capital investment o Favourable tax treatment o Infrastructure investment o R&D funding o Renewable content mandates o Emission taxes Examine the potential for regionalization of tools. Quantification of levels of support required. Investigate other approaches to market development. Phase 1, Stage 3 of the work focuses on the international aspects of a developing ethanol industry and considers the threats and opportunities that international trade in biofuels presents. The specific tasks of this stage include: Identification of the level of international trade. Production cost comparison with the potential exporters of fuel ethanol. 2

33 Analysis of the import alternatives that ethanol users in Canada would face. Evaluate the impacts that ethanol imports might face and identify measures that might mitigate the impacts. Evaluate the impact of trade agreements on enabling or disabling Canadian industry competitiveness. Phase 2 of the work will focus on quantifying the effects of biodiesel production and use from a full cost accounting perspective. The work will include: Perform a literature review of existing full cost accounting studies on biofuels. Describe the relative benefits and costs of biofuel production within the context of greenhouse gas emissions, air quality, safety risk, employment and tax benefits and resource use. Identification of case studies that would optimize the benefits from a full cost accounting perspective. Identify the gaps in the existing understanding of full cost accounting and how they might be addressed in the future. Presentation of the preliminary results in a workshop and then incorporation of the workshop findings into a final report. 1.1 FUEL ETHANOL Fuel ethanol is a high octane, oxygenated fuel component manufactured primarily through the fermentation of sugar. The sugar is usually derived from sugar producing crops, the hydrolysis of starch from grains, or through the hydrolysis of lignocellulosic materials such as straw, grass and wood. The later approach is not yet widely practiced but is the focus of much development effort. Ethanol has been used as a motor fuel in North America since the early 1900 s. In 1908, Henry Ford designed his Model T to run on ethanol. Ethanol gasoline blends were used in parts of the United States prior to the Second World War but through the 1950 s and 1960 s there was no ethanol used in gasoline in North America. In 1979, the US Congress established the federal ethanol program to stimulate the rural economy and reduce the dependence on imported oil. The production and use of ethanol as a motor fuel in the United States and in Canada has increased continuously since that time. There are now over ten billion litres of ethanol used in gasoline in the United States and Canada each year. This represents about 1.8% of the gasoline volume or 1.2% of the energy in the gasoline pool. Most of the ethanol is used in low-level blends of 5-10% ethanol in gasoline, only about 0.25% of the ethanol is used as E85. In North America, fuel ethanol is currently produced mostly from starch containing crops such as corn, wheat and milo. Several plants use a waste sugar stream from another industrial plant such as a sulphite pulp mill, a brewery, cheese factories, potato processors and other food processing plants. The dominant feedstock is corn. There are plans to introduce new technology to convert lignocellulosic materials to ethanol. The first of these plants are expected to be built in the next several years. The basic process involves the enzymatic hydrolysis of starch to sugars and the fermentation of the sugars to ethanol via yeast. The weak ethanol solution known as beer is then distilled and dried to produce anhydrous ethanol, which is suitable for blending with gasoline. There are a number of process variations that are employed such as dry or wet milling, batch or continuous fermentation, etc. There are about 80 operating ethanol plants in North America. 3

34 Most new ethanol plants being considered are dry mill ethanol plants. The basic process flow for one of these plants is shown in the following figure. Figure 1-1 Ethanol Process Flow Schematic The major steps in the dry milling process are outlined below. Milling: The wheat first passes through hammer mills, which grind it into a fine powder, called meal. Liquefaction: The meal is then mixed with water and the enzyme alpha-amylase, and passes through cookers, where the starch is liquefied. Heat is applied at this stage to enable liquefaction. Continuous cookers with a high temperature stage ( º C) and a lower temperature holding period (95 º C) are used. Saccharification: The mash from the cookers is cooled and the secondary enzyme (gluco-amylase) is added to convert the liquefied starch to fermentable sugars, a process called saccharification. Fermentation: Yeast is added to the mash to ferment the sugars to ethanol and carbon dioxide. Using a continuous process, the fermenting mash is allowed to flow, or cascade, through several fermenters, until the mash leaving the final tank is fully fermented. Distillation: The fermented mash, now called "beer", contains about 11-15% ethanol by volume as well as the non-fermentable solids from the grain and the yeast cells. The beer mash is pumped to a continuous flow, multi-column distillation system, where the ethanol is separated from the solids and water. The ethanol leaves the top of the final column at about 96% strength, and the residual mash, called stillage, is recovered from the base of the column and transferred to the co-product processing area. Dehydration: The ethanol from the top of the column passes through the dehydration system, where the remaining water is removed. The alcohol product at this stage is called anhydrous (pure) ethanol. Co-product recovery: Evaporators and gas-fired dryers are used to remove the water from the stillage and produce DDGS. 4

35 2. INDUSTRY STATUS A brief overview of the fuel ethanol industry in North America, Brazil and Europe is provided in the following section to provide a basis for the analysis and discussion that follows in the report. 2.1 CANADA Ethanol production statistics are not publicly available in Canada. The production has only increased marginally over the past five years, as the same plants that were operating in 1999 are still the only plants operating in early The existing producers of anhydrous ethanol suitable for blending with gasoline and their production capacities are shown in the following table. The fuel ethanol production capacity of these five facilities is about 190 million litres per year. Table 2-1 Ethanol Production in Canada Company Location Capacity Comments Mohawk Canada Inc. Commercial Alcohols Inc. Pound Maker Agventures Ltd. Commercial Alcohols Inc. Minnedosa, Manitoba 10 million litres/year Started Wheat Feedstock. Tiverton, Ontario 20 million litres/year Started Corn Feedstock. 7 million litres for fuel. Lanigan, 13.5 million litres/year Started Wheat Saskatchewan Feedstock. Integrated Feedlot Chatham, Ontario 150 million litres/year Started Corn Feedstock. 120 million litres for fuel. Permolex Red Deer, Alberta 26 million litres/year Started Wheat Feedstock. Mostly exported. The Ethanol Expansion Program, announced by the Federal Government on August 12, 2003, is intended to expand fuel ethanol production and use in Canada and reduce transportation-related greenhouse gas (GHG) emissions that contribute to climate change. The first round of the program totals $78 million in contributions. The projects that were allocated contributions are as follows. The quantities are annual fuel ethanol production capacity. The Husky Minnedosa agreement has subsequently been cancelled. Commercial Alcohols, Inc., Varennes, PQ (126 million litres); Husky Oil Marketing Company, Minnedosa, MB (80 million litres); Husky Oil Operations Ltd., Lloydminster, SK (130 million litres); NorAmera BioEnergy Corp., Weyburn, SK (25 million litres); Okanagan Biofuels Inc., Kelowna, BC (114 million litres); Seaway Grain Processors, Inc., Cornwall, ON (66 million litres); and Suncor Energy Products Inc., Sarnia, ON (208 million litres). 5

36 Ethanol use as a blending component of gasoline began in the Province of Manitoba in 1981 with a 10% ethanol blend being marketed. In 1987, ethanol blended gasoline with 5% ethanol were offered in the four Western Canadian provinces with about 250 service stations offering the fuel. In 1992, ethanol blends were introduced into Ontario and in 1995 in Quebec. Today there are approximately 1400 services stations in six Provinces offering 5% or 10% blends of ethanol and gasoline. There are no commercial programs for high-level ethanol blends in Canada. There are demonstration programs for E85 for flex fuel vehicles and some fleets have installed private refuelling systems for the fuel. There are no heavy-duty applications for E95 type fuels in Canada. Accurate information on the consumption of ethanol in Canada is not available from public sources. The following figure has been assembled from the plant capacities, the import and export data from the United States (United States International Trade Commission, 2004). The import and export data that is available online from Industry Canada is only available for monetary value and not quantity. It does show similar trends and it indicates that the US is the only significant source of imported ethanol in Canada. In 2003, the ethanol imports have risen sharply and the estimated consumption is over 280 million litres. Figure 2-1 Canadian Fuel Ethanol Consumption 300,000, ,000, ,000,000 Litres 150,000, ,000,000 50,000, Total Use Production 2.2 UNITED STATES Fuel ethanol as a gasoline blending component has been used sporadically in the United States from the 1920 s. The modern era began in 1979 in response to the second oil embargo of that decade. The fuel ethanol market is dominated by the use of the product in low level blends (less than 10%) but there is growing availability and use of E85, a high-level ethanol blend. The production of fuel ethanol in the United States is shown in the following figure. 6

37 Figure 2-2 US Fuel Ethanol Production 12,000 10,000 8,000 6,000 4,000 2, Million Litres Ethanol Production In addition to domestic production the United States imports 600 to 700 million litres per year of denatured ethanol. This import volume has been relatively constant in recent years. The largest importer is Saudi Arabia but that volume is used for industrial applications and not fuel. The next three largest importers are Jamaica, Costa Rica and Brazil. The ethanol from Jamaica and Costa Rica is imported duty free under the Caribbean Basin Initiative but it is not always used for fuel ethanol. The more or less continuous rise in the annual ethanol production is somewhat deceiving in that the industry went through many changes, particularly in the 1980 s. By the beginning of 1985 there were 163 fuel ethanol plants operating in the United States. Many of these were small plants producing 5 to 20 million litres per year. By the end of 1985, 85 of these plants had ceased operations and by 1990, only 21 plants were still in operation and even some of these survivors have subsequently been closed. This first phase of the modern fuel ethanol industry lasted from 1980 to about 1988 and can be characterized by high capital cost plants and relatively inefficient operations. The capital costs of the plants range from a low of about $2.50 (US$)/annual USG to a high of almost $4.00/annual USG. Ethanol yields were about 85% of that being achieved today and energy consumption was high, often double what the best plants are now achieving. Many plants experienced operating problems. Even large plants had a difficult time surviving. In the early 1980 s the US DOE had a loan guarantee program for fuel ethanol plants. Three operations acquired loan guarantees, in one case (Agrifuels), the DOE withheld additional funding after the project costs escalated and the plant was never completed and the DOE sold the facility for scrap several years later. The 25 million gpy Tennol plant in Tennessee cost $90 million (US$) and experienced problems during commissioning and never reached full operation. The lender called the loan and the DOE acquired the facility and sold it for salvage. Parts of this plant were used to build another plant in the early 1990 s. The final DOE loan guarantee went to New Energy of Indiana, which built a 50 million gpy plant for $147 million (US$). That 7

38 plant is still operating although the DOE paid out the guarantee when the plant defaulted on repayments in The DOE is still involved with the operation. There was some oil industry involvement in the plant ownership, Texaco, Chevron and Ashland all had significant equity positions in plants in the 1980 s but these positions were either divested or the plants ceased operation. Many of the plants built in the 1980 s were designed by large engineering firms with little ethanol plant experience. This factor probably accounted for some of the high capital costs, as the plants were still relatively small projects for these large multi-national engineering companies. The second phase of the industry started in the late 1980 s and lasted through the early to mid 1990 s. These plants were generally better designed by process engineering firms that had ethanol experience; the capital costs were somewhat lower but still high by modern standards. Ethanol yields were improved; operating conditions were better with less energy being consumed. These plants generally started up in a reasonable period of time and were usually able to operate at 10 to 20% above their design capacity. The third phase of the development of the industry began in the early to mid 1990 s and can be characterized by the establishment of a competitive market for ethanol plant design and build contractors. For the first time the process developers were also providing all of the engineering services required and were either building the facility or supervising the construction. In some cases, the companies also took a position in the operation of the facility after it was completed. Capital costs were reduced even further, operating performance improved, ethanol yields were higher, energy consumption lower and plants were able to routinely operated at 20 to 25% above design capacity within weeks if starting up. These efficient low cost plants set the stage for the rapid development of the ethanol industry. It is apparent from the previous figure that the past five years have seen rapid growth in the US ethanol industry with production more than doubling from 5.3 billion litres in 1998 to 10.7 billion litres in In 2000, there were 58 ethanol plants in operation in the United States with a production capacity of 7.1 billion litres per year (, 2000). Of those plants, eight have been closed or are no longer producing fuel ethanol. Those plants are identified in the following table. Most of the closed plants were small and several used waste feedstocks to offset the negative impact of their small size. In some cases, the closures were related to loss of this low cost feedstock. In the case of Sunrise Energy and Sutherland Associates, there were technical issues with the plant design and construction that factored into the plant closings. 8

39 Table 2-2 Closed US Ethanol Plants Company Location Feedstock Production Capacity million litres/year Georgia-Pacific Bellingham, WA Sulphite liquor 26 J.R. Simplot Burley, ID Potato waste 8 Jonton Alcohol Edinburg, TX Corn 5 Manildra Ethanol Hamburg, IA Corn/Milo/Wheat starch 26 Minnesota Clean Fuels Dundas, MN Waste sucrose 6 Parallel Products Bartow, FL Beverage waste 15 Sunrise Energy Blairstown, IA Corn 26 Sutherland Associates Sutherland, NE Corn 57 Total 169 Of the plants that have continued in operation, many of them have increased their production capacity. Those 32 plants are shown in the following table. The average increase in production capacity over the four year period was 32%. Table 2-3 Expanded US Ethanol Plants Company Location Original Production Capacity million litres/year New Production Capacity million litres/year A.E. Staley Loudon, TN Abengoa Bioenergy Corp York, NE 265 (Total) 189 Abengoa Bioenergy Corp Colwich, KS 76 Abengoa Bioenergy Corp Portales, NM 57 Agra Resources Coop (EXOL) Albert Lea, MN Agri-Energy Luverne, MN Al-Corn Claremont, MN Archer Daniels Midland Decatur, IL 3,357 (Total) 4,050 (Total) Archer Daniels Midland Peoria, IL Archer Daniels Midland Cedar Rapids, IA Archer Daniels Midland Clinton, IA Archer Daniels Midland Walhalla, ND Archer Daniels Midland Columbus, NE Archer Daniels Midland Marshall, MN Aventine Renewable Energy Aurora, NE Broin Enterprises Scotland, SD Cargill Blair, NE 378 (Total) 314 Cargill Eddyville, IA 132 Central Minnesota Little Falls, MN Chippewa Valley Ethanol Benson, MN Corn Plus Winnebago, MN DENCO, LLC. Morris, MN ESE Alcohol Leoti, KS 4 6 9

40 Ethanol 2000 Bingham Lake, MN Golden Cheese Corona, CA Heartland Corn Products Winthrop, MN Minnesota Energy Buffalo Lake, MN New Energy Corp. South Bend, IN Northeast MO Grain Macon, MO Processors Pro-Corn Preston, MN Reeve Agri-energy Garden City, KS Total 5,392 7,100 There have also been 32 new plants start operation since These plants and their current production capacity are summarized in the following table. Some of these plants have even gone through an expansion since their original construction. The increase in ethanol production over the past five years can be attributed about 35% to plant expansions and 65% to new plant construction. Table 2-4 New US Ethanol Plants Company Location Feedstock Production Capacity million litres/year ACE Ethanol Stanley, WI Corn 57 Adkins Energy, LLC Lena, IL Corn 151 Badger State Ethanol, LLC Monroe, WI Corn 182 Big River Resources West Burlington, IA Corn 151 Central Wisconsin Alcohol Plover, WI Cheese Whey 15 Commonwealth Agri-Energy, LLC Hopkinsville, KY Corn 76 Dakota Ethanol, LLC Wentworth, SD Corn 182 Glacial Lakes Energy, LLC Watertown, SD Corn 182 Golden Triangle Energy, LLC Craig, MO Corn 76 Great Plains Ethanol, LLC Chancellor, SD Corn 159 Husker Ag Plainview, NE Corn 87 Iowa Ethanol Hanlontown, IA Corn 170 James Valley Ethanol Groton, SD Corn 170 KAAPA Ethanol, LLC Minden, NE Corn 151 Land of Lincoln Agricultural Coalition Palestine, IL Corn 151 Little Sioux Corn Processors, LLC Marcus, IA Corn 174 Michigan Ethanol, LLC Caro, MI Corn 170 Midwest Grain Processors Lakota, IA Corn 170 Northern Lights Ethanol, LLC Big Stone City, SD Corn 170 Otter Creek Ethanol, LLC Ashton, IA Corn 170 Platte Valley Fuel Ethanol Central City, NE Corn 151 Quad-County Corn Processors Galva, IA Corn 87 Sioux River Ethanol, LLC Hudson, SD Corn 170 Siouxland Energy & Livestock Coop Sioux Center, IA Corn 68 Tall Corn Ethanol, LLC Coon Rapids, IA Corn

41 Trenton Agri Products, LLC Trenton, NE Corn 114 Tri-State Ethanol Co., LLC Rosholt, SD Corn 68 U.S. Energy Partners, LLC Russell, KS Milo 151 Utica Energy, LLC Oshkosh, WI Corn 91 VeraSun Energy Corporation Aurora, SD Corn 379 Western Plains Energy, LLC Campus, KS Corn 114 Total 4,377 Finally, there are 12 plants under construction and they are identified in the following table. Table 2-5 US Ethanol Plants under Construction Company Location Feedstock Production Capacity million litres/year Amaizing Energy LLC Denison, IA Corn 151 Central Illinois Energy Coop Canton, IL Corn 114 Golden Grain Energy Mason City, IA Corn 151 Granite falls Energy, LLC Granite Falls, MN Corn 151 Mid-Missouri Energy Malta Bend, MO Corn 151 Midwest Renewables Iowa Falls, IA Corn 151 Northstar Ethanol, LLC Lake Crystal, MN Corn 189 Pine Lake Corn Processors, LLC Steamboat Rock, IA Corn 76 United Wisconsin Grain Processors Friesland, WI Corn 151 Voyager Ethanol, LLC Emmetsberg, IA Corn 189 VeraSun Energy Corporation Fort Dodge, IA Corn 415 Western Wisconsin Grain Processors Wheeler, WI Corn 151 Total 2,040 In summary there are 81 operating ethanol plants with a production capacity of 13.0 billion litres and a further 12 plants with a design capacity of 2.0 billion litres under construction. One of the factors that has made plant expansion and development attractive over the past several years has been the USDA Bioenergy Program. This program seeks to expand the use of agricultural commodities by promoting their use in the production of bioenergy. Under the program, the Secretary of Agriculture makes payments through the Commodity Credit Corporation (CCC) to eligible producers to encourage increased purchases of eligible commodities (energy feedstocks) for the purpose of expanding production of bioenergy and supporting new production capacity. Payments to eligible producers are based on the increase in quantity of bioenergy they produce during a fiscal year over the quantity they produced during the preceding fiscal year. The payments are included in a plant s revenue (and are thus taxable), they do not offset capital expenditures The program operates by: Commercial bioenergy producers apply to CCC during a sign-up period to participate in the program for one or multiple Fiscal Years. 11

42 Eligible producers provide CCC with evidence of bioenergy production and purchases and utilization of agricultural commodities for the Fiscal Year quarter and Fiscal Year to date compared to the same time period in the prior Fiscal Year. CCC uses announced conversion factors, based on the eligible commodity used in bioenergy production, to convert the eligible bioenergy production into units of the commodity on which payments are made. Annual funding is paid out on a quarterly Fiscal Year basis. Payments are structured to encourage participation of producers with less than 65 million gallons annual production capacity. Producers with total annual production of: Less than 65 million gallons, are reimbursed 1 feedstock unit for every 2.5 used for increased production; 65 million gallons or more, are reimbursed one feedstock unit for every 3.5 used for increased production. A payment limitation restricts the amount of funds any single producer may obtain annually under the program to five percent of available funding ($7.5 million (US$) for Fiscal Year 2003). A payment factor is applied when requested payments exceed the annual available funds ($150 million (US$) for FY 2003). In FY 2001, 42 ethanol producers signed up for the program and the forecast increase in production was to be million gallons. At the end of the year program payments were made to 27 ethanol producers (and 5 biodiesel producers) on million gallons of increased bioenergy production over FY 2000 levels: $32.7 million (US$) on million gallons of increased ethanol production; $7.9 million on 6.3 million gallons of increased biodiesel production. In FY 2002, 49 ethanol producers signed up for the program and at the end of the year program payments were made to 32 ethanol producers (and 7 biodiesel producers) on million gallons of increased bioenergy production over FY 2001 levels: $66.1 million (US$) on million gallons of increased ethanol production; $12.6 million (US$) on 8.9 million gallons of increased biodiesel production. In FY 2003, 49 ethanol producers signed up for the program and at the end of the year program payments were made to 44 ethanol producers (and 11 biodiesel producers) on million gallons of increased bioenergy production over FY 2002 levels: $130.8 million (US$) on million gallons of increased ethanol production; $19.1 million (US$) on 18.6 million gallons of increased biodiesel production. The payments made under the program for the individual producers are summarized in the following table. The total amount of money received over the three years has been divided by the increase in nameplate capacity. The payments are made based on the actual increase in production achieved and not in the increased capacity but efficient companies will maximized their benefits under the program. There may also be some companies still receiving benefits under the program so the average value of $ 49,000 per million litres of increased annual capacity may be low. With the costs of plant expansion being in the range of $0.25/litre (US$) of capacity and new construction costing $0.35 to 0.45/litre (US$), the program was effectively covering 12% of the capital costs. 12

43 Table 2-6 CCC Bioenergy Program Payments Company 2001 Payment (US$) 2002 Payment (US$) 2003 Payment (US$) $ Received per million litres of increased capacity A.E. Staley Manufacturing Co. 4,619,011 1,332,673 78,312 Abengoa Bioenergy Corp. 396,680 4,492,623 1,099,420 90,738 Ace Ethanol LLC 947,197 4,650,839 98,211 Adkins Energy LLC 964,016 7,500,000 56,053 AGP Corn Processing, Inc. 684,033 Agra Resources Coop. 5,036, ,130 63,853 Agri-Energy, LLC 312, ,270 12,037 37,550 Alchem Ltd. LLLP 70,660 Al-Corn Clean Fuel 162,898 3,137,474 44,600 Archer Daniels Midland Co. 8,375,223 1,038,923 7,500,000 24,407 Aventine Renewable Energy 738,441 38,865 Badger State Ethanol, LLC 7,500,000 41,209 Broin Enterprises. Inc. 108,286 13,536 Central Minnesota Ethanol Coop 90, , ,799 63,375 Chief Ethanol Fuels, Inc. 375,255 1,632, ,821 Chippewa Valley Ethanol Co. 1,921,864 22,090 Corn Plus LP 4,723, ,543 54,591 Dakota Ethanol, LLC 602,482 7,500,000 1,000,349 50,016 DENCO, LLC 231, , ,049 Ese Alcohol, Inc. 30,277 39,372 34,824 Ethanol2000 LLP 1,861,478 1,071, ,724 56,377 Glacial Lakes Energy, LLC 1,068,391 7,500,000 47,079 Golden Triangle Energy, LLC 2,748,374 2,413,609 67,921 Gopher State Ethanol, LLC 1,246,081 42, ,763 Grain Processing Corporation 1,638, ,148 7,500,000 Great Plains Ethanol, LLC 5,584,434 35,122 Heartland Corn Products 380,235 4,030, ,621 68,565 Heartland Grain Fuels, L.P. 1,236,691 1,236,691 21,675 Husker Ag, LLC 3,515,553 40,409 James Valley Ethanol, LLC 4,230,171 24,883 Kuester Ag Processing 9,901 Little Sioux Corn Proc 5,535,734 31,815 Manildra Energy Corporation 915,671 MGP Ingredients 3,038,562 4,853,595 3,181,856 Michigan Ethanol, LLC 7,500,000 44,118 Midwest Grain Processors 7,500,000 44,118 Minnesota Energy 1,582,846 68,819 Nebraska Energy, LLC 945,028 1,164,399 New Energy Corp. 94,522 2,016, ,021 67,077 Northeast Missouri Grain, LLC 2,569, ,084 2,349,244 59,184 Northern Lights Ethanol, LLC 3,224,280 7,500,000 63,084 Pro-Corn LLC 475, ,234 3,982,805 56,444 13

44 Quad County Corn Processors 1,556,605 3,682,557 60,220 Siouxland Energy & Livestock 2,046,885 2,732,608 70,287 Sunrise Energy Cooperative 182,983 Sutherland Ethanol Co. 211,526 Tall Corn Ethanol, LLC 1,199,120 7,500,000 51,171 Tri-State Ethanol, LLC 909, ,325 22,707 U S Energy Partners, LLC 5,490,089 36,358 Utica Energy, LLC 2,396,753 26,338 Williams Ethanol Services, Inc. 93,696 1,801,702 Wyoming Ethanol, LLC 26, ,747 Total 32,700,000 66,100, ,800, BRAZIL Brazil is the world s largest producer and consumer of fuel ethanol although the US may surpass them in All Brazilian ethanol is produced either directly from sugar cane or indirectly from sugar cane molasses and the country uses swing production of ethanol in part to manage its sugar production and sugar exports. Brazil is the world s second largest sugar producer after India and the world s largest sugar exporter. Ethanol is produced in more than 300 facilities in Brazil, 200 of them tied to sugar mills. This would suggest that the average output per facility is about 42 million litres per year. Ethanol is produced both from sugar molasses and from sugar cane. The total annual ethanol production in Brazil is shown in the following figure. Production peaked at about 15.4 billion litres in 97/98 and has declined until 00/01 when only 10.6 billion litres were produced. Production increased to 12.5 billion litres in 02/03 and again to 14.6 billion litres in 2003/04 (Datagro, 2003). Figure 2-3 Brazilian Ethanol Production 18,000,000 Ethanol Production Cubic Metres 16,000,000 14,000,000 12,000,000 10,000,000 8,000,000 6,000,000 4,000,000 2,000, /76 77/78 79/80 81/82 83/84 85/86 87/88 89/90 91/92 93/94 95/96 97/98 99/

45 Ethanol in Brazil is used both as hydrous ethanol, for use in neat ethanol vehicles and as anhydrous fuel ethanol. The amount used directly in alcohol fuelled vehicles is declining and the use as a gasoline blending agent is increasing. This has resulted in a declining demand for ethanol in Brazil. This declining demand for ethanol may be about to change; a new generation of alcohol fuel vehicles employing the same flexible fuel technology that is used in North America is being introduced to the country. The first VW vehicles using this technology were introduced early in 2003 and other manufacturers introduced their vehicles later in 2003 and early in Figure 2-4 Ethanol Use in Brazil 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, Million Litres Anhydrous Ethanol Hydrous Ethanol Total Ethanol 2.4 EUROPE Fuel ethanol is produced and used in Sweden, France and Spain today but the EU has introduced targets for biofuel consumption that could see a very dramatic increase in ethanol use over the next ten years. The ethanol programs in the three countries and the EU biofuels program are briefly summarized in the following sections. There have been plans announced to produce ethanol in Germany and there is interest in ethanol production in the UK, the Netherlands, Poland and other regions as well Sweden There is one wheat to ethanol plant in operation in Sweden. It has an official capacity of 50 million litres per year. The official capacity is related to the tax exemption that they have been granted by the Swedish government. The actual design of the plant would suggest that 60 to 70 million litres should be possible from the plant. The plant has had some operational difficulties since it started up and production has been just under the official capacity. The difficulties have been related to infections in the fermentation area. The plant design used a low temperature cook to reduce energy consumption so the mash is not sterilized prior to fermentation and no anti-biotics are apparently allowed in an ethanol plant in Sweden. 15

46 All of the ethanol is used as a 5% blend in the Stockholm area. All of the five or six gasoline marketers participate in the program. The program is being expanded beyond the Stockholm area with imported ethanol. The tax relief in Sweden is 4.7 SEK/litre (approximately 85 cents per litre of ethanol at current exchange rates). Ethanol is also used in Sweden in about 400 transit buses operated by the City of Stockholm and in a number of E-85 demonstrations around the country. This ethanol is either imported or produced from sulphite pulp mills in Sweden. Sweden has had an active R&D program on cellulosic ethanol for many years. In 2004, a pilot plant was opened to demonstrate acid hydrolysis of wood waste. The plant is operated by Sekab who also produces ethanol from spent sulphite pulping liquors France Ethanol in France is used to produce ETBE for gasoline blending. There are 13 ethanol plants that have a total quota of 102,940 tonnes per year (130 million litre per year) of ethanol (Ademe, 2003). The average plant size is only 10 million litres per year. Actual production is somewhat less as shown in the following figure. The relatively flat ethanol consumption is set against a backdrop of declining gasoline demand and rising diesel demand. The gasoline demand in 2002 was 17.5 billion litres. On an energy basis, the current use of ethanol in France amounts to 0.45% of gasoline demand. Figure 2-5 Ethanol Consumption in France Million Litres The ethanol was produced from sugar beets (70% of production) and from wheat (30% of production). The French tax relief for ethanol in 2003 is 0.38/Litre (61 cents per litre), this is reduced from the previous level of approximately 0.50/litre Spain There are three ethanol plants with a production capacity of 326 million litres per year in Spain. The ethanol is used for the production of ETBE. There are five refineries with ETBE 16

47 units and their total ethanol demand is 210 million litres per year. A tax exemption has been provided for a third ethanol plant with a capacity of 200 million litres per year. It is unclear at this time if the ethanol will be used directly in gasoline (as a 5% ethanol blend) or if ETBE production will be expanded. Barley and wheat are used as the feedstocks in the Spanish ethanol plants, the first plant was designed to ethanol from barley and the second plant from a combination of barley and wheat. In 2000, the tax relief for ethanol in Spain was $0.48 per litre (Taylor Nelson Sofres) Germany There is no fuel ethanol production Germany at this time but there are three plants under construction. These three plants will have a combined production capacity of 540 million litres per year. The feedstocks for the plants would be rye, wheat, sugar beets or combined cereals and beets. Germany has a 0.65 /litre tax incentive (100 cents/litre). There is considerable interest in fuel ethanol in Germany and in 2003 there were 12 fuel ethanol projects that had been announced (F.O. Licht, 2003). With three of these now under construction. 17

48 3. INDUSTRY FINANCIAL PERFORMANCE In the previous section the operating performance of the ethanol industry in Canada, the United States and elsewhere was highlighted. In this section, the industry in the United States and Canada is examined from a financial performance perspective. 3.1 UNITED STATES There is considerable data on ethanol plant operating costs becoming available in the public domain. A report published by the US National Renewable Energy Laboratory (NREL, 2000) compared the costs of ethanol production from different feedstocks. That report was prepared jointly with the US Department of Agriculture and examined the capital and operating costs for starch based and lignocellulosic-based ethanol plants. The USDA (2002) undertook a benchmarking study using data from 1998 plant operations. The data from these two reports is summarized in the following section. Feedstock costs are also a large portion of the cost of producing ethanol and these are highly variable with both time and location. The feedstock costs, co-product credits and typical operating costs are developed for an ethanol plant to determine the monthly costs, which are then compared against the ethanol selling price to determine the ethanol plant margins and how it changes with time Non-Feedstock Costs The non-feedstock production costs from the NREL and USDA reports are shown in the following table. Only the dry mill cost data from the USDA report is considered here. The fuel and electricity prices will fluctuate with time, as these are commodities. The electricity price is still reasonable for 2004 but the natural gas costs have almost doubled. In response to higher energy costs, the plants are reducing their consumption of power and fuels through improved technology. 18

49 Table 3-1 Non-Feedstock Production Costs NREL USDA USDA Average Medium plant Large Plant US$ /USG US$ /USG US$ /USG US$ /USG Cpl Can Electricity Fuel Waste Management Water Enzymes, Yeast, Chemicals Denaturant Maintenance Labour Admin Other Total Total excluding energy Feedstock Costs Feedstock costs are the largest single component of the production costs of ethanol. Most ethanol produced in North America utilizes corn as the feedstock. Corn prices vary with time and location. The historical price of corn in central Illinois is shown in the following figure (USDA, Feed Grains). It can be seen that the long term price trend is down but that there is considerable volatility. 19

50 Figure 3-1 Corn Price Corn Price, $/bu y = x Jan-80 Jan-81 Jan-82 Jan-83 Jan-84 Jan-85 Jan-86 Jan-87 Jan-88 Jan-89 Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 The corn price varies with location due to the cost of transportation and local supply and demand factors. The following table shows the average price variation between central Illinois and other locations between 1981 and Corn prices are lower in Minneapolis and Nebraska, two regions that have the highest freight costs to export corn. It is not surprising therefore that both these regions have seen significant ethanol plant development. Table 3-2 Variation in Corn Price Basis Location Price Basis, US$/Bushel Central Illinois Chicago Gulf ports, Louisiana Gulf, barge delivered Kansas City Memphis Minneapolis Omaha St. Louis Toledo A portion of the feedstock price is offset by the sales of co-products. The DDG selling price for central Illinois is shown in the following figure. The figure would appear to indicate that DDG pricing has been declining with respect to soybean pricing over this time period. The reduction in DDG price corresponds to increasing DDG production thus altering the supply and demand dynamics. 20

51 Figure 3-2 Historical DDG Pricing $350 $300 $250 $200 $150 $100 y = x $50 $0 Sep-81 Sep-82 Sep-83 Sep-84 Sep-85 Price US $/Ton Sep-86 Sep-87 Sep-88 Sep-89 Sep-90 Sep-91 Sep-92 Sep-93 Sep-94 Sep-95 Sep-96 Sep-97 Sep-98 Sep-99 Sep-00 Sep-01 Sep-02 Sep-03 Sep-04 Corn DDG Soymeal Linear (Corn DDG) The net feedstock price, where the co-product credits are offset against the corn price is shown in the following figure. Figure 3-3 Net Feedstock Cost Sep-81 Sep-82 Sep-83 Sep-84 Sep-85 US Cents/Litre Sep-86 Sep-87 Sep-88 Sep-89 Sep-90 Sep-91 Sep-92 Sep-93 Sep-94 Sep-95 Sep-96 Sep-97 Sep-98 Sep-99 Sep-00 Sep-01 Sep-02 Sep-03 Sep-04 Year 21

52 This figure shows the same volatility as the corn price but the price trend is actually slightly up. The downward price trend on the DDG more than offsetting the downward price trend on the corn price and resulting in a slight upward bias to net feedstock costs Ethanol Selling Prices The historical data for ethanol and gasoline selling prices are shown in the following figure. It is apparent that the relationship between the prices is not fixed but rather it varies with supply and demand figures. Figure 3-4 Ethanol and Gasoline Selling Prices $2.00 $1.80 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Jan-82 Jan-83 Jan-84 Jan-85 Jan-86 US $/USG Jan-87 Jan-88 Jan-89 Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Ethanol Gasoline Operating Margins The financial performance of the US Ethanol industry can be estimated from the cost of the primary inputs (corn and energy), the other operating costs and from the ethanol selling price. The net operating margins as calculated here are essentially the earnings before interest, taxes, depreciation and amortization (EBITDA). For this calculation the average electricity and natural gas prices for industrial customers from the EIA has been used and typical energy consumption factors for a dry mill plant that also dries all of its co-product has been assumed. The energy consumption requirements have been scaled over time to adjust for the continuing improvements that the industry has made. This is shown in the following figure. The effects of any state payments or payments under the USDA Bioenergy program are not included in this generic analysis. 22

53 Figure 3-5 Historical Operating Margin $1.00 $0.80 $0.60 $/US Gallon $0.40 $0.20 $0.00 -$0.20 Jan-82 Jan-84 Jan-86 Jan-88 Jan-90 Jan-92 Jan-94 Jan-96 Jan-98 Jan-00 Jan-02 Jan-04 -$0.40 The high levels of operating margin in the 1980 s were impacted by the presence of state tax incentives that were common in that period. The much higher capital costs for plants built during that decade also required higher margins. This operating margin must cover the capital related costs, the debt servicing and any return on equity. The depreciation, amortization, and interest costs will be depend on the capital structure of the facility and its age but will be in the range of $0.10 to $0.20/US gallon for most modern facilities. In the early period for the industry when capital costs were 2 to 3 times the current level, the capital related charges could reach 40 cents (US$) per gallon. The equity participants are not likely to see a return on their investment until operating margins are above $0.20/gallon for the recent projects. The operating margin data for the past eight years is shown in the following figure. This data is more typical of the recent industry experience since it does not include any state fuel tax incentives. 23

54 Figure 3-6 Recent Operating Margins $1.00 $0.80 $0.60 US $/USG $0.40 $0.20 $0.00 -$0.20 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 -$0.40 The following table presents the annual average operating margins for the past five years. This data will be compared against some actual plant operating and financial data in the next section to verify the model. Table 3-3 Annual Average Operating Margins Year Margin US cents/us gallon Can cents/litres CANADA The Canadian ethanol industry is currently quite small and diverse which makes it difficult to develop meaningful industry performance data. Some general observations are appropriate. Ethanol has generally been priced in Canada on a fixed formula basis, usually a small discount to rack gasoline plus tax incentives. In the United States, there are no such formulas and the price of ethanol can change daily based on the price of gasoline and the general supply and demand situation. The following figure shows the difference between a calculated ethanol prices in Toronto (gasoline rack minus 2.7 cpl plus tax incentives) less the ethanol price in Nebraska. For most of the past ten years, the Canadian formula driven price was higher than the US market price but there have been a few instances where the reverse has been the case. Large positive price spreads encourage ethanol users to import US ethanol rather than contract for Canadian ethanol supply. 24

55 Figure 3-7 Toronto Minus Nebraska, cpl Jan Comparison of US and Canadian Ethanol Prices Jul-93 Jan-94 Jul-94 Jan-95 Jul-95 Jan-96 Jul-96 Jan-97 Jul-97 Jan-98 Jul-98 Jan-99 Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Later in the report there is a full description of the competitiveness of Canadian ethanol compared to US ethanol production but one of the differences is feedstock cost. In Ontario, corn is more expensive than corn in most of the ethanol producing regions of the United States. This is shown in the following figure where Ontario corn (Agriculture Canada, 2004) is compared against the corn price in central Illinois (USDA, Feed Grains). 25

56 Figure 3-8 US vs. Ontario Corn Price $ $ $ $ $ $50.00 $0.00 Aug-93 Feb-94 Aug-94 Feb-95 Canadian $/Tonne Aug-95 Feb-96 Aug-96 Feb-97 Aug-97 Feb-98 Aug-98 Feb-99 Aug-99 Feb-00 Aug-00 Feb-01 Aug-01 Feb-02 Aug-02 Feb-03 Aug-03 Illinois Corn Chatham Corn It is apparent from the figure that price of corn in Ontario is more than it is in the United States and that the difference has increased in recent years. As noted earlier the local price of corn varies depending on location and the costs of moving the product to market. There are regions such as Minnesota and Nebraska where corn is less expensive than the Illinois price shown above. This widening of the basis corresponds to a period of larger US imports of corn into Ontario to meet the local demand. A portion of the higher corn prices should be offset by higher DDG prices (Farm Market News) as shown in the following figure but the remainder is reflected in a higher production cost of ethanol. 26

57 Figure 3-9 Ontario DDG Prices vs. Illinois DDG DDG Can $/Tonne Jul-00 Sep-00 Nov-00 Jan-01 Mar-01 May-01 Jul-01 Sep-01 Nov-01 Jan-02 Mar-02 May-02 Jul-02 Sep-02 Nov-02 Jan-03 Mar-03 May-03 Jul-03 Sep-03 Nov-03 Jan-04 Mar-04 May-04 Jul-04 Illinois DDG Chatham DDG A margin model of a typical Ontario ethanol plant can be developed with the corn and DDG price data shown above. The monthly average natural gas price has been estimated based on Alberta AECO prices plus transportation costs to Ontario. The other production costs are estimated at 10 cpl (Can) based on the values shown in Table 3-1 and the energy requirements for a modern ethanol plant are estimated. The ethanol selling prices are based on a formula price (rack plus incentives less 2.7 cpl discount) as shown earlier. The results of this margin model are shown below. 27

58 Figure 3-10 Operating Margins Ontario Ethanol Plant $0.30 $0.25 Can $/Litre $0.20 $0.15 $0.10 $0.05 $- Jul-00 Sep-00 Nov-00 Jan-01 Mar-01 May-01 Jul-01 Sep-01 Nov-01 Jan-02 Mar-02 May-02 Jul-02 Sep-02 Nov-02 Jan-03 Mar-03 May-03 Jul-03 Sep-03 Nov-03 Jan-04 Mar-04 Much like the US model the monthly variation in profitability can be significant. The model indicates a range of cash flow between 8 and 27 cents per litre over the past four years. The operation would still have interest costs, debt repayment and equity servicing costs to meet from this cash flow. The following table compares the annual average margins between the US and Ontario models. For the past three years, the margins in Ontario have been more stable than in the United States. In 2001, they were lower than the US and this was a period where US ethanol was selling at a premium to Ontario ethanol. In 2002 and 2003, the Ontario margins have been higher than the US model predicts. This is primarily a result of the US ethanol selling at a discount to its implied value of gasoline rack plus tax incentives. This period was a time of rapidly expanding US ethanol production in anticipation of a large increase in demand from California. Ethanol supply exceeded demand (until California demand started) and the price of ethanol was lowered to encourage more demand in the traditional ethanol markets. Table 3-4 Year Comparison of Annual Average Operating Margins Margin US Plant, Can cents/litres Ontario Plant, Can cents/litres 2000 (six months)

59 4. SUCCESSFUL FUEL ETHANOL OPERATIONS Successful companies can often be analyzed to gain a better understanding of the reasons for their success. Governments can learn from the factors that have lead to successful companies when they design public policy. Policies that enhance the critical success factors will be more successful than policies that might enhance other factors that are secondary to the core reasons for success. The identification and analysis of successful ethanol operations is explored in this section. 4.1 DEFINITION OF SUCCESSFUL The business literature is full of books and methods to help companies achieve success but there is much less information available on a definition of a successful company. Some examples include: Winning Behavior: What the Smartest, Most Successful Companies Do Differently, by Terry R. Bacon, David G. Pugh. Successful Companies differentiate themselves not just with superior products, but also by how they behave toward their customers at every touchpoint: service, product development, marketing, branding, bids and proposals, presentations, negotiations, and more. The Innovator's Dilemma: When New Technologies Cause Great Firms to Fail, by Clay Christensen. Successful Companies, he found, tend to swim upstream, pursuing higher-end, higher-margin customers with better technology and better products. These are examples of what Christensen dubs "sustaining innovations." They boost profitability and shareholder returns. They reflect good management. But they can also open a vacuum that disruptive upstarts may rush into with completely different offerings: worse, but cheaper and more convenient products. Dominant companies often ignore these disruptive innovations because they don't interest their mainstream customers. But in so doing, they miss the next great wave of industry growth. Winning at New Products, by Edwin E. Bobrow. In Benchmarking over a dozen leading and successful companies who create, introduce, and sell new products and services we were able to identify the key causes of this high percentage of failure. This Benchmarking, which was done for one of our Fortune 100 clients, served to confirm what our experience had taught us and what the literature bears out, and that is: 1. The most successful companies are new product machines. Rubber Maid, 3- M, HP, and others are perceived, both internally and externally, as being new product machines. Their culture is attuned to new products and all their people think new products. Their customers expect and receive many new products from them each year. This strategy comes from the leaders of the organization who say that this is the way it will be, but, more important, they make it that way throughout their organizations by their actions. 2. They have clear strategic direction. They don't just leave it to the R & D department or the New Products Group to develop products. They make sure everyone in the company knows the strategic direction and that all functions within the company are working toward that same strategic direction. 29

60 3. The corporate culture has been aligned behind new products. Communication, both internal and external, delivered in person by all executives and through various media keep sending the message that the organization is new products and services oriented. It is through action even more than statements that the culture is built. 4. Resources of people and money have been allocated. The message that your organization is new product driven will not ring true without backing up the in-tent with adequate people and dollar resources. 5. The new product effort is cross-functional. Every function must be brought into the new products and services effort. People must be kept informed of the activities and play an active role in meeting the goals that are set for new products. 6. There is a central place where the process resides. Without a New Products Group to lead, facilitate, orchestrate, update the process, and coordinate the effort it soon peters out. 7. Each has developed the process best suited for them. It is most important not to take a process off the shelf or have a consultant come in and hand you one. The process should be developed in house to serve your organization's needs. It is always best developed by you with the guiding hand of experts in the field. 8. Clear measures of success or failure are established. If you don't know what success will be, how can you measure results? The metrics must be spelled out beforehand and tied to the resources. People must know what is expected of them and the rewards they will receive if successful. There are several references to the critical success factors for fuel ethanol found in the literature. Some of these are identified below. It is interesting that the critical issues are quite different depending on perspective of the reviewer. There are reviews from two governments, which are similar in nature and there is a review from university agricultural economists, which is quite different. The European Union in their on-line discussion of biofuels and market barriers to biofuels identified five critical success factors for the development of a biofuels industry. They are: Price of agricultural non-food product and creation of new markets. Availability of land for production of industrial crops, and competing demands for use of such land. Tax relief for biofuels. Clear political involvement in a long term horizon. Promotional experiments carried out at local, regional and national levels. Natural Resources Canada (Bailey, 2002) identified the following success factors required for the expansion of the ethanol industry in Canada: Adequate feedstock supply Oil versus grain prices Feedstock and ethanol markets in close proximity to each other for lower operational costs Markets for co-products Producers must have substantial equity (low debt to equity ratio) A good lender for capital and operating credit Interest of refiners, fuel marketers and auto-manufacturers Reduction of trade barriers (provincial tax treatment) 30

61 Policies and market conditions in the United States Public awareness Successful development of cellulosic ethanol technology. Tiffany and Eidman (2003) examined the economics of fuel ethanol production in the United States and identified five primary success factors and six secondary factors. Their review was very operational in nature rather than strategic and thus their successful factors relate more to operating a business than establishing one. Their primary factors were: Corn price Ethanol price Natural gas price Conversion factor of starch to ethanol Plant capacity factor (ability to operate above the nameplate capacity). Their secondary factors identified were: Capital costs Percentage of debt Interest rates DDGS prices Electric power price Ethanol incentives From the literature, it is clear that successful companies must have a focus on their customers and their needs; the companies must have the resources (human and financial) necessary to compete; and they must have a plan and process to carry out the plan. This is sometimes called the three M s of a business plan, Markets, Money and Management. Under the management part of the business plan it is important to be able to satisfy all of the stakeholders who may be employees, neighbours, governments, etc. (the broader community). The definition of success may be different for each of these areas as discussed below Customer Perspective Customers are a critical component of all successful businesses. Meeting the customers needs is an essential part of all business strategies. Successful companies will have growing markets for their products; they will have customers satisfied with the quality and price of their products. In the case of ethanol companies, the market has been growing rapidly in North America. Much of the recent growth has been in mandated markets such as California, New York and Connecticut where the banning of MTBE and the legislated requirement for oxygen in gasoline has opened the market for ethanol. Almost all companies have access to this growing market and are benefiting from the increased demand. While it is beyond the scope of this work to survey customers to identify the best ethanol suppliers the ethanol companies that are successful in meeting their customers needs are probably operating at relatively high rates of plant utilization. This criterion can be used as a screening tool to identify successful ethanol companies. Customers could be considered either the end user of the fuel or they could be the purchaser. In the case of biofuels, the two customers are not usually the same. Ethanol has 31

62 generally had a better reception from the end user of the fuel (the motorist) than from the purchaser of the fuel (the oil companies) Lenders Perspective Most businesses use a combination of equity and debt to meet the financial needs of the corporation. There is an expectation on the part of the owners that the business will provide a greater financial return than the cost of capital and thus having some debt provides a degree of leverage to the equity participant and increases their rate of return on their investment. There are many different forms that the debt for an operation may take including: traditional borrowing o bank o life insurance companies o pension funds bond offerings sale and lease back arrangements. All of these forms have been used for ethanol plant financings in the United States and in Canada. In many cases a combination of the different forms are used. For the traditional borrowers, the debt may be for general corporate purposes where the lender has some call over all of the borrowers assets or it may be more project specific where the lenders only have the project assets as collateral. Lenders are likely to be much more critical in their review of project financing since they view a higher risk for these projects. New companies, which do not have other assets or a corporate record of accomplishment, have no choice but to seek project finance. The higher hurdles that this type of financing faces increases the difficulty for new entrants in establishing successful enterprises. There may be some differences in how the different types of lenders may view a company or project and their specific requirements for success. Co-Bank (Kistner), one of the more active lenders to co-op based ethanol plants in the United States, identified the elements that they look for in a project: Leadership should be local Excellent management team Sound business and marketing plans with a focus on o Good return on investment, o Equity strategy o Debt strategy o Guarantees Well-thought-out risk management plan Well capitalized and able to cushion for unplanned adversities Frequent, open, and honest communication with the investors. For specific projects, lenders evaluate the credit risk. Lenders typically look at five credit factors: Capacity - the repayment capability. Capital - the financial condition or the balance sheet of the business. Character - the management. 32

63 Collateral - the quality and value of the secondary repayment source. The collateral in most added-value propositions may only be used for the designated purpose and therefore is considered a special-use asset. Conditions - the purpose, amount, and requirements to operate the business. Lenders look at this credit factor from two perspectives: the external and the internal. External conditions cover such areas as the general economy, whether there is enough production in the area to support the venture, demand for the output, stability of markets for inputs and outputs (including contracts), and government regulations. In addition, they will consider the technology risks in deploying the chosen process, and they may consider process guarantees. Internal conditions include the loan covenants and the business s ability to meet a minimum set of financial standards. Successful operations from a lenders perspective will those that are able to execute and deliver the business plan. They must maintain the condition of the balance sheet so as not to imperil the repayment of the debt Investors Perspective Investors usually are primarily focussed on their return on investment when they evaluate investment opportunities. Depending on the nature if the investment group there may be other criteria that are important to the organizations mission or goals, such as: Creating markets for local products Adding value to local products Creating jobs in the local community Increasing local tax bases, and Improving the environment. The return provided by the fuel ethanol operation should be greater than that offered by other investment opportunities. Agricultural investors may be willing to accept lower returns than venture capitalists. In the United States, business plans with returns on equity of 15% are viewed as acceptable by lenders that focus on the agricultural sector, whereas other lenders look for returns of 20 to 25%, typical of what is available in non-agricultural ventures. Companies that can provide acceptable returns to lenders particularly when faced with adverse market conditions will usually provide superior returns to their equity investors over the long term Community Perspective Besides customers, investors and lenders there are many other stakeholders that have an interest in biofuel development. Local investors often consider some of these in their decisions to invest but it is not a given that all companies will consider all of the other stakeholders. Successful companies will ensure that their operations meet or exceed the requirements of environmental regulations, that they add value to the local community in terms of taxes they pay and services they enjoy, and that they are a positive addition to the community. 33

64 4.2 CANADA Of the four fuel ethanol producers in Canada, only Pound-Maker Agventures has financial statements that are publicly available. Pound-Maker s statements are consolidated for the ethanol plant and the feedlot so only limited information is available Pound-Maker Agventures Ltd. Pound-Maker Agventures Ltd operates an ethanol plant and cattle feedlot in Lanigan Saskatchewan. The ethanol plant was started in 1991 with a design capacity of 10 million litres per year. The company is now 100% owned by Pound-Maker Investments Ltd. A private company with over 200 shareholders, because of the number of shareholders, Pound-Maker Investments Ltd. annual reports are public documents. The annual reports do not provide any detailed segregated information on the ethanol plant or the feedlot but only consolidated information. The information in the table below summarizes some of the key aspects of the operation. Table 4-1 Key Operating Data for Pound-Maker Agventures Year, Ending July 31 Ethanol Production Long Term Debt Net Earnings Return on Equity 1,000 litres $1,000 $1,000 % ,781 11, ,700 10,572 2, ,534 9,135 1, ,588 7, ,995 7,200-1, ,495 6,547 1, ,584 6, ,470 6, ,011 6,017 1, ,696 5,313 1, ,232 8,230-2, ,781 7, Other than in 2000 when the ethanol plant experienced a major reduction in demand from a change in retail pricing strategy carried out by it s customer the facility has been able to operate above it s original design capacity since start up. The company was also successful in paying down its debt in the early years of operation and expand the feedlot capacity at the same time. In more recent years, the level of debt has increased as the company bought out the original minority shareholders and restructured its long term debt. The company has paid dividends to its shareholders a number of times. The nature of the swings in net earnings from year to year is a reflection of the fact that the company is involved in commodity businesses where the markets for the raw materials and the products produced may move in different directions. In spite of these swings the company has twice been able to refinance it s long term debt when the original terms expired. 34

65 4.2.2 Commercial Alcohols Inc. Commercial Alcohols Inc. (CAI) is the largest manufacturer and supplier of industrial, fuel, and beverage grade alcohols in Canada. CAI owns and operates a continuous process corn dry-milling ethanol distillery in Chatham, Ontario and a batch process corn dry milling ethanol distillery in Tiverton, Ontario. Combined, the two facilities currently produce over 200 million litres of alcohol per year. The nameplate capacity of the two plants is 170 million litres/year. The Tiverton plant was commissioned in 1989 and the Chatham plant in The 150 million litre per year Chatham plant cost about $150 million to construct. A portion of the high capital cost can be explained by the production of potable alcohol and by the cogeneration of power and steam at the site but even adjusting the capital cost downward for these two factors, this was still a relatively high cost facility. The Chatham facility also experienced a number of design issues (in the DDG drying area) and start-up problems that impacted on production for the first several years of operation. In this case, the process engineering and the detailed design engineering were performed by separate companies this probably impacted the project cost and the design issues. There are a couple of public investment funds (Covington Fund 1 and Vengrowth 1) that have made investments in Commercial Alcohols and these funds have noted in their annual reports that additional equity was required to be injected in the company in In addition, CAI owns full service alcohol-packaging plants in Brampton, Ontario and an alcohol packaging and processing facility in Connecticut, which operates under the trade name Pharmco Products Inc. CAI is a Canadian controlled private corporation and thus very little data on their financial operations is available. It is known that total sales exceed $225 million per year and that they have over 5,000 active customers. Like most ethanol plants, the CAI plants are now operating at production rates above their nameplate capacity. CAI produces more than just fuel ethanol and operates Canada s only ethanol packaging plant. They offer a full range of ethanol products from fuel ethanol to specially denatured ethanol grades to beverage ethanol. These other products are higher value than fuel ethanol and explain the relatively high per unit revenue that CAI reports. 4.3 UNITED STATES Ethanol plant ownership in the United States takes many forms. There are plants owned by large multi-national corporations, by small enterprises and many by farmers. The structure of the industry has changed over the years. Initially the participants were large corporations but in recent years most of the growth of the US industry in terms of new plants has been from the local owner sector. Many companies in the United States could have been chosen as examples of successful companies. Four have been chosen in part because of the availability of public data, but the four are geographically dispersed and represent three different technology providers. These four are all from the third phase of the industry development discussed earlier. They have several factors in common, relatively low capital costs, good operating performance. All four have significant levels of local ownership Chippewa Valley Ethanol Company The Chippewa Valley Agrafuels Cooperative (CVAC) was formed with over 650 shareholders made up of producers, elevators and local investors. Planning for the ethanol plant started in 35

66 1993. CVAC teamed up the design-builder Delta-T Corporation to form Chippewa Valley Ethanol Company, LLC (CVEC). Delta T were original equity investors, in part to meet a shortfall in equity that the local producers faced with their original equity drive. This brought together a local interest with a supply of corn and an engineering firm who had the experience and expertise in the ethanol business. The original lender to the project was the St. Paul Bank for Cooperatives. This bank was later merged with CoBank of Denver. CoBank is part of the Farm Credit System, a $117- billion (US$) nationwide network of lending institutions. The funds to finance CoBank loans come primarily from the sale of Farm Credit System securities to investors in the national and international money markets. They specialize in agribusiness, communications, energy and water systems, and agricultural export financing. CoBank's customers are local, regional and national agribusinesses, rural communications, energy and water systems, Farm Credit associations, and other businesses serving the rural United States. Some of their agribusiness customers process, market, transport and export products as diverse as beans, fruits, vegetables, grains and fish. Others specialize in farm supply products, such as feed, seed, fertilizer and petroleum-based products. Farm Credit associations or Agricultural Credit Associations provide financial services to agricultural and aquatic producers and rural homeowners. Construction on the CVEC plant began in June 1995 and was completed in April ahead of schedule and within budget. It took approximately three years for the project to crystallize from inception to operation. The plant was designed to produce 15 million USG per year. The plant was running at 100% of capacity within 30 days. The plant averaged 98% of design capacity over the first six months of operation and produced 17 million gallons during their first full fiscal year. Over the next few years production expanded to 20 million gpy, a 33% increase over the original design capacity. CVEC has recently completed an expansion of the plant to 42 million gpy. The total capital investment in the original plant and the expansion is $55.5 million (US$). The per unit capital investment is $1.32/USG. This includes the capability of producing potable alcohol, some duplication of investment between the two phases, and the installation of a higher cost but more energy efficient flash ring DDG dryer in the expansion. The local investors now have 100% ownership of the facility. They have diversified the operations and now produce some potable alcohol (Shakers vodka made from Minnesota wheat) in addition to fuel ethanol. CVEC was instrumental in forming United Ethanol Sales, LLC and later Renewable Products Marketing Group, a partnership of other Minnesota ethanol plants, to develop markets and work on value-added products in the ethanol industry. CVEC has also been able to market the DDGS co-product production in the local area. With approximately 50% of the production going to within 30 miles of Benson, Minnesota. Cooperatives in Minnesota do not have to make their financial information public. The following information on CVEC has been assembled from data published over the years on the company website. CVEC s fiscal year ends in September. The cooperative pays no income tax so Net Income before and after tax is the same. Individual members of the cooperative do pay income tax on any distributions received from the coop. 36

67 Table 4-2 CVEC Key Financial Performance Indicators Fiscal Year Ethanol Production Net Income Net Income Long Term Debt Capital Projects USG US $ million US $/USG US $ million US $ million ,000, ,400, ,000, ,240, ,000, ,600, ,900, CVEC have been successful in paying down the original plant debt in five years. The debt repayment was in addition to some distribution to shareholders and the required investments in plant capital to maintain and enhance plant operations during that period. Being in Minnesota, CVEC participated in the Minnesota producer payment program which paid the plant $3 million (US$) per year up to 2003, when the program was reduced due to state budget problems. Without these payments, the company would not have been profitable in the early years. In 2003, the company received $ 1.92 million (US$) from the USDA Bioenergy Program for the increase in ethanol production. Further payments are expected for It can be seen that the first three fiscal years were marginal in terms of profitability but the plant has been much more successful in the past four years. CVEC has also been very successful from an operational perspective and key operational data is shown in the following table. The reduction in performance in 2003 was caused mostly due to interruptions related to the plant expansion construction. Table 4-3 CVEC Key Operational Performance Indicators Fiscal Year Ethanol Fuel used Ethanol Yield Ethanol Yield Production USG BTU/USG USG/Bu Litres/tonne ,000,000 46, ,400,000 46, ,000,000 39, ,240,000 37, ,000,000 33, ,600,000 32, ,900,000 34, CVEC has been able to increase production continuously since they have started and are marketing a large proportion of their DDG in the local area. They would appear to satisfying their customers. They have been innovative in addressing their corporate structure, their business and operating practices and the products (e.g. potable alcohol, local DDG market) that they produce. They have been successful in paying down their bank debt rapidly and then accessing more debt for their plant expansion. They have a history of returning cash not required for debt reduction or business expansion to their shareholders. CVEC has also paid about 10 cents per bushel more for their corn than the local elevator price. Since all of the 37

68 corn for the plant comes from the coop members this is another way to pay a return on the investors equity Dakota Ethanol Dakota Ethanol, located in Wentworth, SD, produces approximately 48 million gallons of ethanol annually and was built by the Broin Companies. Dakota Ethanol was designed as a 40 million gallon facility and it began operations in August of Through plant efficiencies, and production and technology enhancements, the plant is producing well above nameplate capacity. Dakota Ethanol is a partnership formed between the cooperative Lake Area Corn Processors, LLC (LACP) and Broin Companies. Forty jobs have been created along with a significant local economic impact. LACP is required to file their annual reports with the SEC in the United States so a significant amount of public information is available. LACP owns an 88% interest in Dakota Ethanol, LLC, the company that owns the 40 million gallon ethanol plant. The remainder of the equity was supplied by the Broin Companies. Construction began in the summer of 2000, and the plant began production on September 4, It has been operating for about 2 and half years. The Cooperative is a farmer-owned cooperative with 941 members who are residents of South Dakota, Minnesota, and Iowa. Initial equity invested by the shareholders totalled $15,610,000 (US$) as of September 10, Dakota Ethanol used the proceeds contributed from the Cooperative's equity offering, as well as funds from its lender and government sources, to acquire land and construct the plant and related facilities and improvements. A portion of those funds were used for working capital to purchase the initial inventory of corn, chemicals, yeast and denaturant, Dakota Ethanol's major raw materials and to cover Dakota Ethanol's other operating costs until it began to collect receivables. Dakota Ethanol expended approximately $44.0 million (US$) of debt and equity capital to purchase the real estate, build the plant, make the necessary capital improvements, purchase the machinery, equipment and initial inventory, and cover start-up, financing and offering expenses. The lender to Dakota Ethanol is the First National Bank of Omaha. The bank has a large agricultural lending portfolio, which includes providing operating lines of credit, livestock financing (breeder financing and feedlot feeder financing programs), machinery and equipment loans and leasing. The design/build contract with Broin to design and construct the plant was for a total construction cost of $38,086,000 (US$) for a turnkey plant, including site preparation, design and construction and all machinery and equipment. Dakota Ethanol s actual cash payments under the construction contract were approximately $39.9 million (US$) because of approved change orders. In addition, Dakota Ethanol purchased and installed a thermal oxidizer, which is a pollution control device designed to reduce potentially harmful emissions. Installation of the thermal oxidizer was completed in June Dakota Ethanol had initially estimated the costs of installing the thermal oxidizer at $1.6 million and the total costs did not exceed this amount. This represents most of the 2002 capital projects shown in the following table. At the end of 2002, the balance sheet listed assets of $40.5 million (US$) or $1.01 per USG of nameplate capacity. The plant is managed under contract by Broin Management, LLC and the ethanol is marketed by Ethanol Products, LLC, a Broin affiliate and the DDG is marketed by Dakota Commodities a division of Broin Enterprises. Broin receives a fee for all of these services in 38

69 addition to their 12% equity interest in the operation. The key financial performance of Dakota Ethanol is shown in the following table. No tax is payable by the corporation so Net Income before and after tax is the same. Table 4-4 Fiscal Year Dakota Key Financial Performance Indicators Estimated Ethanol Production Net Income Net Income EBITDA Long Term Debt Shareholder Distributions Capital Projects USG US $ million $/USG $/USG US $ million US $ million US $ million ,000, ,000, Q1 ~12,000, Dakota Ethanol has been able to operate their plant at 20% above the nameplate capacity and has been quite profitable in its first two years of production. Included in the net Income for 2002 is $6.3 million (US$) and for 2003, $1.5 million (US$) from the USDA Bioenergy program and the State of South Dakota ethanol production incentive. The shareholder distributions to the cooperative members in 2002 and 2003 totalled $12.6 million (US$) ($1.7 to the minority partner) and that represented an average of a 40% return on equity to the shareholders. An additional distribution of $1.75 million (US$) was made in May Badger State Ethanol Badger State Ethanol, LLC (BSE) is a Wisconsin limited liability company that is operating a dry-mill ethanol production facility in Monroe, Wisconsin. The plant started production mid- October 2002 and is capable of producing 40 million gallons or more of ethanol and 128,000 tons of distillers grains each year. The plant was built by Fagen, Inc. of Granite Falls, MN and designed by ICM Engineering of Colwich, KS. The owners, mostly local producers and investors, entered into a contract with Fagen in which Fagen provided services to them in connection with their plan to build an ethanol plant. Under the terms of the contract, Fagen agreed to design and provide construction related services to us not to exceed $43.8 million (US$). Additionally, Fagen and ICM, Inc. entered into a subcontractor relationship for the construction of the ethanol plant, whereby Fagen was the general contractor and ICM, Inc. was the subcontractor. At December 2002, the total value of the plant, land, improvements and office equipment was $ million (US$). The per unit cost of the plant was $1.16/USG. The owners of the plant raised $17.9 million (US$) in an equity drive in There was a term loan of $30.6 million (US$) provided by First National Bank of Omaha for the remainder of the capital costs. The financial performance of the plant in its first two years is shown in the following table. The first year of operation was less than three months. Due to the company s organization as a limited liability company, the income or loss of the company is reportable by the respective members on their personal income tax returns. Therefore, no income tax provision is included in the company financial statements. 39

70 Table 4-5 Fiscal Year Badger State Ethanol Key Financial Performance Indicators Estimated Ethanol Production Net Income Net Income EBITDA Long Term Debt Shareholder Distributions Capital Projects USG US $ million $/USG $/USG US $ million US $ million US $ million ,500, ,400, Q1 ~12,000, BSE received $7.5 million (US$) in 2003 under the USDA Bioenergy Program and expects to receive approximately $3 million (US$) from this program during They did not receive nor accrue any incentive payments for The ethanol industry also benefits from various state production incentives. During 2003, BSE received approximately $1.63 million (US$) as a production incentive from the state of Wisconsin and expect to receive approximately $633,000 (US$) in The state program has not been renewed and the likelihood of this incentive being available in the future is in doubt. The company uses forward contracts to set the price of some of their inputs and a part of the improved performance in the first quarter of 2004 was due to gains realized on the value of the contracts as corn and natural gas prices increased Northern Lights Ethanol Northern Growers, LLC is a South Dakota limited liability company that owns and manages a 77.16% interest in Northern Lights Ethanol, LLC. Northern Lights built and operate a 40 million gallon ethanol plant near Big Stone City, South Dakota, which produces ethanol and distiller's dried grains with solubles. Northern Lights began grinding corn on June 26, 2002 and the first ethanol was produced on July 5, Northern Growers' 650 members, who are residents of South Dakota, North Dakota and Minnesota, are primarily agricultural producers and they supply a significant portion of the plant's corn requirements. Northern Growers was originally formed as a South Dakota cooperative and on March 27, 2003, the members of Northern Growers approved a reorganization into a South Dakota limited liability company. Northern Growers is farmer-owned with initial equity invested in 2001 by the shareholders totalled $12,738,940 (US$). The Cooperative has a 77.16% ownership interest in Northern Lights Ethanol, the remainder is held by Broin Investments. Northern Lights used the proceeds contributed from the Cooperative's equity offering, as well as funds from its minority member (Broin Investments), its lender and government sources, to construct the plant and related facilities and improvements. A portion of those funds was used to purchase the initial inventory of corn, chemicals, yeast, and denaturant, which are Northern Lights' major raw materials, and to cover Northern Lights' other operating costs until it began collecting on its receivables. Northern Lights originally anticipated that a total of $43.9 million (US$) of debt and equity capital would be necessary to construct the plant, make the necessary capital improvements, and purchase the machinery and equipment. Northern Lights have a similar relationship with the Broin Companies that Dakota Ethanol has and was described above. Broin manages the plant and markets the ethanol and DDG on behalf of the plant. 40

71 The primary lender is U.S. Bank National Association, Sioux Falls, South Dakota. U.S. Bancorp with assets in excess of $189 billion (US$) is the 8th largest financial services holding company in the United States. As of December 31, 2002, Northern Lights balance sheet includes $44.2 million (US$) for land, equipment and building. The per unit capital cost was $1.10 per USG based on the design capacity. The Northern Lights' ethanol plant has one unique feature in which steam is supplied primarily from a source other than on-site boilers. The plant's steam requirements are supplied by the coal Big Stone Power Plant, although the plant has boilers on site for use as necessary in the event of an interruption in the steam supply from Big Stone, or if economic conditions favour use of the on-site boilers. The Big Stone Power Plant is directly adjacent to the site where the ethanol plant is located. The system has cut their demand for and usage of natural gas in half - and has reduced their overall steam generating costs by 25%. The LLC is treated as a partnership for federal income tax purposes. The LLC pays no tax on its net income. Rather, each member will be subject to income tax based on the member's allocable share of income, gain, loss, deduction and credits, whether or not any cash is actually distributed to the member. The LLC's members have the same corn delivery obligations as with the original Cooperative structure. The key financial performance of the company since start-up is shown in the following table. Table 4-6 Fiscal Year Northern Lights Ethanol Key Financial Performance Indicators Estimated Ethanol Production Net Income Net Income EBITDA Long Term Debt Shareholder Distributions Capital Projects USG US $ million $/USG $/USG US $ million US $ million US $ million ,500, ,580, Q1 12,000, In addition to product sales revenue, Northern Lights recorded incentive revenue of approximately $5.3 million (US$) during the year ended December 31, 2003 and $7.1 million (US$) for the six months of production in the year ended December 31, Incentive revenue consists of income received from federal and state governments in connection with Northern Lights ethanol production. For the years ended December 31, 2003 and 2002, Northern Lights recorded approximately $4.1 million (US$) and $6.7 million (US$), respectively, of incentive revenue from the United States Department of Agriculture s Commodity Credit Corporation under its Bioenergy Program. Northern Lights recorded incentive income of approximately $1.2 million from the state of South Dakota for the year ended December 31, 2003, and approximately $400,000 (US$) for the year ended December 31, Of this $1.2 million for the year ended December 31, 2003, $600,000 (US$) is attributed to the 2003 program year, which ended June 30, 2003 and $600,000 (US$) is for the 2004 program year Summary US Ethanol Plants The financial results of the three plants and the plant model developed in the previous section are summarized and compared in the following table. In this case, the EBITDA is 41

72 used, as that is the closest to value predicted by the model. CVEC is not included because they have a different year end. Table 4-7 Summary of US Ethanol Plant EBITDA Results Q1 $/USG $/USG $/USG Industry Margin Model Dakota Ethanol Badger State Ethanol Northern Lights Average of Three Plants Average without incentives There is significant variation between the individual plants and between the average of the three plants and the model. The three likely reasons for this are: The use of derivatives and forward pricing contracts, The plants received USDA Bioenergy funds and some state production incentives, The local market conditions for the major inputs and products. The plant financial results should be better than predicted by the model because of these additional factors. The company financial statements do acknowledge the use of futures contracts but do not separate that item out in the financial statements. Some plants sell their ethanol using a combination of spot prices, fixed three to six month prices and a fixed basis to the floating gasoline price. The industry model uses spot prices for all of the major commodities. The financial statements also identify the federal and state payments. Over time, it is likely that the use of derivatives or spot pricing will provide the same average return. Over the 27 month period in the table the predicated results and the actual results without the USDA and state incentives is almost identical. The success factors of these plants can be summarized as: Low capital costs, Significant amount of equity investment. Proven expertise with design/build engineers and contractors, Efficient operations capable of operating at 20% above the nameplate capacity, The use of professional management to supplement local skills, Co-operative marketing of ethanol and DDG, Continuous improvement programs, in some cases driven by co-operative R&D programs. 42

73 5. ETHANOL FEEDSTOCKS The dominant feedstock for fuel ethanol production in North America is corn but almost any material containing cellulose, starch or sugar can be used to produce ethanol with existing technology. Four feedstocks are produced in large enough quantities to be considered for commercial ethanol production with commercial technology, corn, wheat, barley, and in some regions potatoes. The regional availability of these feedstocks is discussed in this section. There are other starch and sugar containing crops such as rye, triticale, oats, and sugar beets that can theoretically be converted to ethanol but the production volumes of these crops in Canada is generally low and not sufficient to use as a base on which to build an ethanol industry on. Technology is being developed that will be able to produce ethanol from cellulosic materials. In light of this the potential ethanol feedstocks of corn stover, wheat and barley straw, hay and wood residues are identified as well in this section. Consideration is given to the supply and disposition of each of these feedstocks in addition to their production rates. Since the interest here is in commercial production, regions with less than 500,000 tonnes of the grain feedstocks are generally not considered to be large enough to support commercial ethanol production. The exception being the Maritime Provinces where the threshold is 50,000 tonnes because of the lower implied demand for ethanol in those regions. 5.1 CORN Corn is the dominant feedstock for ethanol production in the United States. The United States is a large exporter of corn. In Canada, corn is produced primarily in Ontario and Quebec and currently supply and demand are roughly in balance domestically Corn Production The primary corn producing regions of Canada are Ontario and Quebec but small amounts of corn are grown in other provinces as well. In the following table the 2003 corn production by province is shown (Statistics Canada, 2004). There is also fodder corn produced in a number of regions, principally Ontario and Quebec. This corn is not suitable for ethanol production and is used directly for animal feed. 43

74 Table 5-1 Corn Production ,000 tonnes British Columbia 0 Alberta 7.6 Saskatchewan 0 Manitoba Ontario 5,562.9 Quebec 3,500.0 New Brunswick 0 Nova Scotia 21.5 Prince Edward Island 0 Newfoundland 0 Yukon 0 North-West Territories 0 Nunavut 0 Canada 9,587.3 There is insufficient corn production in Alberta and Nova Scotia to support ethanol production. The corn production in Manitoba has been increasing in recent years and while some is used for ethanol production, the volumes are not sufficient to be the sole feedstock for large scale ethanol production in that province. The Ontario Corn Producers Association (2004) provides a summary of corn production and disposition for the two major corn producing regions and that data is summarized in the following tables. Table 5-2 Ontario Corn Supply and Disposition 1999/ / / / / tonnes 1000 tonnes 1000 tonnes 1000 tonnes 1000 tonnes Ontario production 5, , , , ,564.4 Imports from U.S , , , ,142.9 Total Ontario supply 7, , , , ,619.0 Ontario industrial use 1, , , , ,158.7 Ontario feed use 3, , , , ,114.3 Ontario exports Total Ontario use 6, , , , ,463.5 The dominant use of corn in Ontario is for feed and the industrial use including fuel ethanol production utilizes about 40% of the domestic production. The existing fuel ethanol industry in Ontario uses about 500,000 tonnes of corn per year. Ontario has been a net importer of US corn for several years. The Quebec corn supply and disposition is shown in the following table. Feed usage dominates the disposition of corn in Quebec. Imports and exports are reasonably balanced most years. 44

75 Table 5-3 Quebec Corn Supply and Disposition 1999/ / / / / tonnes 1000 tonnes 1000 tonnes 1000 tonnes 1000 tonnes Quebec production 2, , , , ,502.2 Imports Total Quebec supply 3, , , , ,388.6 Quebec industrial use Quebec feed use 2, , , , ,225.4 Quebec exports Total Quebec usage 3, , , , ,606.3 Increased fuel ethanol production from corn in Canada will require increased production or some changes to the traditional supply and disposition patterns. These possibilities are discussed below. The corn area harvested in Canada is shown in the following figure, after a rapid increase through the 1960 s and 70 s the area devoted to corn was relatively stable through the 80 s and 90 s. There has been a recent increase probably due to new varieties requiring less heat and thus suitable for more regions in Canada. With the requirements for crop rotation in modern agriculture, it is unlikely that there would be large increases in corn acres even if the demand increased. There is less than 0.5% of the Ontario and Quebec farm land in summerfallow every year so increased corn production can not come from decreased summerfallow acreage. Figure 5-1 Canadian Corn Area 1,400,000 1,200,000 1,000, , , , , Area, hectares

76 One factor that will contribute to increased supply is the annual improvement in yield that the corn industry has experienced. The performance over the past 50 years is shown in the following table. The industry has experienced an increase of about 1.25 bushels per year over this time period. By 2010, this could be expected to contribute an additional 650,000 tonnes per year of corn, which is sufficient to produce 260 million litres of ethanol. Figure 5-2 Ontario Corn Yield Yield, Tonnes/ha The only other potential for increased corn supply for ethanol is through the reduction in the amount of corn used for feeding or other industrial uses in Ontario and Quebec. Animal feed is the primary use for corn production in both of these provinces. Corn demand by class of animal in Ontario and Quebec is shown in the following table (Statistics Canada, 2003). Table 5-4 Livestock Demand for Corn 2001 Ontario Quebec Total 1,000 tonnes 1,000 tonnes 1,000 tonnes Beef Cattle Dairy Cattle ,708.4 Hogs 1, , ,358.1 Poultry Total 3, , ,482.1 Each of these classes of animals also consumes soybean meal as part of their rations. In Ontario, the soymeal consumption is about 25% of the corn usage for each class of animal as shown in the following table. 46

77 Table 5-5 Livestock Demand for Soybean Meal 2001 Ontario Quebec Total 1,000 tonnes 1,000 tonnes 1,000 tonnes Beef Cattle Dairy Cattle Hogs Poultry Total 1,911 1, ,455.4 The use of corn DDG in the rations of cattle can reduce the demand for both soybean meal and corn. It may be possible to increase the availability of corn by increasing the DDG use in Ontario and Quebec. Approximately 400,000 tonnes of corn could be made available through the greater use of the DDG in cattle rations. Less is known about the use of DDG in hog and poultry rations but DDG use in these sectors has been increasing in the United States. Additional corn could probably be liberated in these sectors as well. In other parts of Canada wheat and barley is used in place of corn in animal rations so it would be possible to import these grains from western Canada to displace corn feed and make more available for ethanol production. This may require a higher price for the corn or at least a larger differential between corn prices and wheat and barley prices to be attractive to the livestock sector. The final potential source of additional corn for ethanol production would be the reduction in the use of corn for other industrial applications. Nacan Products Limited, a division of US based National Starch & Chemicals has announced that it is closing its Collingwood, Ontario cornstarch manufacturing facility by the end of This plant processed about 90,000 tonnes of corn per year, which could be used to produce 35 million litres of ethanol per year. In summary, increased domestic corn availability for ethanol production is most likely going to come from increased production through higher yields (a maximum potential of 600,000 tonnes/year by 2010), and increased use of DDG displacing both corn and soybean meal from animal rations (potential of 400,000 tonnes/year). Both of these scenarios are feasible without major changes in the price of corn. Further substitution of the corn used for animal feed is possible but would probably only happen with higher relative corn prices. A maximum potential of one million tonnes of corn will produce 400 million litres of ethanol. There may also be an additional 100,000 tonnes from reduced industrial processing and perhaps some released from feed usage in Quebec when there is an industrial alternative. This is in addition to the existing usage of 500,000 tonnes per year. It is more likely that only a portion of this will be available as feed usage of corn may also continue to increase and use a portion of this new availability. A more likely scenario is that an additional 800,000 tonnes of corn might become available for ethanol production over the next six years. Imports of corn from the United States are also a source of additional feedstocks and serve as a safety valve to meet increased demand in years when domestic production is reduced Corn Prices The price of corn varies from year to year depending on the global supply and demand situation. Feed grain prices are reported weekly by Agriculture and Agri-Food Canada s Market Analysis Division. The historical corn prices for Chatham, Ontario and for St Jean, Quebec are shown in the following figure. Historically, the price of corn in Quebec is slightly 47

78 higher than it is in Ontario, although recently as Ontario has moved to be a net importer Ontario prices have risen and are now comparable with those in Quebec. Figure 5-3 Corn Prices Can $/tonne /08/93 02/02/94 02/08/94 02/02/95 02/08/95 02/02/96 02/08/96 02/02/97 02/08/97 02/02/98 02/08/98 02/02/99 02/08/99 02/02/00 02/08/00 02/02/01 02/08/01 02/02/02 02/08/02 02/02/03 02/08/03 02/02/04 St Jean Chatham The long term average corn price is shown in the following table. Table 5-6 Average Corn Prices 1993 to 2004 Price $/tonne $/bu Chatham, Ontario St. Jean, Quebec WHEAT Wheat has been used for fuel ethanol production for the past 20 years in Canada. There is also significant fuel ethanol production based on wheat in France, Sweden and Spain. In the United States, some ethanol is produced from wheat at vital wheat gluten plants Wheat Production Wheat is produced is many regions of Canada but the major producing provinces are the three Prairie Provinces plus Ontario. The provincial distribution of wheat production in 2003 is shown in the following table (Statistics Canada, 2003b). Only Alberta, Saskatchewan, Manitoba and Ontario have sufficient wheat production to consider using it as an ethanol plant feedstock. 48

79 Table 5-7 Wheat Production ,000 tonnes British Columbia 53.1 Alberta 6,456.8 Saskatchewan 10,433.0 Manitoba 4,162.5 Ontario 2,218.1 Quebec New Brunswick 15.3 Nova Scotia 11.2 Prince Edward Island 30.0 Newfoundland 0 Yukon 0 North-West Territories 0 Nunavut 0 Canada 23,552 The wheat crop will change in size from year to year depending on market and growing conditions. The historical Canadian wheat production (Canadian Wheat Board, 2001 and 2003) is shown in the following figure. Durum production has remained relatively constant but other types of wheat have seen a decline in production. Figure 5-4 Historical Wheat Production 35,000 30,000 Wheat Production, tonnes 25,000 20,000 15,000 10,000 5, Wheat Durum All Wheat 49

80 The primary reason for the drop in wheat production has been the decline in acres planted. The wheat yield trend line has remained almost constant over this time period. Producers have been able to produce higher returns from diverting wheat acres to oilseeds and specialty crops. The wheat area remains more than double the next largest crops, barley and canola. Wheat acreage is expected to remain near current levels over the next decade with production rising slightly due to higher yields (Agriculture and Agri-Food Canada, 2004b). The historical wheat acreage is shown in the following figure. Figure 5-5 Wheat Acreage 40,000 Wheat Acreage, Thousand Acrea 35,000 30,000 25,000 20,000 15,000 10,000 5, Wheat Durum Wheat All Wheat The wheat supply and disposition for recent years (Statistics Canada, 2004) is shown in the following table. Unlike corn and barley the majority of the wheat crop is exported. The domestic usage for feed and industrial applications is less than the domestic usage of corn or barley despite the crop size being two to three times larger than either of the other two crops. The feed, wastage, and dockage (FWD) value is not measured but it is calculated as the residual value based on the other categories. To the extent that one or more of the other categories is understated or overstated, this will impact on the implied FWD value. 50

81 Table 5-8 Wheat Supply and Disposition Average ,000 tonnes 1,000 tonnes 1,000 tonnes Production 24,485 20,568 16,198 Imports Grain Exports 17,053 15,942 8,899 Product Exports Total Exports 17,281 16,214 9,191 Human Food 2,813 2,910 2,938 Industrial Use Seed Requirements 1,031 1,019 1,020 Feed, Wastage and Dockage 3,780 3,333 4,187 Total Domestic Disappearances 7,728 7,388 8,264 Total Disappearance 25,009 23,330 17,455 The historical trend for wheat exports is shown in the following figure. Wheat exports have been declining along with the production, as financial returns from the export of wheat have not been as attractive to producers as those of other crops. The wheat exports from Canada represent about a 15% share of the world market. Figure 5-6 Historical Wheat Exports 30,000 Wheat Exports, 1000 tonnes 25,000 20,000 15,000 10,000 5, Wheat Grades While all producers endeavour to produce the highest quality product, the wheat quality is usually determined by the weather conditions during the growing and harvesting seasons. Wheat quality is traditionally measured by the protein levels in the grains and by the 51

82 presence of damaged and foreign materials in the grain. Wheat that grades as #1 or #2 is the preferred grain for flour or food production. Wheat that grades #3 or lower is usually used for feed purposes. Lower grades are priced lower than higher grades although the discounts can vary from year to year. Ethanol producers have different quality criteria that they are interested in, starch and fermentable content. Protein and starch levels usually move in opposite directions with lower protein wheat usually having a higher starch content and being less expensive are more attractive ethanol feedstocks. The distribution of wheat grades for various years is shown in the following table. Grade data on the whole Prairie wheat crop is not readily available. Agencies such as the Canadian Wheat Board and the Canadian Grain Commission are more focussed on the grade data of the material that is available for export. The provinces of Saskatchewan and Manitoba have undertaken field surveys in the past and that data has been combined on a production weighted basis to arrive at the values shown in the following table. The amount of wheat grading #3 or lower averages about 30% of the crop. It is this material that is of interest to ethanol producers. On a total wheat crop of 23 million tonnes, this represents an average of about 6.9 million tonnes per year of lower grade wheat. This is higher than is required for feed use and results in some of the lower grade material being sold in export markets. Table 5-9 Wheat Production by Grade #1 #2 #3 <#3 Sum #3 and lower % % % % % 01/ / / / / / / / / / / / / / / / / Average Wheat Classes Unlike corn there are a number of classes of wheat make up the total production and this is summarized in the following table. Each class of wheat has been developed to meet specific market and/or agronomic needs. These classes are shown in the following table. 52

83 Table 5-10 Class Canadian Wheat Production by Variety Typical Protein Level (%) Average Production, Million tonnes Canadian Western Red Spring (CWRS) Canadian Western Extra Strong (CWES) Canadian Prairie Spring Red (CPS-R) Canadian Western Red Winter (CPRW) Canadian Prairie Spring White (CPS-W) Canadian Western Soft White (CWSWS) Canadian Western Amber Durum CWAD) Eastern Canadian 1.4 Total As stated above, ethanol producers convert the starch in wheat to ethanol and look for grades and classes that have a lower protein content and thus a higher starch content. The wheat classes that are of most interest to ethanol producers are Canadian Prairie Spring (Red and White), Canadian Western Red Winter and Canadian Western Soft White because of their specific properties and 3 CWRS and lower grades because it is often the lowest price. Canada Prairie Spring Red Wheat (CPS-R) has been developed to allow Canadian farmers to compete with American hard red winter wheat in markets that do not require the high protein and strong gluten of CWRS wheat for the products that they produce. These include hearth breads such as French bread, flat breads such as pita, and crackers. CPS-R production is estimated by Agriculture and Agri-Food Canada (AAFC) to have averaged about 1.8 Mt between 1997 and Production in the period averaged only 411,000 tonnes so the production of this class of wheat has been expanding quickly as domestic demand for the class increased. Exports of CPS-R wheat have averaged 353,000 tonnes over the past five years, about 20% of production, with the major markets being countries that tend to use wheat for the production of flat breads or noodles. The major domestic use of CPS-R wheat is for feeding livestock, largely hogs, in western Canada. CPS-R wheat is priced lower than CWRS wheat, and it does not receive protein premiums. The price for #1 and #2 CPS-R is usually comparable to the price #3CWRS wheat. It yields about 20-30% higher than CWRS, largely offsetting the lower price. Canada Western Red Winter Wheat (CWRW) is the only winter wheat grown on the Prairies. It is grown only on a small area, with production averaging just 311,000 tonnes between 1997 and Production is rising, particularly on the eastern Prairies, and it reached 441,000 tonnes in 2001, with almost 50% grown in Manitoba. The popularity of CWRW is increasing, as it provides several important benefits. On average, winter wheat yield is 23% higher than spring wheat. It often escapes infection by serious pests such as Fusarium Head Blight and the orange wheat blossom midge. It offers workload displacement, and promotes conservation tillage practices. Average protein content of CWRW is similar to CPS-R, averaging 11.3%. Exports have averaged only 58,000 tonnes over the past 5-years. Domestically, the major use of CWRW is for feed. Canada Prairie Spring White wheat (CPS-W) varieties were developed by Canadian wheat breeders largely in response to demand from the Asian noodle market, which traditionally 53

84 imported Australian Standard White wheat for noodle production. Average protein content is slightly lower than CPS-R wheat, with the 5-year average being 11.2%. The white seed coat produces a flour with fewer visible bran specks, and with a whiter colour at high extraction rates, compared to a red wheat. Production of CPS-W is estimated by AAFC, to have averaged about 0.4 Mt over the past 5- years. Exports of CPS-W have averaged almost 300,000 tonnes between and , relatively little is milled domestically, and the slightly higher protein CPS-R wheat is preferred for livestock feeding. Canada Western Soft White Spring Wheat (CWSWS) is the only soft wheat grown on the Prairies. It has a soft kernel and low protein. Most is grown under irrigation, in southern Alberta, since dryland production can result in excessively high protein content if rainfall is not adequate. It can be used for flat breads, but it is largely used for the production of cookies, pastries, biscuits and crackers. Due to low prices, production has been declining, as alternative crops could be more profitably grown on the irrigated land. The 1997 to 2001 average has been about 150,000 tonnes, but this fell to only 72,600 tonnes in As a result, most CWSWS is now used domestically in western Canada for the production of cake and pastry flour. Eastern wheat is mostly winter wheat grown primarily in Ontario. Only a small amount of this wheat is exported. A large portion of the wheat is milled domestically for food applications. Given the lower production than corn in Ontario it is not likely to be a feedstock of major interest to ethanol producers in the region. All of the wheat classes that are of interest to ethanol producers are lower protein, higher starch and higher yielding the Canadian Western Red Spring wheat. A larger domestic market for these classes should lead to higher production of these classes through the substitution of land for these wheats with land used for CWRS. This would result in an increase in wheat produced and a slight decrease in wheat available for export. The pricerevenue yield for the different wheat varieties compared to CWRS is shown in the following table (CWB-MARC). Note that crop yield as variable and some of the yield data from this source is different from other sources mentioned here. Based on this analysis, CPS-R provides more revenue from the land than does CWRS wheat and this is probably the reason for the rapid growth in production of this class in the late 1990 s. It is likely that if there were a larger market for this class more would be grown. 54

85 Table 5-11 Yield-Price Spreads between Western Canadian Wheat Classes Wheat class Yield advantage Price spread Revenue/ha average average CWAD CWRW CWES CPSW CPSR CWSWS** Non-registered Wheat Availability for Ethanol Production Wheat for the production of ethanol will come from the supplies of lower grade feed wheats and the increased production of CPS-R wheat and perhaps winter wheats. Over the past ten years, the production of CPS-R wheat has increased dramatically as the domestic demand from livestock feeders for the product increased. Increased demand from ethanol producers should also lead to higher production. Wheat feedstock availability for ethanol production will arise from the diversion of wheat production and land from exports to a domestic ethanol industry. Fifteen million tonnes of wheat exports could produce 5.5 billion litres of ethanol per year. This is far in excess of the target but it is also not reasonable to divert the total quantities of exports. Assuming that 20% of the wheat exports are diverted would result in feedstock supplies of approximately 3 million tonnes. In fact, the wheat availability will be higher than this since the land will be diverted from CWRS wheat for exports to CPS-R wheat for ethanol production. The CPS-R wheat with its 20 to 40% yield advantage will result in increased production of 3.6 to 4.2 million tonnes. Since the ethanol plants will also be an outlet for lower grades of CWRS, it will be assumed that the feedstock availability is at the low end of this range at 3.6 million tonnes. This is assumed to be available in the three Prairie Provinces proportional to the existing wheat production. This would result in 50% (1.8 million tonnes) being located in Saskatchewan, 30% (1.08 million tonnes) in Alberta and 20% (0.72 million tonnes) in Manitoba Wheat Prices The historical feed wheat prices reported by Agriculture and Agri-Food Canada s Market Analysis Division are shown in the following figure. These prices are from an elevator and not directly from a producer. They therefore include elevation charges. An ethanol plant would likely obtain its grain supply directly from the producers and pay less than these prices. Some price data on farm prices of wheat has been obtained from the Agriculture Departments of the three Prairie Provinces. This data is not as complete as the AAFC data but it can be used to estimate the difference between the farm price and the elevator price. The savings in costs for not passing through an elevator are typically $10 to $25. The savings vary with location and year. Prices in Saskatchewan are slightly lower than in Alberta and Manitoba, due to the higher transportation costs of moving grain from Saskatchewan to an export point in BC or Ontario. Wheat prices in eastern Canada are much higher than in western Canada. 55

86 Figure 5-7 Historical Feed Wheat Prices Can $/tonne /08/93 02/02/94 02/08/94 02/02/95 02/08/95 02/02/96 02/08/96 02/02/97 02/08/97 02/02/98 02/08/98 02/02/99 02/08/99 02/02/00 02/08/00 02/02/01 02/08/01 02/02/02 02/08/02 02/02/03 02/08/03 02/02/04 CALGARY SASKATOON WINNIPEG The long-term average price for feed wheat in Western Canada is shown in the following table. The price directly from a producer has been conservatively estimated at $15 per tonne less than the elevator price. Table 5-12 Average Feed Wheat Prices 1993 to 2004 AAFC Price from Elevator Price Direct from Producer $/tonne $/tonne Calgary Saskatoon Winnipeg Feed wheat prices in western Canada tend to track US corn prices rather than US wheat prices. In the following figure the annual average farm price for US #2 soft red wheat, the average farm price for US #2 corn and the feed wheat price in the elevator in Saskatoon (higher than farm prices by $10 to $15/t) are compared. All prices have been converted to Canadian dollars using the average exchange rate for the year. Canadian wheat prices averaged $126/tonne over this period and corn prices averaged $123/tonne. The US average wheat price was $159/tonne. Canadian wheat prices are always lower than US wheat prices. US wheat prices are usually higher than corn prices, which partially explains why corn is the preferred feedstock for animal feed and ethanol production in the United States. 56

87 Figure 5-8 Canadian Feed Wheat Prices vs. US Wheat and Corn Prices / / / / / / / / / / / / / /94 Can $/tonne 1994/ / / / / / / / /03 US Wheat US Corn Sask Feed Wheat 5.3 BARLEY Barley has been used intermittently for ethanol production in Canada and the United States and it is used in the Spanish ethanol plants. Compared to corn and wheat, barley has a lower starch content, higher fibre, and higher levels of difficult to ferment materials such as beta glucans. Ethanol yield from barley is typically 320 to 330 litres per tonne Barley Production Barley production in Canada is found in nine provinces, although over 90% of the production is in the three Prairie Provinces. Production for 2003 by province is shown in the following table. Production levels in 2003 were slightly above the long-term average. Only the three Prairie Provinces and Prince Edward Island meet the volume threshold set for feedstock for ethanol production. 57

88 Table 5-13 Barley Production ,000 tonnes British Columbia Alberta 5,530.2 Saskatchewan 4,354.5 Manitoba 1,371.7 Ontario Quebec New Brunswick 55.8 Nova Scotia 11.5 Prince Edward Island Newfoundland 0 Yukon 0 North-West Territories 0 Nunavut 0 Canada 12,327.6 The following figure shows the historical trend in barley production. Figure 5-9 Historical Barley Production 18,000 16,000 Barley Production, tonnes 14,000 12,000 10,000 8,000 6,000 4,000 2, Barley supply and disposition is shown in the following table. Animal feed is the primary use of barley. There are some exports of raw grain and processed barley (malt) but these volumes are much lower than the domestic usage. The export of raw grain has been declining and the exports of processed barley (malt) have been relatively stable. 58

89 Table 5-14 Barley Supply and Disposition Average ,000 tonnes 1,000 tonnes 1,000 tonnes Production 10,160 10,846 7,489 Imports Grain Exports 1,697 1, Product Exports Total Exports 2,236 1, Human Food Industrial Use Seed Requirements Feed, Wastage and Dockage 7,910 8,913 6,792 Total Domestic Disappearances 8,197 9,656 7,409 Total Disappearance 10,433 11,426 8,354 The following figure shows the historical total barley exports. These have decreased as domestic feed consumption has increased. Figure 5-10 Historical Barley Exports 6,000 Barley Exports, Thousand Tonnes 5,000 4,000 3,000 2,000 1, The historical barley acreage is shown in the following figure. The acreage has been relatively stable. It is unlikely that ethanol producers would favour barley over wheat as a preferred feedstock over an extended period of time and thus increased barley acreage is not a likely outcome of an expanded fuel ethanol industry. It is apparent that barley acreage has been relatively stable in recent years. A small increase in barley production could result from the trend towards reduced summerfallow in western Canada. 59

90 Figure 5-11 Barley Acreage 12,000 Barley Acreage, Thousand Acres 10,000 8,000 6,000 4,000 2, Some of the barley exports could be diverted towards a domestic ethanol industry. The potential volume is likely in the range of 500,000 to one million tonnes per year. This would be sufficient to produce 150 to 300 million litres per year of ethanol. Barley is a less attractive feedstock than corn or wheat from an ease of processing perspective so for most provinces it will not be the feedstock of choice. In Prince Edward Island there is no or very little corn and wheat production but, for the population, relatively high barley production rates. According to Statistics Canada (2003) only about 20% of PEI barley is used for animal feed on the island. One half of the barley production on the island would support the production of about 15 million litres per year of ethanol. It will be assumed that 500,000 tonnes of barley (about 20% of the typical export level) could be diverted from the export market to fuel ethanol production. This barley will only be available in the three Prairie Provinces and PEI. The barley available on the prairies (90% of the total) will be assumed to be available in approximate proportion to production, 50% in Alberta, 40% in Saskatchewan and 10% in Manitoba Barley Prices The historical barley prices reported by Agriculture and Agri-Food Canada s Market Analysis Division are shown in the following figure. These prices are from an elevator and not directly from a producer. They therefore include elevation charges. An ethanol plant would likely obtain its grain supply directly from the producers and pay less than these prices. Some price data on farm prices of barley has been obtained from the Agriculture Departments of the three Prairie Provinces. This data is not as complete as the AAFC data but it can be used to estimate the difference between the farm price and the elevator price. The savings in costs for not passing through an elevator are typically $6 to $15. The savings vary with location and year. 60

91 Prices in Alberta are slightly higher than in Saskatchewan and Manitoba, probably due to the higher livestock population in that province. Barley prices in eastern Canada are much higher than in western Canada. AAFC does not report barley prices for PEI, the PEI Department of Agriculture does have some data on prices for 1987 to 1999 and for the time period where both data sets are available the barley price on PEI is approximately $44/tonne less than the Truro, NS price. Figure 5-12 Barley Prices Can $/tonne Feb Oct May Dec Jul Feb Sep May Dec Jul Feb Sep Apr Nov Jul Feb Sep Apr-04 WINNIPEG SASKATOON CALGARY Truro The long-term average price for barley in Western Canada is shown in the following table. The price directly from a producer has been estimated at $10 per tonne less than the elevator price. Table 5-15 Average Barley Prices 1993 to 2004 AAFC Price from Elevator Price Direct from Producer $/tonne $/bu $/tonne Calgary Saskatoon Winnipeg PEI ( ) POTATOES Potatoes have a starch content of about 80% on a dry matter basis (16% on an as produced basis) and that starch could be converted to ethanol. In the United States, J.R. Simplot has produced ethanol from the cull potatoes and potato waste at two plants in Idaho for many 61

92 years, although one of the plants was recently closed due to decreasing amounts of feedstock. These plants were quite small, producing about 8 million litres per year each Potato Production Potatoes are produced in most regions of Canada as shown in the following table (Statistics Canada, 2004). Potato production is significantly lower than the production of corn, wheat and barley. The total Canadian potato crop would only produce about 500 million litres per year (ethanol yield is 525 litres/dry tonne). Table 5-16 Potato Production Three Year Average Tonnes Tonnes Tonnes Tonnes Canada 843, ,871 1,068, ,960 Newfoundland 871 1,043 1,361 1,091 PEI 166, , , ,367 Nova Scotia 7,075 10,975 10,141 9,397 New Brunswick 130, , , ,966 Quebec 95,864 91, ,980 97,400 Ontario 71,819 63,166 81,633 72,206 Manitoba 158, , , ,837 Saskatchewan 27,338 32,317 37,143 32,266 Alberta 163, , , ,673 British Columbia 21,841 22,884 23,546 22,757 Potatoes have a very high water content, which makes them an ideal growth medium for other organisms and results in shorter practical storage times and higher spoilage rates than cereal grains. A substantial portion of the crop is lost to pests, diseases, and storage problems. The cullage and loss data for Prince Edward Island is shown in the following table (Cousins). The production data in this table is presented on a wet basis. 62

93 Table 5-17 PEI Potato Production And Cullage Year Production (Cwt) Cullage/Loss (Cwt) Cullage/Loss (%) ,629,073 4,435, ,213,883 3,515, ,592,361 3,675, ,919,210 3,497, ,083,365 3,471, ,518,320 2,353, ,650,581 2,947, ,964,950 2,682, ,600,424 4,692, ,444,915 3,110, ,412,782 2,990, ,208,723 3,912, A Royal Commission on the Prince Edward Island Potato Industry concluded that cullage was higher than in other potato-growing regions partly because of a lack of processing alternatives beyond the french fry market. However, in the subsequent decade, the processing industry has expanded, but cullage rates have not changed drastically since the Royal Commission Report. The culled potatoes are currently fed to cattle in many regions of Canada. In some cases, potato producers keep their own cattle; more often, culls are shipped to beef (and sometimes dairy) farms for a cost to the cattle farmer of little more than the price of shipping. Feedlots can account for a large portion of potato cullage in any given year. This system of cull disposal is an economic drain on potato producers, for whom cullage represents almost a dead loss. On the other hand, the supply of cull potatoes is one of the elements that makes the cattle sector a viable industry in some locations such as PEI, particularly in view of high prices for other feed sources. Cousins suggested that the PEI beef industry, valued at about $30 million and 15 percent of farm cash receipts, might not survive without the cull potato supply. Potatoes are likely a potential ethanol feedstock only in New Brunswick and PEI where other feedstocks are limited. In other provinces, the volume of cull potatoes available is too low in proportion to the ethanol demand to be a significant resource. Assuming a 10% cull rate, the ethanol production potential from cull potatoes is 12 million litres per year in PEI and 7 million litres per year in New Brunswick. These are very small plants and the diversion of the cull potatoes to ethanol production would have an impact on the cattle and dairy industries in these provinces. Cull potatoes are not available on a year round basis and ethanol plants would have to have a dual feedstock capability or sit idle for half of the year. Seasonal ethanol supply would be problematic for petroleum marketers. It is assumed that one half of the potato culls from these two provinces could be converted to ethanol Potato Prices Potato prices are high relative to cereal grains. The potato prices for each province for 2001 and 2002 are shown in the following table. The prices are presented on a dollars per dry tonne basis for ease of comparison to cereal grains. 63

94 Table 5-18 Potato Prices Per dry tonne Per dry tonne Canada $1,163 $1,064 Newfoundland $1,747 $1,999 PEI $1,160 $850 Nova Scotia $1,066 $1,118 New Brunswick $1,197 $892 Quebec $1,283 $1,182 Ontario $1,317 $1,536 Manitoba $921 $900 Saskatchewan $2,036 $1,961 Alberta $959 $1,069 British Columbia $2,262 $2,911 The feedstock cost for ethanol would be around $2.00 per litre if the plant had to pay these prices. As mentioned above it is more likely that only cull potatoes would be used for ethanol production and these can be obtained for the cost of transportation. There would be some protein co-product produced from the processing of potatoes for ethanol. The material could have protein levels of 55 to 60% based on the protein content of the potatoes, which would command a high price, but the yield would only be about 20% of the dry potato weight. The combined impact of the high price but lower volume would result in co-product credits per tonne similar to that received for cereal grains. 5.5 STARCH ETHANOL FEEDSTOCK SUMMARY The potential starch ethanol feedstocks are summarized and compared to the potential demand for ethanol on a regional basis in this section. The potential regional demand for ethanol is calculated from the gasoline demand and the assumption that 35% of the gasoline contains 10% ethanol. The results are shown in the following table. Even with the relatively conservative assumptions for wheat and barley export diversions there is 50% more feedstock available that is required to meet the target. As an ethanol market develops, more feedstock may be diverted from exports, particularly if there is some variety switching that occurs resulting in the capacity to produce even more ethanol. In regions that are heavily dependent on a single crop, such as potatoes in the Maritimes an increased demand for cereal grains may provide more opportunities for crop rotation and increase the diversity of agriculture. Note that in the following table the supply and demand are rarely in balance within single provinces. This highlights the important role that inter-provincial trade will play in achieving the targeted volumes. 64

95 Table 5-19 Comparison of Feedstock Supply and Ethanol Demand Ethanol Demand Corn Wheat Barley Potatoes Total Supply million L million L million L million L million L million L British Columbia Alberta Saskatchewan Manitoba Ontario Quebec New Brunswick Nova Scotia Prince Edward Island Newfoundland Yukon North-West Territories Nunavut Canada 1, , , CORN STOVER Corn stover is the dried stalks and leaves of a cereal plant after the cereal has been harvested. It can be left in the field or is sometimes used as part of an animal feed ration. There has been considerable work done on the potential of corn stover as an ethanol feedstock in the United States. The material that is left in the field mostly decays to produce carbon dioxide and a small amount (11-19%, Glassner) increases soil carbon content Corn Stover Production Corn stover is produced in equal mass to the grain corn harvested (Biocap, 2003). Like starch ethanol plants, lignocellulosic plants must be of a large scale to achieve the necessary economies of scale. This means that only Ontario and Quebec are potential sites for a lignocellulosic plant using corn stover. The maximum corn stover production potential is therefore 3 million tonnes per year in Quebec and 5 million tonnes per year in Ontario. Biocap reported 8.3 million tonnes for all of Canada for the year 2001 based on the total corn production. Not all of the production is available for energy use. Some of the material must be left in the fields for soil protection and sustainability and not all of the material is recoverable due to difficulties with harvesting. Finally, some crop residues may already be utilized for nonenergy applications. In the case of corn stover, essentially none is currently being utilized so no discounting of the volume is required for current applications. Biocap assumed an 80% sustainable removal rate and a 50% recoverable rate due primarily to complications of the late harvest. The net available corn stover residue for Canada is therefore 40% of the 65

96 production or 3.2 million tonnes. Of the total, 1.2 million tonnes is in Quebec and 2.0 million tonnes is in Ontario. These are estimates since there is very little experience with corn stover recovery in Canada. In the United States, there has been more interest in this feedstock and more work undertaken to better understand the resource. NREL (2002b) has been involved in some life cycle assessment work studying soil carbon changes and the impact of stover removal in Iowa. The stover removal rate and the impact on soil carbon is a function of the tillage practices as shown in the following figure. In this work, it was found that 30 to 50% of the stover, depending on the tillage practices had to remain in the field to maintain soil organic carbon levels. Figure 5-13 Soil Carbon Content vs. Corn Stover Removal Rates Other work in the United States (Sokhansanj, et al) have based their assessment on only 25% of the stover being available for fuel ethanol production. Based on these US assessments the Biocap estimates of corn stover availability may be high, particularly with the late harvest issues that face Canada that are not as significant in the US Corn Stover Price The price of corn stover can only be estimated since the product is not sold commercially in Canada or the United States. Sokhansanj et al estimated the collection and removal costs for corn stover in the United States. They calculated a baseline value of $30/tonne (US$) with a range of $23 to $45/tonne. The baseline case consisted of shredding and raking in one operation, round baling [580 dry kg (1270 dry lb)], transporting from the field to an intermediate storage facility 8 km (5 miles) away using a bale wagon pulled by a tractor, and stacking the bales 5 high under a shed using a telescopic handler. The costs did not include any payment to the producer or the transportation costs to the ethanol plant. Corn stover has some nutrient content that is returned to the soil when it is allowed to decompose. The value of these nutrients is approximately $10/ton (US$) (Iowa State). 66

97 The producer is likely to want some profit for his efforts in removing the corn stover even though there are some benefits from doing so. In the United States, it has been estimated that the corn stover would be available for less than $50/ton (US$) at an ethanol plant (Glassner). This would be composed of $27 for the harvesting and baling, $10 for the nutrients and the other $13 for transportation and profit. The value in Canadian dollars per metric tonne would be $75/tonne. This is relatively expensive feedstock compared to some of the other sources of lignocellulosic materials. 5.7 WHEAT AND BARLEY STRAW Cereal grain straw is one of the feedstocks of interest for producing ethanol from lignocellulosic materials. In Canada, the Prairie Provinces are potential major suppliers of straw for biofuel production. Available estimates of wheat and barley straw for each of the Prairie Provinces are presented in the sections below. These estimates are typically generated by theoretical models and are subject to change as new findings become available from on-going research Straw Supply Straw production is dependent on factors such as the crop grown, soil type and weather. Estimates of straw production are typically calculated from average grain production and straw to grain ratios. For wheat, the straw to grain ratio ranges from 1.3 under average weather conditions (BIOCAP, 2003) to a reported high of 3.1 for black soil zone (AAFRD, 1996). For other crops, including barley, the reported straw to grain ratio ranges from an average of 1 to a high of 1.4 (BIOCAP, 2003). To arrive at the surplus straw that is potentially available for biofuel production, the total straw production estimated above needs to be reduced by the amounts attributable to chaff, stubble, soil conservation requirements, cattle use and current competing industrial uses. The reported amount of straw needed to satisfy soil conservation requirement ranges from 750 kg/ha for reduced tillage to 1,500 kg/ha for conventional tillage. For cattle use, the daily needs for bedding and feed have been estimated at 2.5 kg and 7.5 kg, respectively (Kraft, 1995 and Townley-Smith, 2004). For the livestock industry, there is a general preference for barley straw over wheat straw. Another issue that needs to be considered is sustainability requirement. Data is currently lacking on this issue but some are suggesting a very conservative straw removal rate of once every four years be used (Stumborg, 2004). Straw is not a large source of farm income at the present time so there is little actual data available on actual production and use. Estimates have been made by Agriculture and Agri- Food Canada and by some of the agriculture departments of the Prairie Provinces. Not surprisingly, there is some variation in the estimates. Manitoba Agriculture & Food (MAF) has prepared estimates of straw supply from each quarter section (160 acres) of land within the twelve crop districts in Manitoba (MAF, 2000). Straw production was estimated from historical grain production data ( ) and straw to grain ratio correlations that were developed by Agriculture and Agri-Food Canada (AAFC). Based on an assumed crop cutting height of 20 cm (8 inches), harvested straw was estimated to be 63% of total straw produced for wheat as well as barley. Although published literature has generally suggested that quantities of 750 to 1,500 kg/ha of straw are required to meet soil conservation requirements, MAF adopted the assumption that when cutting to the 20 cm height sufficient straw is generally left standing in the field after the removal of baled straw. 67

98 In Manitoba, about 1,015,600 tonnes of straw is required annually to meet cattle needs for feed and bedding. Barley and wheat straw account for 80% (812,500 tonnes) and 20% (203,100 tonnes) of the total, respectively. Over 93% of barley straw is dedicated to livestock use (BIOCAP, 2003) and therefore very little is expected to be available for other uses. After accounting for cattle and conservation needs, an average of 2.6 million tonnes/y of wheat straw is available provincially for industrial use after cattle needs are met. When compared to the available wheat straw estimate from AAFC, the MAF estimate is of the same order of magnitude as the AAFC value of 2.8 million tonnes, which represents the high end of the range of AAFC estimates (Townley-Smith, 2002). Currently there are 2 known industrial users of wheat straw in the Manitoba. DowBioProducts at Elie, formerly Isobord Enterprises, uses about 186,000 tonnes/y of wheat straw from its surrounding area to produce board products (MAF, 2003). About 5,000 tonnes/y is consumed by Erosion Control Blanket at Riverton (Myrowich, 2004). After accounting for the above industrial uses, the remaining available wheat straw amounts to an average of 2.4 million tonnes/y. Agriculture and Agri-Food Canada has established available straw estimates for Saskatchewan based on long-term average crop yields, straw to grain ratios, soil conservation and livestock requirements (Townley-Smith, 2002). After accounting for cattle requirements, the range of estimated available wheat straw quantities varies from 3.6 million tonnes/y under conventional tillage to 5.1 million tonnes/y under conservation tillage. A review of 1991, 1996 and 2001 Census of Agriculture data indicated that the percentage of land being conventionally tilled has decreased from 64% in 1991 to 32% in 2001 provincially. By proportioning the AAFC wheat straw estimates based on the 2001 Census tillage data, wheat straw is estimated to be about 4.6 million tonnes/y for Saskatchewan. Using the same approach, barley straw is estimated at 1.4 million tonnes/y. AAFC has indicated that these estimates are expected to be at the high end of its estimates since sustainability of straw harvest has not been considered. The AAFC is currently reviewing and refining its estimates of surplus straw due to recent changes in straw to grain ratios and updated soil base maps. In addition, the AAFC has also initiated a research program to investigate the issues of soil specific residue requirements and sustainable straw yields (Townley-Smith, 2004). New AAFC research findings may result in changes to the above straw estimates for Saskatchewan. Parkland Strawboard plant in Kamsack was commissioned in 2002 and was designed to process wheat straw into strawboard for use in the construction and furniture industry. However, the company was under bankruptcy proceedings by December 2002 (Saskatchewan Government Growth Fund Ltd., 2004). A literature search did not reveal any other Saskatchewan industries that are currently consumers of wheat straw. Based on historical analysis, surplus crop straw quantities for Alberta have been estimated by the Alberta Agriculture, Food & Rural Development (Spiess, 2003). The estimates for soil conservation requirements and cattle use are not broken down by straw type of 3.5 million tonnes (in 2001). In 1998, there were four companies that had announced plans to utilize wheat straw for strawboard manufacturing in Alberta, including Agrafibre, Compak, Alta Goldboard and Fieldboard International (AAFRD, 1998). However, it is not clear if any of these plants are in operation currently. The straw supply and demand situation for each of the provinces is summarized in the following table. For Alberta the conservation requirements and the animal use has been prorated according to total straw production. 68

99 Table 5-20 Straw Summary Manitoba Saskatchewan Alberta Total Wheat Straw 4,517,000 12,603,000 8,223,000 25,343,000 Production Soil Conservation 1,671,000 7,325,000 ~2,990,000 11,986,000 Requirement Animal use 203, ,000 ~2,000,000 2,874,000 Industrial Use 191, ,000 Available Supply 2,452,000 4,607,000 3,233,000 10,292,000 Barley Straw 1,387,000 3,535,000 5,322,000 10,244,000 Production Soil Conservation 513,000 1,507,000 ~1,837,000 3,857,000 Requirement Animal use 812, ,000 ~1,500,000 2,911,500 Industrial Use Available Supply 61,500 1,429,000 1,985,000 3,475,500 Wheat and Barley Available Supply 2,513,500 6,036,000 5,218,000 13,767,500 The total wheat and barley straw production is in excess of 35 million tonnes per year but the soil conservation requirements are on the order of 16 million tonnes per year. There is some uncertainty about this number and the various government organizations that have looked at the issue have taken different approaches to determining the requirement. The type of tillage practiced does have an impact on the straw requirement with low tillage methods requiring less straw for conservation. The trend in Western Canada is for increased use of low or no till systems so the trend should also be towards reduced straw requirements for soil conservation. The values in the previous table are also averages over all soil types and tillage methods. Lighter soils will require less straw removal and heavy soils will allow for higher straw production and possibly more frequently. The ability to remove straw will also be influenced by the crop rotation and straw should not be removed when the following year is planned for summerfallow, pulse crops or other crops that produce low amounts of residue. As noted earlier some are recommending that straw be removed only one year in four to be conservative with respect to sustainability requirements. There is no question that there is still much to be learned about producing large amounts of straw as a crop. The reality is that it will take some time to develop a market for millions of tonnes of straw per year and much will be learned in the development of the first markets for lignocellulosic ethanol. In the assessment of wheat and barley cereals for ethanol production 20% of the exports were considered a reasonable level of diversion from the export market to the domestic market. For the straw, there is no market for the surplus material at present so the 20% diversion rate is probably too low. On the other hand, not all of the straw is likely to be collected for a variety of reasons. It may be that 20% of the 13.7 million tonnes of straw is not economically collectable. Given all of the uncertainty regarding sustainability requirements, the producers response to a large market for straw the best that can be said is that somewhere between 3.4 million tonnes and 11 million tonnes of straw is potentially available for ethanol production. This would be expected to produce from 1 to 3.6 billion litres of ethanol per year. 69

100 5.7.2 Straw Price Straw is bought and sold for industrial uses and animal feeding and bedding in many areas of western Canada. Prices change with supply and demand. In 2004, prices from $22 to $45/tonne have been posted on the forage web sites operated by the provincial agriculture departments. Increased demand for straw for biofuel production will likely move prices higher than they have historically been. Stumborg (2003) suggested that straw should be available in western Canada for $50/tonne. The cost build-up is shown in the following table. Some producers may be willing to accept lower profit margins and sell straw for less than $50/tonne. Table 5-21 Straw Cost Build-up Component Cost $/tonne Percentage Collection Loading Transport Nutrient replacement Profit Total HAY The agriculture residues such as straw and corn stover are the primary feedstocks that the most advanced cellulosic ethanol developers are focusing on in Canada and the United States. There are other potential sources of cellulosic feedstocks that a few developers are considering or could be considered as having secondary supply potential. These include wood residues, either from mills or from the forests or crops such as hay. These other sources are discussed here but are not expected to be significant resources for ethanol production in the near future but they could become important in the medium term if an industry develops in Canada. Some 6 to 7 million hectares of farmland is used to produce 20 to 25 million tonnes of Tame Hay or forage in Canada each year. The main components of Tame Hay are Timothy Hay, Alfalfa and mixed hay (usually a combination of hay and a legume such as clover or alfalfa). Tame Hay is used as animal feed in Canada and some is exported to the United States and the Far East. Hay is a perennial crop so understanding its production and use patterns could be helpful in understanding how other grasses such as switchgrass (which has been considered as an ethanol feedstock by some developers) could be produced Hay Production Forages in Canada are harvested from May through October, depending on the region and the species being harvested. In most areas, export destined hay is cut at the optimum time as determined by destination and individual customer preferences. It is allowed to field dry under natural sunlight and wind conditions. Some processors use dehydration drums to dry the long fibre forage for processing and eliminate the weather risk associated with field drying. The hay is then baled and stacked under a protective cover usually a shed or tarpaulin covering. The hay is allowed to go through another curing period in storage. During this time, 70

101 it will finish curing and then be available for export. Hay production is found in all regions of Canada. The production for 2003 is shown in the following table (Statistics Canada, 2003b). Table 5-22 Tame Hay Production Area Harvested Yield Production 1,000 ha Tonnes/ha 1,000 tonnes British Columbia ,270.1 Alberta 2, ,395.7 Saskatchewan 1, ,676.2 Manitoba ,131.9 Ontario ,125.6 Quebec ,475.4 New Brunswick Nova Scotia Prince Edward Island Newfoundland Canada 7, ,335.9 The characteristics of Timothy Hay and Alfalfa are shown in the following table. Alfalfa has too high a protein content to be used for feedstock for a cellulosic ethanol plant but the Timothy Hay would probably be an acceptable feedstock. Table 5-23 Hay Characteristics Timothy Hay Alfalfa As Fed As Fed Moisture, % Crude Protein, % Calcium, % Phosphorous, % Potassium, % Acid Detergent Fibre, % Neutral Detergent Fibre, % Forage exports tend to be the higher value alfalfa product rather than the low protein hay or grasses. Forage exports range from 500,000 to 800,000 tonnes per year. It is unlikely that any of this material would be diverted from the export market to produce ethanol since the value is too high. Recent export data is shown in the following table (Agriculture and Agri- Food Canada, 2004c). Table 5-24 Forage Exports 1,000 tonnes $1,000 $/tonne , , , , ,

102 Biocap estimated that 5% of the Tame Hay production goes unutilized each year. While this may be true, it is unlikely that any overproduction would occur in the same region each year and thus be available for commercial energy production. In addition to the 7.2 million ha of farm land used for Tame Hay production Canada also has as much as 15 million ha of land classified as natural pasture. If the demand is there and prices support it, some of this land may become actively managed to produce larger amounts of hay or natural grasses and become a potential source of feedstock for cellulose ethanol plants Hay Price The price of Tame Hay will fluctuate with local supply and demand conditions. The Saskatchewan Department of Agriculture, Food and Rural Revitalization has published a guide to forage production. The production cost of Tame Hay varies from $43 to $48/tonne depending on the soil type in the province. In Alberta in 2003, Tame Hay was being sold for $60/tonne. Manitoba Agriculture has published the historical price of Tame Hay as shown in the following figure. Figure 5-14 Manitoba Tame Hay Prices While Tame Hay is not likely, to be the first choice as a feedstock for cellulosic ethanol plant operators the large volumes produced and the price received for the material is likely to establish a ceiling on straw prices. If straw prices rise above the price of hay then some producers may look to supply Timothy Hay or consider one of the other potential perennial 72

103 grasses such as switchgrass as a crop for ethanol production. Higher hay prices in the longer term could result in some of the unimproved pasture in Canada (as much as 15 million ha) being actively managed for forage production and balance the supply against an increased demand. 5.9 WOOD RESIDUES Wood residues are another source of lignocellulosic feedstocks. These residues can be produced at manufacturing sites such as sawmills and pulpmills or they can be produced in the forests. The technology for converting wood residues into ethanol is not as advanced as it is for converting agricultural residues to ethanol. The information on wood residue production and possible un-utilized surpluses is presented in this section although the data is not carried through to the summary section because of the lack of near commercial technologies for the conversion to ethanol Wood Residue Production The Biocap biomass inventory relies on data from a report by Hatton prepared in This is still the most current and comprehensive national inventory available. The summary of that data is shown in the following table. The wood residues consist of both bark and whitewood. The proportions are roughly equal between the two in most regions. Table 5-25 Wood Residue Production and Surpluses Production Utilization Surplus Distribution of Province/Country Surplus Million tonnes Million tonnes Million tonnes Million tonnes British Columbia % Alberta % Saskatchewan % Manitoba % Ontario % Québec % New Brunswick % Nova Scotia % Prince Edward Island n/a n/a n/a -- Newfoundland % Canada % Wood residue utilization has continued to improve in the five years since the Hatton report was prepared. It is likely that less than five million tonnes is currently available. Given that the ethanol plant requirements are likely in the order of 500,000 tonnes of whitewood per plant per year, ethanol plants using wood residues would only be feasible in BC and Quebec. None of the other provinces would have sufficient feedstock resources available. Even in these two provinces, there may be significant transportation requirements to assemble sufficient feedstock in one location. Some developers are considering smaller plants that would produce not only ethanol but also lignin that could be targeted at high value markets. These plants would be better suited to the available supply of wood residues. 73

104 In other parts of the world wood residues are also produced from the small branches that are not suitable for wood or pulp production. In other regions the forests are being actively thinned and fallen branches removed in order to reduce the risk of forest fires. Both of these practices would lead to a significant increase in the quantity of wood residues that would be available for energy production should the practices be applied in Canada. Estimates of the quantities of this material have been made by Biocap (2003) and Levelton using similar but slightly different methodology. The estimates ranged from 20 to 22 million tonnes per year of tops and branches as shown in the following table. Table 5-26 Forest Based Biomass Residues Province/Country Biocap Levelton 1,000 tonnes 1,000 tonnes British Columbia 8,168 6,134 Alberta 2, Saskatchewan Manitoba Ontario 3,671 3,976 Québec 3,780 5,421 New Brunswick 486 1,864 Nova Scotia Prince Edward Island Newfoundland Yukon 540 North West Territories 744 Canada 21,831 19, Wood Residue Prices The surplus wood residue is currently disposed of mostly through combustion with no energy recovery. This costs the disposer the capital and operating costs of the combustion system and thus the wood residues have a negative value for the mills. Nevertheless, most mills are only willing to commit to the supply of the material if there are compensated for it. In most locations, the mill residues are currently available for about $10 per tonne. Forest residues will be more expensive to collect, process, and transport than mill residues. This material is not being collected commercially in Canada but there is starting to be some discussion and investigation into the concept. The collection and processing of forest residues is now being practiced in Finland as that country has plans to increase the use of bioenergy. The cost of the material is dependent on the technology employed, transportation distances and how much of the material is removed from the forests. The cost of chips from forest residue and forest thinning in Finland is 30 to 50% higher than the cost of mill residues but there is an expectation that costs will be reduced as more experience is gained with the systems LIGNOCELLULOSIC ETHANOL FEEDSTOCK SUMMARY The potential availability of lignocellulosic feedstocks for ethanol production is summarized in the following table. The data from the previous tables on lignocellulosic feedstocks has been filtered so that only those provinces with more than 500,000 tonnes of a particular feedstock 74

105 have been carried through to the summary table. Volumes of feedstock less than this are not likely to be economic. The low end of the range of straw availability is used for the summary. Table 5-27 Comparison of Lignocellulosic Feedstock Supply and Ethanol Demand Ethanol Demand Corn Stover Straw Wood Residues Forest Residues Total Supply million L million L million L million L million L million L British Columbia ,024 2,704 Alberta ,010 Saskatchewan Manitoba Ontario ,312 1,952 Quebec ,789 2,713 New Brunswick Nova Scotia Prince Edward Island Newfoundland Yukon North-West 0 Territories Nunavut Canada 1,473 1,024 1,130 1,520 6,340 11,487 Of all of these materials, the wood residues are the only materials that are currently collected. Much of this material is bark and the residues are composed of both softwoods and hardwoods. The technology required to convert the material to ethanol is still being developed and is several years behind the technology used to convert stover and straw to ethanol. The forest residues face the same issues and more. The material is primarily softwoods and contains bark as well as whitewoods. Very little of this material is currently collected. The most likely feedstocks are straw and corn stover. The quantity of straw available could be as high as four times the quantity shown in the table but not enough information is currently available on the sustainability of continuous removal of cereal straws so a very conservative assumption has been used for the table. 75

106 6. FINANCIAL MODEL INPUT DATA An ethanol financial model has been prepared for this study. The model includes income statements, balance sheets, statements of cash flow and all necessary supporting schedules. The model is flexible in that different corporate structures can be modelled, different debt structures are feasible and it is adaptable to the tax structures in all of the provinces. The model does require the user to input the plant specific details as well as the corporate details. The production cost of ethanol is composed of the capital related costs, the other operating costs and the feedstock costs. Ethanol plants generate revenue from the sales of ethanol, distillers grain, and in some cases carbon dioxide and electricity. The ethanol model is generic in that the same model can be used for starch and cellulosic feedstocks but the user will have to input the appropriate data. The input requirements are discussed below for starch and cellulose plants separately. 6.1 CAPITAL COSTS In the discussion of ethanol success factors earlier Tiffany and Eidman identified capital costs as one of the secondary success factors along with debt levels and interest rates. All three are related and plants with lower capital costs can tolerate higher interest rates and debt levels than more expensive plants. Fuel ethanol from starch or sugar has grown rapidly in the United States and Brazil over the past two decades. In both cases, there have been large reductions in plant capital costs and production costs. In the United States, for example, a 190 million litre per year ethanol plant cost about $150 million US (1980) dollars to build in the early 1980 s. Today a 190 million litre per year plant can be built for about $50 million US (2004) dollars. This reduction in capital cost is a result of learning experiences. There is overwhelming empirical evidence that deploying new technologies in competitive markets leads to technology learning, in which the cost of using a new technology falls and its technical performance improves as sales and operational experience accumulate. The shape of the curves indicates that improvements follow a simple power law. This implies that relative improvements in price and technical performance remain the same over each doubling of cumulative sales or operational experience. In the energy sector, experience curves have been prepared for many electricity production technologies in the European Union and that data is shown in the following figure (IEA 2000). 76

107 Figure 6-1 Renewable Energy Learning Curves Starch Ethanol Over 80 ethanol plants that process grain have been built in the United States over the past twenty years so there has been considerable progress made in reducing plant capital costs. A report published by the US National Renewable Energy Laboratory (NREL, 2000) compared the costs of ethanol production from different feedstocks. This report was prepared jointly with the US Department of Agriculture and examined the capital and operating costs for starch based and lignocellulosic-based plants. This report considered a 95 million litre per year plant and the costs were broken out by plant section as shown in the following table. This was a dry mill plant and did not include utilities production so these costs have been estimated separately. Table 6-1 Capital Cost Estimates for 95 Million Litre/Year Plants by Process Area. Area Million Canadian Dollars Feedstock Handling 3,458,000 Saccharification 3,059,000 Fermentation 6,118,000 Distillation 7,049,000 Solid/syrup separation and drying 13,965,000 Storage/load out 1,995,000 Wastewater treatment 1,330,000 Steam production 2,660,000 Air and water utilities 1,330,000 Total 40,964,000 77

108 NREL reports that plants have been constructed recently for $1.25 to $1.50/annual USG of capacity. This does not include working capital, interest during construction or financing costs. These costs can add 15 to 20% to the total project costs. In the following table, the capital costs of a number of recent plants are summarized. All of these plants are dry mill operations. Most of these plants have been able to exceed their nameplate production capacity in continuous operation but only the nameplate data is used in the table. The early data is from company press information and the more recent data is from the company SEC Filings. In some cases, the plants were not built due to problems raising the financing but fixed price agreements for plant construction were entered into so that data has been used. Project costs include total working capital requirements some of which is financed by the accounts payable, to equalize the data the working capital ratio has been assumed to 1.0 for operating plants with higher ratios. Table 6-2 Capital Costs of Recent US Corn Ethanol Plants Name Location Year Design Size Million USG/yr Capital Cost Million USD $/USG Project Cost Million USD $/USG Chippewa Benson, MN Valley Ethanol Agri-Energy Luverne. MN LLC Exol Albert Lea, MN Ethanol 2000 Bingham Lake, MN. Golden St. Joseph, MO Triangle Dakota Wentworth SD Ethanol Badger State Monroe, Ethanol Wisconsin Great Plains Chancellor, SD Ethanol Golden Grain Mason City Iowa Ethanol Husker Ag Plainview, NE East Kansas Garnett, KS Ethanol Granite Falls Granite Falls, Ethanol MN Illinois River Rochelle, IL Energy Iroquois Rensselaer, IN Bioenergy Little Sioux Marcus, IA Corn Processors Northern Lights Milbank, SD

109 Oregon Trail Ethanol United Wisconsin Grain Processors Western Plains Energy Davenport, NE Freisland, WI Campus, KS NREL reports an exponential scaling factor that they have used to adjust the equipment costs between different plant sizes of This factor can be used within reasonable ranges but it may not be applicable to very large differences in plant sizes. Some of the costs may not scale well such as transportation servicing costs, land costs, etc. The curve fit to the above data as shown in the following figure suggests that the overall plant exponential coefficient is The data points for the smaller plants are older but essentially the same curve results from only using the post 2001 data. Figure 6-2 Impact of Plant Size on Capital Costs Million US$ y = x R 2 = Capacity Million USG The average of the ratio of total project cost to plant capital cost is 1.20 to 1. There does not appear to be any correlation between plant size and the ratio. This plant capital cost data is all for corn ethanol plants built in the United States. It must be adjusted for Canadian construction and for feedstocks other than corn. The KMPG Competitive Alternatives website ranks construction and operating costs for 11 nations and a number of industries. For capital costs for all manufacturing industries, for specialty chemical manufacturers, and for food processors the capital costs in Canada are less than 3% higher than they are in the United States. Consultants Inc. were involved in the development of a detailed cost estimate of an ethanol plant in Canada in 2002 and Over 95% of the plant was competitive bid with 79

110 Canadian suppliers and contractors. Most of the bids received were in line with the low bids received for a similar sized plant in the United States. In some plant areas, Canadian costs were higher and in some cases, the costs were lower. Site and Utility development costs were higher in Canada, although these can vary significantly between sites. Overall, capital costs were 10-15% higher than projected by the above curve. Wheat and barley plants are expected to cost more than corn ethanol plants. This is a function of the lower ethanol yield, which requires more grain to be processed at the front end and more DDG to be processed at the back end of the plant. The costs will not be a function of the difference in yield since the alcohol recovery portion of the plant will be the same size, as will be some of the utilities. It can be expected that a wheat ethanol plant, which requires approximately 8% more feedstock to be processed and produces 15% more DDG will cost 10% more than an equivalent sized corn plant. A barley plant that has to process 23% more grain and produces 50% more DDG can be expected to cost 30% more than a corn plant. The plant capital cost equations that are used in the model are derived from the equation in Figure 6-2 after converting to litres, Canadian dollars and a 10% increase in cost for Canadian conditions are: Corn Capital Cost (Canadian $)=4.12*(Capacity in million litres/3.78) Wheat Capital Cost (Canadian $)=4.53*(Capacity in million litres/3.78) Barley Capital Cost (Canadian $)=5.36*(Capacity in million litres/3.78) The model has the provision for the user to apply an adjustment to capital costs for specific cases. The model also estimates the Provincial Sales Tax that is appropriate for the plant location. All of the plants will require additional capital for financing costs, prepaid costs such as insurance and licenses and working capital for inventories and receivables. The organizational costs are calculated as a user specified percentage of the capital cost and the financing costs are calculated from a user specified percentage of debt. The working capital is calculated from the sum of the accounts receivable, inventory and prepaid accounts in the first quarter of the first year of operation. The interest during construction is calculated through an iterative process based on the interest rates for the construction loan and the sub-debt and an estimated cash flow through the construction period. In most cases, the sum of these factors is close to the 20% of capital costs experienced in the United States. The expected costs for corn ethanol plants of various sizes are shown in the following table. Costs for individual projects will vary due to local conditions. Provincial sales tax would be in addition to these estimates. Table 6-3 Expected Corn Ethanol Plant Costs Plant Size Capital Cost Total Capital Requirements Million Litres Million $ Million $ The expected costs for wheat ethanol plants of various sizes are shown in the following table. Provincial sales tax would again be extra. 80

111 Table 6-4 Expected Wheat Ethanol Plant Costs Plant Size Capital Cost Total Capital Requirements Million Litres Million $ Million $ Cellulosic Ethanol There have not been any large scale cellulosic ethanol plants built so the only capital cost data available is from engineering studies. Several studies were published by NREL, the most recent one being June This project determined that the capital cost for a 260 million litre per year plant was $250 million (CDN). Working capital, start-up costs, permits, etc were an additional 15%. In this case, the assumption was that the plant would be 100% equity financed so there was no financing costs or interest charges during construction. It was assumed that this was the n th plant and that some learning had already taken place. If the same power curve applies to cellulosic plants as grain plants then the capital cost curve for lignocellulosic plants would be: Lignocellulosic Capital Cost (Canadian $)=9.5*(Capacity in million litres/3.78) The initial plants will cost more than this. Iogen have stated that their first plant, which will produce 170 million litres per year will cost $315 million (CDN). This is the total project cost so the capital cost may be $265 million. This would suggest that the cost curve for the first plant would be: Lignocellulosic Capital Cost (Canadian $)=13.8*(Capacity in million litres/3.78) If the typical learning curve were applied to cellulosic ethanol plants then the factor for subsequent plants would decrease as shown in the following table. At the 5 th plant, the Iogen cost would be same as that projected by NREL. Table 6-5 Cellulosic Plant Factors for Subsequent Plants Plant Learning Curve Factor Plant Cost Factor OPERATING COSTS STARCH ETHANOL The operating costs for starch ethanol are well understood and documented. The USDA (2002) undertook a benchmarking study of dry mill operating costs in Some costs have been declining significantly in recent years through plant design improvements and the study 81

112 team had access to operating data from a number of process developers and plant operators. The approach taken here is to provide the USDA value and then provide a recommendation for a state of the art value based on our dataset. The user can choose the data to be used on the Input Sheet Feedstock The feedstock costs were discussed in section 5 of the report. They can vary depending on location in Canada, time and of course the particular feedstock used. The user must input the feedstock price for each year of the model as well as the yield. Inputting the price for each year allows for the modelling of fluctuating price scenarios. In the following table the yield, average price and price ranges for the feedstocks are shown. Table 6-6 Feedstock Input Data Feedstock Location Yield 10 yr Average Price Range Price Litre/tonne $/tonne $/tonne Corn Ontario Quebec Wheat Alberta Saskatchewan Manitoba Barley Alberta Saskatchewan Manitoba PEI Potatoes PEI New Brunswick Energy Ethanol plants require electricity and heat for the process. This is one area where there has been significant reductions in the amounts required over the years. In the early 1980 s ethanol plants required about 80,000 BTU of thermal energy per USG for the process. By the mid 1990 s this had been reduced to about 45,000 BTU per USG and now some process developers are guaranteeing 34,000 BTU/USG and some plants are operating below this. Similar improvements have been made with electrical power. The USDA survey only provides cost data and not the physical units used. Energy prices vary significantly from state to state so it is not possible to determine an accurate energy consumption value from this data. For a corn ethanol plant, the recommendation for the model is to use 9.8 MJ/litre (35,000 BTU/USG) of ethanol produced. This is slightly above the 34,000 BTU/USG guarantee mentioned above but it allows for higher energy usage during start-ups, shutdowns and cleaning that would not be included in the guarantee. 1 Five year average,

113 Energy consumption for a wheat ethanol plant will be higher than this since there is more wheat to grind and more DDG produced. It will be assumed that the energy consumption is 12% higher than for corn or 11.0 MJ/litre (39,300 BTU/USG). There is much less information available for barley and potato plants. It is assumed that a barley plant will require more energy and 13.5 MJ/litre (48,200 BTU/USG) is recommended for the model. The potato plant should be similar to the corn facility in terms of energy consumption. Some process suppliers are now guaranteeing 0.75 kwh/usg for electrical consumption. The recommendation for the model is 0.24 kwh/litre (0.90 kwh/usg) for corn. This is higher than the guarantee but it allows for all site power and not just process power and it allows for some process interruptions. For a wheat plant the electrical energy consumption is assumed to be 0.27 kwh/litre (1.02 kwh/usg). For a barley plant the power consumption is recommended to be 0.33 kwh/litre (1.24 kwh/usg). The recommended energy consumptions for the financial model are summarized in the following table. Table 6-7 Energy Consumption Recommendations Natural Gas Electricity MJ/litre KWh/litre Corn Wheat Barley Potatoes Energy costs can vary with location and time across Canada. Natural gas prices tend to reflect the prices in Alberta plus the cost of moving the gas from Alberta to the point of use. Alberta natural gas prices are shown in the following figure. Prices have been rising. There is also a long term correlation between natural gas prices and oil prices. One must be careful to ensure that the ethanol selling price scenario is consistent with the natural gas price forecast. The five year average ( ) natural gas price at AECO was $5.27/GJ. 83

114 Figure 6-3 Natural Gas Prices $/GJ AECO Jan-95 Jul-95 Jan-96 Jul-96 Jan-97 Jul-97 Jan-98 Jul-98 Jan-99 Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 The local cost of natural gas distribution is estimated by province in the following table. Transportation tariffs can be complex with a number of components to the final cost. Even within a province, there can be significant differences between locations. An estimate has been made of typical costs to arrive at the values in the table. These costs must be added to the Alberta prices to arrive at the plant cost. Table 6-8 Natural Gas Distribution Costs Province Additional Transportation Cost $/GJ British Columbia 0.90 Alberta 0.0 Saskatchewan 0.25 Manitoba 0.65 Ontario 1.50 Quebec 2.00 Note that the natural gas transportation costs can be significant. $2.00/GJ equates to a cost of 2 /litre of ethanol. This is 40 to 50% of the cost of moving ethanol by rail from the prairies to Ontario or Quebec. Electricity prices vary across Canada. In some markets, prices are regulated and generally uniform in price and in other regions prices are set by the market and are influenced by supply and demand. Electricity prices can range from 3 cents per kwh to over 7 cents/kwh depending on location. Approximate cost for the larger provinces are shown in the following table. 84

115 Table 6-9 Power Costs Province Power Cost Cents/kWh British Columbia 3 Alberta 7 Saskatchewan 4 Manitoba 3 Ontario 5.5 Quebec Labour The labour requirements are a function of plant size. Ethanol plants require some 30 to 40 employees to operate. Plants up to 100 million litres in size should be able to operate with 30 employees. Plants of 200 million litres per year may require 40 employees. The average labour cost is estimated to be $45,000 per employee. Employee benefits are set at 15% of the labour costs. Both of these values can be adjusted on the input sheet. The labour costs are escalated by the user set rate of inflation (financing assumptions sheet). The USDA reported labour costs of 9.6 cents/usg for small plants and 7.1 cents/usg for large plants. These included benefits. This is equivalent to 3.5 to 2.6 cents/litre Canadian. Data from the prospectus and the annual reports of US ethanol companies would suggest that labour costs are lower than the USDA has reported. Thirty employees in a 100 million litre per year plant at the above costs would represent a labour cost of 1.35 cents/litre plus benefits. The larger 200 million litre plant would have labour costs of 0.9 cents/litre plus benefits. Labour costs in Canada are generally lower than in the United States so some savings is expected Chemicals Ethanol plants utilize enzymes, yeasts, acids and bases to convert the starch to ethanol. The USDA reported that enzyme costs were 5.5 cents/usg (2 cents/litre CDN), yeast costs were 1.0 cents per gallon (0.4 cents/litre CDN), and other chemical costs were 2.7 cents per gallon (1 cents/litre CDN). The suppliers of these chemicals are all very competitive and there are new and more effective products continually being introduced to the market place. The result is that costs have declined. It is recommended that for a corn ethanol plant the enzyme cost be 1.65 cents per litre, the yeast cost be 0.35 cents per litre and the cost of other chemicals be 1.0 cents per litre. The total cost of enzymes, yeast and other chemicals is 3.00 cents per litre. Wheat and barley plants may require additional enzymes for maximum effectiveness. For wheat plants, the cost of enzymes should be 2.0 cents per litre and for barley plants the estimated costs are 2.5 cents per litre. The yeast and chemical costs can stay the same. The dosages of enzymes and yeast implied by these costs is higher than that recommended by the suppliers. Very well run plants may be able to reduce their costs by 25 to 35% compared to these values. 85

116 6.2.5 Maintenance The USDA reported maintenance costs of 3.5 cents per USG. Maintenance costs in the model are forecast to be 1% of the original capital cost in year one of operation and increasing linearly to 2% in year 10 of operation. This amounts to a cost of approximately 0.5 cents per litre at the beginning. This is lower than the USDA estimate but it is in line with recent operating experience with US plants. The maintenance factor is the same for all feedstocks but the capital costs per unit of production for wheat and barley is above that of corn so their per unit maintenance costs are also higher Other Other direct costs include the cost of water and waste disposal. The USDA reported costs of 1.0 cent/usg (0.36 cents/litre CDN) for these factors combined. These costs are strongly influenced by the local conditions. Many process developers are moving towards zero process water discharge, which helps to minimize these costs. The USDA figures have been used in the financial model and the costs have been allocated equally between water and waste. The ethanol that is produced must be denatured with gasoline prior to leaving the site. The denaturant must be at least 1 % gasoline. The denaturant volume and cost per litre is entered in the model Administrative Administrative expenses cover costs such as advertising, office supplies, telephone, licenses and memberships, travel, training, professional services, insurance and local taxes. Management costs are also included. The USDA reported these costs as 4.0 cents/usg (1.5 cents/litre CDN). In the model, these costs are set to 1.5 cents per litre for the sum of all admin costs and are not specified separately. 6.3 OPERATING COSTS CELLULOSE ETHANOL Much less is known about the operating costs of lignocellulosic ethanol plants since there are no operating facilities and only engineering studies are available. The most recent report is the 2002 NREL report Feedstock The feedstock cost in the NREL report was $30 (US$)/ dry ton or $25.50 per tonne as received. The equivalent price in Canadian dollars per metric tonne is $39/tonne. Feedstock costs could range from $35 per tonne to over $50/tonne depending on the location and feedstock. The recommended value for the model is $40/tonne. The yield of ethanol from the cellulosic feedstock must also be entered. NREL used a value of 320 litre/tonne Energy Cellulosic ethanol plants have generally been designed to be self sufficient in energy and in fact usually producing some power for sale. 86

117 Any purchased energy can be entered into the model the same way that it is for grain ethanol. Both the per litre energy consumption and the price of the energy must be entered Labour Labour requirements for cellulosic ethanol plants are expected to be higher than for grain plants as the feedstock is somewhat more difficult to process. NREL estimated 76 people for a 260 million litre plant. Iogen have suggested that their first 170 million litre plant may have 100 employees. Labour costs are input as well as the total number of employees Chemicals One of the uncertainties with respect to lignocellulosic ethanol is the cost and quantity of enzymes required. NREL has a goal of reducing the enzyme cost to $0.10 (US$)/USG and is working with Novazyme and Genecor on programs to accomplish this. The latest results from Novazyme suggest that costs are now down to $0.25(US$)/USG. This is about 9.0 cents/litre Can. NREL have estimated the costs of other chemicals at 7.7 cents/(us$)/usg (2.84 cents/litre CDN) Maintenance NREL have estimated the annual maintenance cost at 2% of initial installed capital equipment for year one. This is double the cost for a grain ethanol plant. At year 10 the rate has been increased to 3%. A higher level is warranted considering the increased severity of the processing and the difficulty of solubilizing the feedstock Other Other costs include water and waste disposal costs. NREL estimated these at 2.5 cents(us$)/usg. This is 0.9 cents per litre Can, almost three times those of a grain ethanol plant. The ethanol that is produced must be denatured with gasoline prior to leaving the site. The denaturant must be at least 1 % gasoline. The denaturant volume and cost per litre is entered in the model Administrative Administrative expenses cover costs such as advertising, office supplies, telephone, licenses and memberships, travel, training, professional services, insurance and local taxes. Management costs are also included. NREL reported these costs as 4.4 cents(us$)/usg (1.65 cents/litre CDN). In the financial model, these costs are set by the user. 6.4 REVENUES Ethanol plants receive income from the products that are produced. The actual number of products and the revenue from the products will vary with the individual plant, its feedstock, and plant location. The financial model can handle a wide range of situations. Details of the revenue streams are discussed below. 87

118 6.4.1 Ethanol The ethanol market in Canada has been limited with few buyers and sellers. The transactions have almost always been based on long term contracts with a formula price tied to the rack gasoline price, the value of the various federal (10 cents per litre) and provincial tax incentives (zero to 25 cpl) plus a small discount. The discount reflects the fact that the gasoline is often sold at a discount to the rack and that there may be some additional costs that the marketer may face as a result of using ethanol. The discounts have been in the range of 1.5 to 3.0 cents per litre. Depending on the agreement the cost of transporting the ethanol may be paid by the ethanol producer or by the petroleum marketer. The financial model has been set up to handle each of the components of the price formula as a separate input. The user will input the rack price of gasoline, the federal tax incentive, the provincial tax incentive, the discount level and the freight cost. If some of these items don t apply then a zero is entered in that row. The input data can be set independently for each year in the model. This allows for backcasting and more realistic forecasting scenarios. The historical gasoline rack prices for several locations in Canada are shown in the following figure. It can be seen that gasoline prices are relatively uniform across Canada but that they are quite volatile. The prices have increased in recent years. The average price in the past five years has ranged from 32 to 34 cpl depending on the location. There is also a provision for a selling commission and freight for the ethanol from the plant to the terminal. In the United States, most ethanol plants use a marketer to sell their products and pay that marketer a commission. It is not clear if this trend will extend to Canada but provision has been made in the model to allow for it. Figure 6-4 Gasoline Rack Prices 60 Gasoline Rack Price, cpl Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Edmonton Vancouver Toronto Montreal Ethanol prices in the United States are less closely tied to gasoline prices. There are many more buyers and sellers than in Canada and there is a more active market. The ethanol price 88

119 is influenced not only by the gasoline price and the tax incentives but also by the ethanol supply and demand. Some of the participants in the Canadian ethanol industry expect that a similar situation will eventually exist for ethanol in Canada. The following figure shows the historical ethanol price premium or discount for US ethanol. This has been calculated by adding the Federal and State tax incentives for Nebraska to the gasoline rack price for Nebraska less the ethanol selling price in Nebraska. It is apparent that ethanol has sold at both a discount and a premium relative to gasoline plus tax incentives. Figure 6-5 US Ethanol Prices Relative to Benchmark Prices Cents/US Gallon Jan-82 Jan-83 Jan-84 Jan-85 Jan-86 Jan-87 Jan-88 Jan-89 Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan Nebraska Ethanol-Gasoline-Incentives Co-Products Ethanol plants can produce a variety of co-products depending on the process and the local markets. The co-products make a very important contribution to the overall facility revenue. The contribution can range from 20 to 30% depending on commodity prices. The protein coproducts compete against other sources of protein and the total protein market in North America is quite large and is growing. The protein market is becoming quite sophisticated and is able to differentiate between DDG produced with different feedstocks and even in cases between corn DDG produced in different plants. Lower value co-products such as carbon dioxide and electricity depend more on local markets and these may or may not be available in all locations Distillers Grains Dry mill grain ethanol plants produce distillers grains (DDG), which contain the nonfermentable portion of the feedstock plus spent yeast from the production process. DDG is a used as a source of protein in animal rations. It competes with soybean meal and to a certain extent canola meal in feed rations. 89

120 Ethanol produced in wet milling operations produces corn gluten feed and corn gluten meal whereas ethanol produced in dry milling operations producers distillers grains. Wet milling operations can produce products other than ethanol such as high fructose corn syrup or cornstarch. There is therefore more corn gluten feed and meal produced than just from fuel ethanol production. Wet milling operations dominate the corn grinding industry and until recently have also dominated the ethanol production sector. In recent years, most of the new ethanol plants that have been built have been dry milling plants so distillers grains production have been increasing. In the following figure estimates of distillers grains production and corn gluten meal and feed production is shown (ProExporter). Figure 6-6 Co-product Production 12,000 10,000 1,000 tonnes 8,000 6,000 4,000 2, DDG Corn Gluten Feed and Meal It is important to note that while Distillers Grains production has been increasing it is still much less than the production of gluten feed and meal. Distillers Grains competes not only against corn gluten meal and feed but also against other sources of protein meal. Worldwide, the protein meal supply from all sources is about 210 million tonnes (Agriculture and Agri-Food Canada). Of this total, soymeal contributes about 70%. In the United States, soymeal production has been increasing and is approximately 40 million tons in recent years (USDA, 2003). Over 30 million tons is consumed in the United States in animal feeds. When DDG production is considered relative to world or domestic protein meal production a doubling of DDG production would still not have the production contributing 10% of the domestic protein meal consumption. The US feed market absorbed an additional 10 million tons of soybean meal in the past ten years as well as the increased corn gluten meal and feed shown above. 90

121 Figure 6-7 US Soymeal Supply and Disposition 1,000 Tons 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5, Production Exports Domestic Disappearance Traditionally some DDG has been exported to markets outside of the United States, mostly in Europe. The level of exports has been relatively constant for most of the past decade as shown in the following figure (USDA FATUS). DDG exports now account for about 20% of DDG production and the fraction is decreasing as the production volume increases. Figure 6-8 DDG Exports 900, , ,000 Metric Tonnes 600, , , , , ,

122 The corn gluten feed and meal product has also been traditionally exported. The export data for these two products are shown in the following figure. The amount of the lower protein gluten feed has been slowly increasing while the quantity of the high protein meal has been decreasing in recent years. More than 50% of the combined products have are exported. Figure 6-9 Corn Gluten Feed and Meal Exports Metric Tonnes 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000, CGM Exports CGF Exports DDG production for Canada has been stagnant along with ethanol production. All fuel ethanol production in Canada uses the dry mill process or in one case is combined with a vital wheat gluten operation. Dried distillers grains are produced at three of the five fuel ethanol facilities. One facility uses all of the distillers grains on site for animal feed and the other sells the protein as wheat gluten. The three facilities produce about 140,000 tonnes per year of distillers grains from the fuel ethanol plants. Canada imports and exports distillers grains mostly with the United States. The US exports to Canada of DDG, corn gluten feed and corn gluten meal are shown in the following figure. 92

123 Figure 6-10 US Exports to Canada 120, ,000 80,000 Tonnes 60,000 40,000 20, Gluten Meal DDG Gluten Feed The same commodities are produced in Canada and exported to the United States, that trade data is shown in the following figure. Imports and exports are regional like many commodities in Canada. Exports from Canada typically occur in the east and imports in the west. Figure 6-11 Canadian Exports to the United States 140, , ,000 Tonnes 80,000 60,000 40,000 20, DDG Gluten Feed Gluten Meal 93

124 The net trade in DDG between the two countries is shown in the following figure. It would appear that with relatively constant Canadian production of DDG and net exports to the US declining the Canadian consumption of DDG is increasing. Figure 6-12 Net Canadian DDG Exports 120, ,000 80,000 Tonnes 60,000 40,000 20, Canada Net Exports The Canadian demand for protein supplements for animal feed is met by imports, mainly from the United States. Soybean meal imports for the past ten years are shown in the following figure and the increasing trend is apparent. 94

125 Figure 6-13 Canadian Imports of US Soybean Meal 1,200,000 Soybean Meal Imports from US 1,000, , , , , DDG can not be substituted for soybean meal in all rations directly since each product has different feed characteristics. In some rations, such as dairy, DDG is more attractive because of its higher level of by-pass protein but in other rations soybean meals higher lysine level makes that product the first choice. The key factor is that Canada imports a significant amount of protein meal and at least a portion of those imports could be substituted by domestic DDG production if it was available. There may be a need for an educational program to make feed formulators aware of the benefits of DDG once more DDG becomes available on the market. The price of DDG is primarily a function of the protein content of the material and the location. In the United States, DDG prices tend to be lowest in Minnesota and then generally increase in price as one moves away from this region. This trend is expected to be found in Canada as well, with prices being lowest in Manitoba and increasing as one moves east and west. The increase in price is generally a function of the freight cost to move the product from the producing region to the consuming region. DDG prices for Illinois and for Ontario for corn DDG were shown earlier in section 3 of the report. The DDG price is established on a North American basis and while Canadian production is relatively small the Canadian prices for DDG are determined by the supply and demand factors of the much larger North American market for protein meals. In the financial model the user can input the DDG price for each year of operation, the DDG yield as a percent of the feedstock weight, and the cost of any freight that the ethanol producer is paying for the product. Ethanol plants often use specialist companies to market their DDG and the sales commission paid on these sales can be entered separately as well. The price of DDG is generally a function of its feed energy content and its protein level. DDG s from different grains will therefore have different values in the market place. In the following table, the amount of DDG produced and the relative value to corn DDG is summarized for the grain feedstocks considered here. This production yield must be input by the user for the specific grain being modelled. 95

126 Table 6-10 DDG Assumptions Feedstock DDG Production Factor Relative DDG Value % feedstock weight Relative to corn DDG Corn Wheat Barley Potatoes 28 (dry weight basis) 1.3 The assumptions made about DDG selling prices should be consistent with the assumptions made about feedstock prices. There is not a lot of good public data on DDG selling prices in Canada over a ten year period. For corn DDG, the prices for four years (Jan 2000 to August 2004) suggest that the selling price has been 20% above the price of corn. Fifteen years of experience in Manitoba suggests that wheat DDG sells for 1.68 times the price of wheat. Given the protein content of wheat DDG compared to corn and the relative price of corn and wheat, the wheat DDG is where one would expect it to be. Using these relationships and accounting for transportation costs the estimated corresponding DDG prices are shown in the following table. Table 6-11 DDG Input Data Feedstock Location Average Price $/tonne Corn Ontario 176 Quebec 188 Wheat Alberta 235 Saskatchewan 225 Manitoba 215 Barley Alberta 142 Saskatchewan 132 Manitoba 122 PEI 142 Potatoes PEI 200 New Brunswick 200 It is informative to consider the net feedstock cost impact of corn, wheat and barley. This accounts for the feedstock cost, the co-product value (price and volume) and the ethanol yield. This information for Ontario corn and Saskatchewan wheat and barley is shown in the following table. 10 year average feedstock costs are used. Table 6-12 Net Feedstock Costs Ontario Saskatchewan Saskatchewan Corn Wheat Barley Feedstock cost $/t DDG selling price $/t Ethanol yield, l/t DDG Yield, % Net feedstock cost, $/l

127 Distillers grains can also be sold in a wet form. The wet DG (WDG) usually has a solids content of about 35% and is produced by centrifuging the stillage and processing the thin stillage through an evaporator system. The two streams are usually recombined to produce WDG. WDG has a short storage life of three to ten days depending on temperature and cannot be economically transported long distances because of the high moisture content. The nutritional value is similar to DDG and the plant can save up to one half of its energy requirements compared to a plant producing DDG. The selling price of WDG is highly variable and depends on the local supply and demand situation. In some cases, plants have been able to achieve the same price for WDG as DDG on a dry basis. In these cases, the plant has better economics because of lower energy costs (and lower GHG emissions). In other situations the WDG sells at a discount to DDG and there is no operating economic benefit to WDG (although the plant capital costs are lower). Many plants in the US produce and sell both DDG and WDG and the flexibility of being able to do both allows them to optimize the production costs. Lignocellulosic ethanol plants are not expected to produce any high protein co-products so the production yield should be zero Carbon Dioxide The fermentation of sugar to ethanol also produces almost an equal weight of carbon dioxide. In some markets, it may be possible to market this material to industrial gas companies or directly to end users. There is some capital and operating requirements for capturing and compressing the carbon dioxide. The model assumes that the additional capital and operating cost is borne by the customer and that the ethanol plant is paid for the raw gas. This is the way that most ethanol plants deal with the issue in North America. The quantity of carbon dioxide is calculated automatically by the model based on the assumption that 90% of the produced gas is captured. The user must enter the gas revenue. Carbon dioxide prices can range from $10 to $25/tonne (CDN) depending on the local market conditions and the purity of the raw gas produced. A selling commission can also be applied to these sales if required. Carbon dioxide is produced in both grain ethanol and lignocellulosic ethanol plants Electricity Lignocellulosic ethanol plants will generally produce their own electricity from the combustion of the lignin and they will usually have some excess that they can sell to the power company. The model requires the user to input both the quantity of power sold to the grid and the per unit sales price Other Products Some ethanol plants may extract and sell other valuable co-products. These are handled generically by the model. The user inputs the additional sales revenue per litre of ethanol produced. 97

128 7. BUSINESS STRUCTURES AND INCOME TAXES 7.1 OVERVIEW There are various organization or business structures that a business enterprise can operate within. The most common business structures tend to be corporations, partnerships, limited partnerships, co-operatives or joint ventures. The type of business structure that is utilized in any given situation is determined generally as a result of the nature of the legal relationship the owner(s) wish to have amongst themselves (including the rights and obligations of the various owners), in addition to how the owner(s) prefer to have the income from their investment taxed. The following commentary on business structure matters and taxes should not be considered as an exhaustive assessment of all relevant aspects of each business structure. The commentary is intended only to provide readers with a basic understanding of the differences in business structures as it relates to understanding the differences in the financial statements of various business structures, the nature of the legal relationship with its owners, in addition to how profits earned within the various organizational structures are generally taxed under current Canadian taxation laws. The type of business structure chosen has a direct impact on: how the financial position of the business is reported under Generally Accepted Accounting Principles ( GAAP ), what the legal nature of the relationship between the investor and owners is with the entity in which they have an ownership interest, and how the profits of the business are to be taxed. For example, a corporation is a self contained entity in that its financial statements present all of its assets and/or liabilities in respect of the income earned by the business since earnings are taxed at the corporate level. In addition, all other assets and liabilities of the company are accounted for in the financial statements of the company. The shareholders of the company are considered to have limited liability in that they are generally only liable for the amount of monies that they have contributed in the form of share capital to the company. In the case of partnerships or joint ventures, the income is taxed at the joint venturer or partner level, thus the financial statements for these types of business structures do not report all of the liabilities or assets that the business has in respect of income taxes. Additionally, a partner or joint venture investor does not have limited liability. A partner in a partnership has full liability for any liabilities assumed by its other partners in the ordinary course of business. In the case of a joint venture, a joint venturer is generally liable only for their respective share of the liabilities of the joint venture business. Co-operatives and limited liability partnerships are in many ways a variation of the above business structures. A co-operative will generally operate within a corporate structure, however, it has the ability to allocate earnings to its member shareholders. These allocations are usually referred to as patronage allocations and are considered to be tax deductible to the co-operative entity and taxable as income to the recipients. As the name implies, in a limited liability partnership the limited liability partners are only at risk or liable for the amount of their investment in the specific partnership. A limited liability partnership will have a general partner who is responsible for the management of the business affairs of the partnership and is liable for the liabilities of the business. 98

129 In addition to the basic business structures outlined above, there are numerous variations and complex ownership structures that can be tailored to meet the specific needs of the investors/owners. For example, a corporate partnership is frequently used to limit the liability of a partner(s) where owners/investors do not wish to expose themselves or their other assets to legal claims that might arise from the business being carried on by the partnership. A detailed review of the various alternative business forms that might be structured for a particular situation is beyond the scope of this document. The above review of business structures was intended to highlight the following key points: The form of business structure may affect how a particular business will prepare or present its financial statements and how certain assets, liabilities, revenues and expenses, may be included or excluded from the financial statements. Accordingly, this can affect such items as the comparability of financial ratios amongst different business structures. While the type of the business structure may affect such items as financial ratios, the choice of business structure does not have a significant impact on the underlying economics (i.e. earnings before income taxes and/or cashflows from operations) of the business. Income earned from non-corporate business structures are generally taxed at the investor level. Thus from an investor s perspective, the effect of income taxes and/or capital taxes will be factored into their investment analysis and decision making process even though such taxes will not be accounted for in the financial statements of the business enterprise. Additionally, where such earnings are taxed at the investor level, the investor will ultimately be looking to receive cash distributions from the business enterprise to fund their income tax liabilities. Thus from an economic unit perspective, the cashflows and earnings after taxes are practically identical to that of a totally self-contained corporate entity. The form of business structure may affect the nature of the legal relationship of the business, including its creditors, with the investors/owners of the business. Outlined below are additional factors that are applicable to the more common types of business structures that investors might contemplate. Additionally, pertinent Canadian Federal and Provincial taxation matters are discussed including Provincial sales taxes and related manufacturing and processing incentives where applicable. 7.2 BUSINESS STRUCTURES Corporations Public & Canadian Controlled Private Corporations A corporation is a separate legal entity, distinct from its shareholders. Investors in a company own shares of the company. Whether a shareholder has the right to vote usually depends on the type(s) and number of shares owned. The liability of shareholders is usually limited to the amount invested in the company. Corporations do not allocate its income or losses to investors. Rather, distributions of after tax corporate earnings are made to investors by way of a dividend. The dividend is generally considered to be taxable to the recipient as dividend income. The significance of dividend income is that it is taxed in a manner that considers the fact that a certain amount of taxes have already been paid by the corporation. Corporations are required to pay Canadian federal and provincial income taxes on its net income for tax purposes. Accordingly, the financial statements of a corporation will generally include all assets, liabilities, revenues and expenses pertaining to its income taxes. 99

130 Canadian income taxation makes a distinction between public corporations and what is referred to in the tax legislation as Canadian Controlled Private Corporations ( CCPC s ). A public company is considered to be a corporation that has its shares or other ownership instruments publicly traded, usually on a stock exchange. By comparison, a CCPC generally refers to a company whose shares are not sold on a stock exchange, is not owned directly or indirectly by a company whose shares are sold on a stock exchange, is resident in Canada, incorporated in Canada and is not controlled directly or indirectly by a non-resident. A CCPC is eligible to pay a lower rate of tax on active taxable income below $300,000. From the perspective of a fuel ethanol operation, the tax savings that might be realized by qualifying as a CCPC rather than a public corporation is not significant to the overall economics of the business. An advantage to investing in CCPC s is that the capital gains exemption is available upon the sale of qualifying investments in CCPC s by an individual wherein the first $500,000 of the gain upon the sale of the investment is exempt from tax. To qualify, the shares must fall under the definition of qualified small business corporation shares. This definition requires all or substantially all (generally considered to be 90% or greater) of the assets to be used principally in active business carried on in Canada. The shares must also be held by the individual throughout the 24 month period prior to the disposition and more than 50% of the value of the assets in the corporation must be used in active business throughout the required holding period. There is a lifetime maximum of $500,000 for the capital gains exemption. Both public corporations and CCPC s are liable for large corporations tax and provincial capital tax. This is discussed later Partnerships & Limited Partnerships A partnership is not a separate legal entity from the partners even though it possesses assets and property of its own. It is therefore not a taxable entity in itself and the partners of a partnership are required to report their pro-rata share of income and pay income taxes on that income. Generally, under Canadian laws, a partner in a partnership arrangement is considered to be liable for the debts and/or other liabilities of the partnership operation. However, a limited partnership is a structure whereby the limited partners enjoy limited liability with respect to the partnership's operations. Normally, limited partnerships are used to isolate the risk of each business venturer. However, by law, a limited partner is not allowed any authority in the conduct of the affairs of the partnership. If they do, they lose their limited liability protection. A limited partnership requires that there be at least one general partner who is responsible for the day-to-day affairs of the partnership and who is also liable in the same manner that a partner is in a conventional partnership arrangement. This is a disadvantage when compared to a United States LLC where all investors have limited liability. A limited partnership can allocate losses and earnings to its partners, however for taxation purposes the deduction of losses by a limited partner is limited to their at-risk amount. An investor's "at risk amount" is essentially the partner's adjusted cost base in the partnership plus any capital contributions the limited partner has agreed to pay. This is an advantage when compared to a co-operative corporation or a CCPC, which do not allow for the allocation of losses. Even though a partnership is not a taxable entity, it does compute its taxable income as though it were a separate taxpayer. A partnership has its own fiscal period and the profit and loss for income tax purposes is determined at the partnership level and allocated to each 100

131 partner at the end of the fiscal year of the partnership. The income allocated to each partner retains its original source characteristics, that is, business income, capital gains, dividends, etc. are allocated separately and taxed accordingly. Each partner is then taxed at their applicable personal rates if the partner is an individual, or applicable corporate rates if the partner is a corporation. The partners each hold a partnership interest, which represents their equity in the partnership. All partners are entitled to share equally or unequally in the profits of the partnership regardless of each partner's contribution of capital, labour, management skills and creditworthiness. However, if an unreasonable allocation of income or loss is being made for income tax purposes, the Canada Revenue Agency has the ability to alter the allocations. If a CCPC or a co-operative corporation is a partner in the partnership, any manufacturing and processing income earned inside the partnership and allocated to the corporate partner will be eligible for the manufacturing and processing income tax rate at the corporate level. As well, other incentives offered in various provinces may also flow to the company (discussed under, "Provincial Manufacturing and Processing Incentives and the Provincial capital tax. This is discussed later Joint Ventures A joint venture, similar to a partnership, is not considered a separate legal entity from the coventurers. Similarly, it is not a taxable entity in itself. However, it is different from a partnership in that co-venturers contractually do not have the power to bind other coventurers, co-venturers retain ownership of property used in the undertaking, co-venturers are not jointly and severally liable for debt of the undertaking and co-venturers share gross revenues. A joint venture is a structure where two or more property owners join their assets to pursue a specific project. Upon the termination of the project, the joint venture ceases to exist and each venturer recovers its original property. Joint ventures are normally used in specific limited life projects such as oil & gas ventures, construction projects and real estate. The distinction from a partnership is sometimes fine and one should be careful in setting up the venture not to create a structure, which in law may be considered a partnership. As stated above, as with a partnership, a joint venture is not itself a taxable entity for income tax purposes. However, where a partnership splits net income of the partnership, the coventurers in a joint venture split the revenues derived from the joint venture. From this revenue the joint co-venturer deducts expenses incurred for the purposes of earning that revenue. This may be an important distinction between a partnership and a joint venture. For example, capital cost allowance is calculated at the partnership level. As a result, all partners must agree on the amount the partnership should deduct each year. In a joint venture, capital cost allowance is calculated at the co-venturer level. This allows each co-venturer to independently determine the amount of capital cost allowance to claim. Losses from the joint venture operations, resulting from the agreed to sharing of revenues being less than the agreed to sharing of expenses, are reported by the co-venturers and included in their regular income tax filings. 101

132 7.2.4 Co-operative Corporations A co-operative corporation is a separate legal entity that is distinct from its members. A cooperative corporation is a corporation established for the purpose of marketing, including processing incidental to or connected therewith, natural products belonging to or acquired from its members or customers. It also includes a corporation established for the purposes of purchasing supplies, equipment or household necessaries for or to be sold to its members or customers or of performing services for its members or customers. To qualify as a co-operative, at least 90% of the members must be individuals, other cooperative corporations, or corporations or partnerships that carry on the business of farming. As well, if the co-operative has issued shares, those same persons or partnerships must hold at least 90% of its shares. Generally, all members of a co-operative have only one vote in the conduct of the affairs of the corporation irrespective of the members percentage of ownership interest. The liability of members is usually limited to the amount invested in the co-operative corporation. Payments to members are usually in the form of a patronage allocation. A patronage allocation is an amount paid to members that has been saved by operating in a co-operative form and by performing certain services for its members that the members otherwise would need to have hired outsiders to do for them. The patronage allocation is deductible to the cooperative corporation and taxable to the member. As explained above in the case of a partnership or joint venture arrangement, the income that is allocated and taxed in the hands of the corporate partners or corporate venturers retains its original source characteristics. For example, if the income is earned from a manufacturing and processing operation (which qualifies for reduced taxation rates in a corporate business structure) generally the partners or joint venturers are allowed to report this income as manufacturing and processing earnings and have access to the same preferential rates of income tax as what a corporation would be entitled to for this type of income. It is not clear from the existing tax legislation that this would be the case where a cooperative corporation has earned income from manufacturing and processing activities and has made a patronage allocation to its members. For corporate co-operative members, Canada Revenue Agency has indicated that all relevant facts would have to be examined in order to determine whether the patronage allocation could be taxed as manufacturing and processing income. Thus, it would appear that Canada Revenue Agency would decide this matter on a case by case basis. If profits are not distributed to members in the form of a deductible patronage allocation, the co-operative will pay tax on the income earned by the co-operative. Only profits of a cooperative can be allocated to members. Losses cannot be allocated to members, but can be used by the co-operative to offset prior years or future year s taxable income. This is a significant disadvantage when compared to a Limited Liability Company ( LLC ) currently available in the United States since a LLC is able to allocate profits as well as losses to investors. Generally, a co-operative corporation is liable to pay large corporations tax (discussed later). However, there is the possibility that this type of entity could be exempt from large corporations tax if the principal business of the co-operative is to market, including processing incidental to or connected therewith, natural products belonging to or acquired from its members or customers. A co-operative corporation is generally exempt from provincial capital taxes. 102

133 A co-operative corporation will have access to the manufacturing and processing income tax rates as well as other tax incentives that are available to a Canadian controlled private corporation New Generation Co-operatives A New Generation Co-operative ( NGC ) is similar to a co-operative corporation, however the key difference is that it s membership interest confers a right and obligation upon the holder. The membership holder will generally have both the right and obligation to supply a specified amount of raw materials (i.e. feedstocks in the case of an ethanol operation) to the NGC and the NGC has the obligation to take delivery of the raw materials. This helps to secure the supply of the necessary raw materials for the co-operative while offering the producer a guaranteed market for their product. Several provinces have enacted legislation specific to NGC s to enhance agriculture and agricultural support initiatives. Typically NGC s are seen as positioning primary producers with the opportunity to share in additional profits from the further value added processing of their products. NGCs have been prevalent in the U.S. for a number of years and tend to be business models that tie primary agricultural producers to value added processing enterprises. Despite the fact that the NGC model is prevalent within the U.S. and closely parallels the LLC model that has been observed to be used in many of the Northern states for ethanol production, Canada has relatively few NGC s. The authors are not aware of any apparent reasons for why there are so few NGC s in Canada Limited Liability Corporations A Limited Liability Corporation ( LLC ) is not an organizational structure that is presently available in Canada under existing legislation, however a brief discussion may be both relevant and of interest when one considers what alternative business structures might be contemplated to stimulate the development of the Canadian ethanol industry. When one looks at the information provided in Section 2 in respect of ethanol plants that have recently been constructed in the United States, approximately 66% of the entities were organized as LLC s. In total, the plants organized as LLC s accounted for approximately 67% of the new ethanol production capacity to come on stream. It should be noted that these percentages are in all likelihood understated as it has been observed that in some cases the new entity will initially be organized as a partnership or regular corporation and will be reorganized into a LLC at a later date. A LLC is similar to a limited partnership and is also similar to a New Generation Cooperative. The similarities to the limited partnership are two fold in that limited liability is available and also in that income and losses can be passed through to its owners if the LLC chooses to be classified as a partnership. However, an advantage of a LLC over a limited partnership is that all investors will have limited liability, not just the limited partners as with a limited partnership currently available in Canada. The LLC is similar to a New Generation Co-operative in that owners are called members, and ownership of a membership in the LLC can include the right and obligations features for both the member as well as the LLC that exist as discussed earlier for New Generation Co-operatives. Another advantage of a LLC over a co-operative corporation, a CCPC and a limited partnership is that for United States federal income tax purposes it can be classified as a sole proprietorship, partnership or corporation. However, once the classification is chosen, it generally cannot be changed for the next 60 months. How a LLC is classified will not affect each member's limited liability. This allows a LLC to chose to be classified as a partnership 103

134 for the first 60 months while the entity may have start up losses, and then after the first 60 months, change its classification to a corporation which will allow it access to corporate tax rates on profits. In the US, a LLC is eligible for the small producer ethanol tax credit whereas a co-operative is not. This has driven some co-operatives to reorganize as an LLC. Members of an LLC generally can be individuals, corporations, other LLC s and foreign entities. If the LLC has operating losses allocated to members, the amount of the loss an investor can deduct may be limited Income Trusts An income trust may be used when a company is going public as an intermediary between the corporation and the investors. Generally, individual investors invest in the income trust, which owns the shares in the corporation. By using an income trust between the public investors and the operating corporation, the corporation may be able to reduce or eliminate corporate tax at the operating level and pass on the savings in the form of higher distributions to investors. This is achieved by having the company being indebted to the income trust resulting in any interest incurred by the corporation flowing to the income trust. The company gets a deduction for the interest expense, and the interest earned inside the trust is distributed to the unit holders. If all the income earned inside the trust is distributed to the unit holder, the income trust will pay no tax. Therefore, the company gets a deduction for the interest, and assuming the investors are individuals, tax would only be paid at one level, the individual investor level, resulting in less overall tax being paid. Using an income trust allows the investors to retain many of the non-tax advantages of the corporate form such as limited liability but also avoid certain tax disadvantages associated with the corporate form such as the possibility of double taxation. The disadvantage to using an income trust is the additional costs. For example, the income trust must be established and administered, two sets of financial statements must be prepared and audited and other requirements of an income trust must be monitored Nova Scotia Unlimited Liability Companies A Nova Scotia Unlimited Liability Company ( NSULC ) is a company incorporated under the laws of the Nova Scotia Companies Act. Members of a NSULC have unlimited liability for the obligations of the company. However, unlike members of a general partnership, the members of an unlimited liability company have no direct liability to creditors of the company. The members' responsibility arises only on the winding up of the unlimited liability company. If the assets of the company are insufficient to satisfy its obligations then the members of the NSULC become liable. A NSULC is taxed as a corporation in Canada. For purposes of United States tax, it may be taxed as a partnership if the company chooses to be taxed as such and it qualifies to do so in the United States. Therefore, the use of a NSULC enables an investor to create an entity that is a corporation for Canadian tax, but a flow-through entity for United States tax purposes. A NSULC may not the best structure to use for investment in ethanol in Canada; however, it may be an appropriate structure for an investor from the United States to hold its investment through. 104

135 7.3 INCOME, CAPITAL AND SALES TAXES Federal and Provincial Income Taxes This section provides information regarding federal and provincial income tax considerations applicable under current legislation. The comments that follow are not intended to address all income tax aspects of related to ethanol operations. Readers are cautioned that the following analysis is based upon current tax legislation and that this legislation is continuously amended and changed. For the purposes of this report and due to the nature of the business of ethanol production, we are illustrating the manufacturing and processing corporate tax rates. If a company has qualifying manufacturing and processing profits, it is entitled to have its income taxed as manufacturing and processing income, which is effectively taxed at rates that are less than the general corporate tax rate. Federal and Provincial governments have traditionally enacted lower tax rates for this type of income to stimulate manufacturing and processing activities. The rate applicable to manufacturing and processing income varies from province to province, however in the majority of cases the rates are significantly lower than the general tax rates that would otherwise apply. The combined federal and provincial corporate manufacturing and processing income tax rates on active business income varies by province as follows: Table 7-1 Manufacturing and Processing Income Tax Rates Province Income Tax Rate British Columbia 35.62% Alberta 33.62% Saskatchewan 32.12% Manitoba 37.62% Ontario 34.12% Quebec 31.02% New Brunswick 35.12% Nova Scotia 38.12% Newfoundland 27.12% Prince Edward Island 29.62% Provincial Manufacturing and Processing Incentives and Sales Taxes In addition to the reduced corporate rates discussed above, in some Provincial jurisdictions manufacturing and processing incentives have been established to encourage manufacturing and processing activities. These incentives usually effectively provide for the abatement of Provincial sales taxes and in many cases such abatement mechanisms are tied in with the particular Provinces income tax legislation. Depending on the nature of activities of an entity, it may be more beneficial to operate in one province over the others. Most of the benefits are only available to corporations (includes Canadian controlled private corporations and co-operative corporations). The incentives related to eligible purchases that are explained below would be applicable to building and equipment directly used in the production of ethanol. 105

136 British Columbia In July of 2001, the British Columbia manufacturing and processing ( M&P ) tax credit was discontinued and the Province elected rather to exempt production machinery and equipment from provincial sales tax. This exemption from provincial sales tax is eligible for any entity that is a qualifying manufacturer and purchases qualifying equipment (therefore, not limited to corporations). British Columbia provincial sales tax is currently 7.5% Alberta Alberta has no provincial sales tax and no further M&P incentives Saskatchewan Saskatchewan has a non-refundable M&P investment tax credit on eligible manufacturing and processing equipment purchased. The credit can be carried forward seven years and back three years to be applied against Saskatchewan provincial tax. The credit is intended to rebate the provincial sales tax. This credit is only available to corporations. The provincial sales tax rate in Saskatchewan is currently 7% and the M&P investment tax credit is 7% of eligible purchases. Even though this credit is only available to corporations, this credit can also carry through to a corporation if the corporation is a beneficiary of a trusts or a partner in a partnership. The amount that the corporation can claim would be the portion of the investment tax credit that can reasonably be considered to be the corporation's share thereof. This allocation is generally based on the proportion of the income allocated in the year Manitoba Similar to Saskatchewan, Manitoba has a non-refundable M&P investment tax credit on eligible manufacturing and processing equipment purchased. The credit can be carried forward seven years and back three years to be applied against Manitoba provincial tax. The provincial sales tax rate in Manitoba is currently 7%, but the M&P investment tax credit is 10% of eligible purchases. Even though this credit is only available to corporations, this credit can also carry through to a corporation if the corporation is a beneficiary of a trusts or a partner in a partnership. The amount that the corporation can claim would be the portion of the investment tax credit that can reasonably be considered to be the corporation's share thereof. This allocation is generally based on the proportion of the income allocated in the year. According to the Manitoba Income Tax Act, this credit is currently slated to only be available until July 1, Ontario If you are a qualifying manufacturer, you do not have to pay Ontario sales tax on exempt production machinery and equipment. There are also other purchases a qualifying manufacturer may not have to pay sales tax on. The exemption from sales tax is eligible to any entity that is a qualifying manufacturer (not limited to only corporations). Ontario provincial sales tax is generally 8%. 106

137 Quebec Quebec provides a "tax holiday" for eligible corporations carrying on a M&P business in remote regions. This is effective until December 31, The "tax holiday" is a deduction in calculating taxable income. An eligible corporation together with associated corporations must have paid-up capital (tax base for capital tax) of less than $20 million. The tax holiday is phased out when paid-up capital exceeds $20 million and disappears at $30 million. In addition to the above deduction from taxable income, there is also a deduction from paidup capital for corporations eligible for the "tax holiday". The deduction is equal to the entire tax paid-up capital where that capital is not greater than $10 million. The deduction is prorated if paid-up capital is greater than $10 million but less than $15 million. Quebec also offers a refundable tax credit for payroll increases for certain businesses carrying on manufacturing or processing in remote resource regions of Quebec. The manufacturing and processing of ethanol may not be a qualifying activity. The credit is available to eligible corporations for five consecutive years, however, the corporation must commence to carry on business in an eligible region no later than during calendar year Therefore, this is likely not applicable in this case unless the legislation changes. Qualifying new manufacturing and processing machinery and equipment purchased for use in Quebec within a reasonable period of time following its acquisition qualify for a 100% deduction in the year of purchase. There is also a temporary 125% deduction on these qualifying purchases until April 1, The Quebec provincial sales tax is currently 7.5% New Brunswick, Nova Scotia and Newfoundland New Brunswick, Nova Scotia and Newfoundland have all harmonized their respective provincial sales tax with the federal goods and services tax. With the introduction of the harmonized sales tax, the former retail sales tax systems of Nova Scotia, New Brunswick and Newfoundland no longer apply and the sales tax paid on capital and business expenditures is refundable in the same way as GST. The harmonized sales tax rate in Nova Scotia, New Brunswick and Newfoundland is 15%. New Brunswick, Nova Scotia and Newfoundland have no further M&P incentives Prince Edward Island Similar to Saskatchewan and Manitoba, Prince Edward Island has a non-refundable M&P investment tax credit on eligible manufacturing and processing equipment purchased. The credit can be carried forward seven years and back three years to be applied against Prince Edward Island provincial tax. This credit is only available to corporations. The provincial sales tax rate is currently 10% in Prince Edward Island and the M&P investment tax credit is 10% of eligible purchases. Even though this credit is only available to corporations, this credit can also carry through to a corporation if the corporation is a beneficiary of a trusts or a partner in a partnership. The amount that the corporation can claim would be the portion of the investment tax credit that can reasonably be considered the corporation's share thereof. This allocation is generally based on the proportion of the income allocated in the year. 107

138 7.3.3 Federal Investment Tax Credits Currently, there are federal investment tax credits relating to qualifying current and capital research and development expenditures incurred by a corporation which are calculated similar to the provincial tax credits outlined above. The investment tax credit is used to reduce the current year's federal tax payable and may be carried forward ten years to be applied against future year's federal tax. A portion may be refundable as well. In the past, there was an ability to flow out certain of these scientific research and development credits to investors. However, it is no longer possible to do this under current tax legislation. In the past, there were federal investment tax credits related to the purchase of qualifying equipment for manufacturing and processing activities which were similar to the provincial investment tax credits outlined above. The investment tax credit was used to reduce federal tax and a portion may have been refundable. This tax credit is no longer available. Allowing qualifying ethanol activities to be eligible for a federal manufacturing and processing investment tax credit or the ability to flow out this investment tax credit as well as research and development investment tax credits to investors may stimulate the investment in ethanol activities Large Corporations Tax Large Corporations Tax ( LCT ) is essentially a tax a corporation must pay when its capital tax base is over a certain threshold amount. Loosely defined, the capital tax base is a corporation's liabilities (with some exceptions for current trade payables) plus stated capital plus equity. The threshold of the capital tax base varies for federal purposes and provincial purposes. If a company's capital tax base is over the threshold amount LCT is paid regardless of income of the corporation. The capital tax base on which capital tax is imposed varies in definition federally and from province to province. For the purposes of the calculations in this paper, we have assumed the capital tax base is substantially similar in definition for federal and provincial capital taxes. We do not believe that this will result in a significant difference. Only the provinces of Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia and New Brunswick impose a capital tax on corporations with permanent establishments in these respective provinces Federal The federal LCT is currently 0.20% on capital employed in Canada in excess of $50 million. The federal LCT is reduced by the federal surtax component of Part I Tax. The rate of 0.20% is scheduled to decline over the next few years as follows: Saskatchewan January 1, % January 1, % January 1, % The Saskatchewan LCT is computed at a rate of 0.60% on capital employed in Saskatchewan in excess of $17.5 million. The exemption of $17.5 million is increasing to $20 million effective for corporations with taxation year beginning on or after January 1,

139 Manitoba The Manitoba LCT is computed at a rate of 0.30% on capital employed in Manitoba in excess of $5 million. There is also an extra 0.20% on capital in excess on $10 million Ontario The Ontario LCT is computed at a rate of 0.30% on capital employed in Ontario in excess of $5 million Quebec The Quebec LCT is computed at a rate of 0.60% on capital employed in Quebec in excess of $600,000. The $600,000 exemption is gradually eliminated where the base capital tax is calculated is between $600,000 and $2.4 million. If the base capital tax is calculated on is $2.4 million or more, there is no exemption when determining LCT New Brunswick The New Brunswick LCT is computed at a rate of 0.30% on capital employed in New Brunswick in excess of $5 million Nova Scotia In calculating the LCT in Nova Scotia, if the tax base is less than $5 million the rate is nil. If the tax base is between $5 million and $10 million the rate is 0.50% on the full base less a $5 million exemption. If the tax base is greater than $10 million the rate is 0.30% on the full tax base, there is no exemption Personal Income Tax Rates In the above discussion, we have mentioned corporate income tax rates. If an investor is an individual, the investors tax rates will vary depending upon the investors province or territory of residence, the province or territory the income was earned in, the investors overall taxable income for the year, the nature and/or form in which the income is received in (i.e. dividends, interest or payment of pre-tax business profits in the form of a patronage allocation) and whether the income received is considered to be active business income or passive investment income. A comprehensive analysis of all possible investor income tax considerations and the numerous variations thereon is beyond the scope of this paper. Individuals are taxed at progressive tax rates that vary according to the amount of their taxable income. The relevant 2004 maximum marginal tax rates for different income types and for different jurisdictions in Canada are shown in the following table. It is assumed that potential investors would be in this tax bracket. 109

140 Table 7-2 Personal Tax Rates Marginal Tax Rates Jurisdiction Taxable Income All Other Dividends Capital Gains Amounts Income Alberta $113,805 and up 39.00% 24.08% 19.50% British Columbia $113,805 and up 43.70% 31.58% 21.85% Manitoba $113,805 and up 46.40% 35.08% 23.20% New Brunswick $113,805 and up 46.84% 37.26% 23.42% Nfld./Labrador $113,805 and up 48.64% 37.32% 24.32% Nova Scotia $113,805 and up 48.25% 33.06% 24.13% Nunavit $113,805 and up 40.50% 28.96% 20.25% Northwest Territories $113,805 and up 42.55% 29.02% 21.28% Ontario $113,805 and up 46.41% 31.34% 23.20% P.E.I $113,805 and up 47.37% 31.96% 23.69% Quebec $113,805 and up 48.22% 32.81% 24.11% Saskatchewan $113,805 and up 44.00% 28.33% 22.00% Yukon $113,805 and up 42.40% 28.64% 21.20% The characterization of the income as active business income or passive investment income may affect the amount of losses or tax deductions that an investor can claim in a particular circumstance. Readers should be aware that the characterization of the income as passive investment income or active business income is of significance to primary agricultural producers who may operate their business as an unincorporated business and who might invest in such a venture as part of their overall farming operation. Generally speaking, payments that are distributed to investors in the form of dividends on shares or interest payments on debt are considered to be passive investment income. Passive income is generally subject to more restrictive limits in the amount and nature of the tax deductions or losses that can be claimed as compared to active business income. 110

141 8. SOURCES OF CAPITAL 8.1 OVERVIEW The two main forms of capital can be characterized as debt and equity instruments. The general characteristics related to debt and equity providers/investors are outlined in the table below (Coopers and Lybrand). Table 8-1 Sources of Capital Providers of Debt Providers of equity Need for liquidity High Medium to Low Receipt of reward Regular schedule with defined date for return of capital Uncertain sources are dividends (based on profits) and sale side of equity Rewards required Adequate to achieve margin over cost of marginal funding (role of lenders as intermediaries) holdings Significantly in excess of return Role of excess return Not generally considered Excess return expected on some investments to offset unexpected losses on others Risk profile Risk control Highly adverse loss of investment to be avoided at all costs Business/financial risk analysis Cash flow Security Personal guarantees Receivership Risk accepting prepared for diminution (or possible loss) of value in some investments Business/financial risk analysis Management skills Replace senior management Involvement with company Limited Significant via Board of Directors Within the range of debt and equity instruments, there are many different investment vehicles that provide a combination of debt and equity features, some of which are discussed below. It is important to note that different sources of capital should be used in conjunction with each other. Most investors will look for a corporate business structure to invest into where there may be a combination of shares issued, notes pledged and/or options provided to allow investors to realize their return. 8.2 INSTITUTIONAL LENDERS Institutional lenders, including traditional banks and lending companies, will offer both senior debt financing and line of credit financing. The details of each of these are outlined below. 111

142 8.2.1 Senior Debt Financing Senior debt financing is a secured commercial loan made to businesses for a specific period of time. It is repaid with interest, usually with regular periodical payments. In general, senior debt financing is available from traditional banks and finance companies. The amount financed through senior debt varies depending on the type, age, and quality of assets available for security. Typically, advance rates are approximately 60 75% of the fair market value of land and buildings and 40 90% of the liquidation value of machinery and equipment. In the case of an ethanol plant, lenders will likely offer senior debt financing using the buildings and equipment as collateral. Some lenders also lend based on certain multiples of earnings before interest, taxes and depreciation (EBITDA). The multiple varies greatly between industries and companies. The term of the financing generally depends upon the useful life of the buildings and other equipment that are offered as security. In some cases where a business is reliant on a limited market or limited number of customers for its sales, lenders will wish to match the term of their loan to the term to a sales contract. Payments on senior debt are usually required monthly, however some lenders may be willing to structure repayment schedules to conform to the company s projected cash flows. The interest rate on senior debt ranges from 0.25% under bank prime to 5% over bank prime, depending on the perceived risk of the company s cash flows as well as the quality of the collateral. There are usually other fees associated with securing senior debt financing. These fees could be in the range of approximately 1-3% of the total financing obtained. Typically, interest rates and fees tend to be higher where the security provided for the loan is considered to be less liquid. Senior debt lenders use covenants to exert control over the borrower in order to protect their loan. They often monitor several financial covenants on a monthly basis. Breaking a covenant may put the company in default of the loan and put the senior lender in a position to exercise influence over the operations and future direction of the borrower. Senior debt lenders are more reluctant to lend to borrowers in the following circumstances, some of which currently exist within the current Canadian alternative fuels industry: The business is a start-up business with no proven track record or proven management expertise. The borrowers business is in an industry where the profits are viewed as being affected by cyclical fluctuations in either the price of its finished goods or in the cost of raw materials that are key to the production of the finished goods. The borrower is operating in an industry that is reliant on Government programs or incentives for market access and /or positive business economics. The borrower has no other assets or business interests that the senior lender can attach a security interest to. The lender has limited knowledge and in-house expertise of the industry that the borrower s is in. The borrowers industry is an industry that relatively few businesses operate in and/or has a limited market for the sale of its goods or services. The security provided for the loan is largely intangible. 112

143 8.2.2 Line of Credit A line of credit is a loan made to businesses to supplement working capital. A line of credit is used to fund daily operations of the company and to bridge unexpected cash flow interruptions or shortfalls. A line of credit allows a company to minimize borrowings and maximize cash utilization since most lenders will automatically fluctuate operating loans daily, resulting in lower borrowing costs. A company can typically obtain a line of credit based on a certain percentage of the value of its receivables and inventory, depending on the type and quality. Due to the nature of the operations of an ethanol plant, there is likely to be significant receivables and inventory throughout the year that can be used to secure a line of credit. 8.3 SUBORDINATED DEBT FINANCING Subordinated debt financing, often called mezzanine financing, typically incorporates elements of both debt and equity financing. The instrument is usually specifically tailored to meet both the borrowing company and the investing company s needs and there is often both current and deferred return components. The current return component is usually a periodic interest payment. The deferred return is usually dependent upon the company s future results and is often in the form of options or warrants. The deferred return component is usually required to boost the return above what is earned from the interest income. Subordinated debt financing is generally made available directly from insurance companies, pension funds, subordinated debt funds or finance companies such as Roynat Capital, the Business Development Bank, etc. The amount of subordinated debt lent is based on projected cash flows after servicing existing senior debt. The term of the financing is typically between six and ten years, and the principal repayment is often delayed until the maturity of senior debt. Subordinated debt is more risky to investors than senior debt financing since it is generally subordinate to senior debt in terms of collateral rights and rights to cash flow. As a result, subordinated debt financiers require a much higher rate of return than senior debt lenders, often in the range of 15 25% including the deferred return. The fees associated with securing subordinated debt are also higher than those charged to secure senior debt financing. Subordinated debt financiers traditionally have fewer financial and other covenants compared to senior debt financiers. Subordinated debt lenders rely primarily on their assessment of ability of the business to generate and sustain positive cash flows and provide the rate of return they are targeting when making their investment decision. Security considerations tend to be less important as senior lenders tend to have first claim and the subordinated investors only has a residual security interest. Typically a business will only seek out a subordinated debt lender when they have exhausted all sources of equity and are unable to secure the necessary capital for their venture from a senior lender due to the higher costs associated with subordinated debt and/or equity instruments. Senior lenders typically will consider the subordinated debt to be equity for purposes of their lending and covenant calculations since the subordinated lender(s) rank in priority of their security behind the senior lender. 113

144 8.4 EQUITY FINANCING With equity financing, investors receive a portion of the company equity in return for their investment. Finding outside equity investors for a business is often difficult due to the risk involved in the investment. There is no collateral offered and the equity owners have no priority to the company s assets. Due to the high risk of equity investments, investors typically seek investment opportunities with very high returns, usually in the range of 25-50% per annum. Such an investor generally needs to clearly see some type of future exit strategy upon which the majority of the return can be realized. These types of equity investors may be either individuals or large institutional investors. In addition to conventional equity investors, there is also another class of equity investors that can be referred to as synergistic investors. This type of investor considers more than just the financial return they will get from the prospective equity investment. For example, other factors that a synergistic investor might consider are factors such as securing a market for the inputs and/or outputs of other business interests that the investor holds; making investments that will diversify or hedge the risks that the investor has from other business/investment holdings; or the creation of jobs and wealth within the community the investor resides in Venture Capital Venture capitalists are private or publicly sponsored pools of capital that take equity positions in companies. The type of investment made varies depending on the situation and preference of the investor. Typically, capital is invested in convertible preferred stock, convertible notes or common stock. Traditional venture capital funds target companies with strong management, unique technology, rapid growth and the potential for great profitability. While venture capitalists will invest in companies in many stages, early-stage funding is most popular for venture capitalists. At this stage, the company has achieved some revenue, is poised for future growth and the ultimate opportunity to make money is more clearly demonstrated. Venture capitalists seem to be somewhat reluctant to invest in companies at the start-up stage. Most venture capital funds do not participate in day-to-day management, however, they usually occupy a seat on the company s board of directors in order to ensure that their investment is being managed appropriately. This often assists many companies in that they are able to provide significant management assistance when needed. Most venture capital funds look to exit an investment within three to seven years. 8.5 TAX EFFECTIVE INVESTMENT VEHICLES Historically, Canadian income tax legislation has provided mechanisms that could be used to stimulate or increase the ability of an entity to raise capital to fund their operations by offering to investors a investment unit that would entitle the investor to certain preferential tax treatment. These types of investments units are commonly referred to as tax shelters. Generally the intended result of a tax shelter is that the purchaser/investor is able to claim a tax deduction equal to a portion or in some cases the entire amount of the investment in a short period of time, creating a tax loss from that source which is used to reduce other income that the investor has that would be subject to current tax. Tax shelters frequently use a flow through mechanism such as flow through share to achieve the desired outcome. In simple terms, the business venture will allocate tax deductions that it 114

145 would otherwise be entitled to take in respect of certain expenditures it has made to the investors that have purchased its tax shelter units. The investor then claims the deduction they have been allocated as an expense on their tax return. In recent years, the more popular types of tax shelters have been offered in the film, computer software and resource industries. To issue flow through shares, the business must fit the applicable provisions of the income tax act. The features of the more pertinent flow through income tax legislation provisions are expanded upon below. In addition, a limited partnership structure can be used in certain circumstances to provide a tax efficient investment opportunity to investors in a manner similar to flow through shares. Limited partnerships have the advantage that they are widely available in that the use of this type of organizational structure is not restricted to specific industries. As explained below, the ability to use a limited partnership structure to offer a tax efficient investment opportunity will depend upon the entities particular circumstances Flow Through Shares If a corporation qualifies as a principal business corporation under the Income Tax Act (Canada) ("ITA"), the corporation has the opportunity to issue flow-through shares. Flowthrough shares provide the investor with an equity interest in the company and the right to claim income tax deductions for new expenditures made by the company on exploration or development. The investor is able to deduct these amounts if the company renounces these expenditures and transfers them to the investors. Since the investor receives an equity interest as well as the ability to deduct the transferred expenses, there is typically a premium on these types of shares. Flow-through shares enable a company who has limited access to alternative sources of financing to raise needed capital. As mentioned, a principal business corporation is able to issue flow-through shares. A principal business corporation means a corporation the principal business of which is any of, or a combination of the following: a) the production, refining or marketing of petroleum, petroleum products or natural gas, b) exploring or drilling for petroleum or natural gas, c) mining or exploring for minerals, d) the processing of mineral ores for the purpose of recovering metals or minerals from the ores, e) the processing or marketing of metals or minerals that were recovered from mineral ores and that include metals or minerals recovered from mineral ores processed by the corporation, f) the fabrication of metals, g) the operation of a pipeline for the transmission of oil or gas, h) the production or marketing of calcium chloride, gypsum, kaolin, sodium chloride or potash, i) the manufacturing of products, where the manufacturing involves the processing of calcium chloride, gypsum, kaolin, sodium chloride or potash, j) the generation of energy using property described in Class 43.1 of Schedule II to the Income Tax Regulations, and k) the development of projects for which it is reasonable to expect that at least 50% of the capital cost of the depreciable property to be used in each project would be the capital cost of property described in Class 43.1 of Schedule II to the Income Tax Regulations. 115

146 In 1997, applicable after December 5, 1996, j) and k) above were added to the description of principal business corporation in the ITA. At this same time, Canadian renewable and conservation expenses (CRCE) was added to the ITA. The Government of Canada added these provisions to the ITA in order to promote a healthier environment by encouraging investment in energy efficiency and renewable energy projects. CRCE provided the renewable energy sector with similar tax advantages that were only available to the non-renewable resource sector (i.e. oil, gas and mining) before this time. These tax advantages are the ability to fully deduct expenditures associated with the start-up of renewable energy and energy conservation projects or the ability to renounce the CRCE expenditures to shareholders through a flow-through share agreement. If CRCE had not been added to the ITA, development expenses incurred in the renewable energy sector would have had to be categorized as an eligible capital expenditure or added to the capital cost of property resulting in realizing the expenditures over a period of time. As well, the renewable energy sector would not be able to benefit from flow-through shares. These would have been significant disadvantages to organizations wanting to undertake development work in the renewable energy sector when compared to those undertaking development work in the non-renewable energy sector. Currently, a company producing ethanol does not have the opportunity to benefit from issuing this type of share since it would not qualify as a principal business corporation. However, the production of ethanol, even though it does not qualify as a CRCE, is similar to CRCE in that ethanol production promotes a healthier environment by reducing greenhouse gas emissions from transportation. By enabling entities that are undertaking ethanol production to benefit from being able to fully deduct expenditures associated with the start-up of ethanol projects or the ability to renounce the expenditures to shareholders through a flowthrough share agreement would be in line with the Government of Canada's initiative to promote a healthier environment. The total amount raised by flow-through funds in 2003 was in excess of $375 million compared to a total of almost $282 million raised in Thus, there is an increasingly significant amount of capital able to be invested in eligible companies. Each fund invests in a variety of eligible companies. For 2003, the average single investment in a company was approximately $736,000 while the largest investment was approximately $4.4 million. Often there is more than one flow-through fund that invests in a particular company. For 2003, the average total investment per company was approximately $1.95 million, while the largest total investment in one company was $ million. This shows that the required investments for start-up ethanol operations would be on the high side of investments for flow-through funds, however, it would still be within the range of the investments that they are willing to invest in. Most flow-through funds look to exit an investment within three years, thus the typical investment horizon for such funds may not be very suitable for the typical alternative fuels venture Limited Partnership Units As discussed earlier, business ventures that are organized as a limited partnership structure allocates its taxable income or losses to the holders of the limited partnership units. Where losses are allocated out, an investor is generally entitled to claim a loss for tax purposes against other income that they might have to a maximum of their at risk amount. In simple terms a limited partner investors at risk amount is limited or equal to the cost of their investment. 116

147 The allocations of tax losses to limited partners can effectively be used for tax purposes in the same manner as that of deductions allocated to a flow through investor in a tax shelter scenario. Typically, however, it is only in the initial years or the initial commencement of operation stages that a new business will have ability to create tax losses (which tend to relate to the expensing for tax purposes of initial organizational and operational start-up costs) that can be allocated to limited partners. By comparison, flow through shares can be issued at any point in an eligible entities life span. Frequently it is observed that a limited partnership structure will be used in situations where a new venture expects to be in a position to initially allocate tax losses to its investors and upon becoming taxable, it will be reorganized into a corporate structure. 8.6 TYPICAL CAPITAL STRUCTURES As mentioned above, most companies structure their company with a combination of debt, equity and other financing. Below is a summary of the capital structures for some of the ethanol operations that were discussed in Section 4 of the report. Table 8-2 US Ethanol Plant Capital Structures Dakota Ethanol LLC Northern Growers LLC Badger State Ethanol LLC Chippewa Valley Ethanol Capital costs, $ 40,000,000 44,100,000 46,435,000 24,400,000 Working capital, $ 4,000,000 6,500,000 6,000,000 3,500,000 Equity Members, $ 15,610,000 12,700,000 17,900,000 10,000,000 Equity Corporate investor, $ - 3,700, Equity Sub debt, $ Senior term debt, $ 26,600,000 31,100,000 30,600,000 16,800,000 Senior term debt to equity Senior term debt as a % of capital costs 66.5% 70.5% 65.9% 68.9% Equity as a % of capital costs 39.0% 37.2% 38.5% 41.0% There are some trends evident in the above information. In general, senior term debt lenders financed between 66% and 70% of the capital cost of the projects. In addition, the equity as a percentage of capital cost was consistent between companies, ranging between 37% and 41%. Even though these companies are operating in the US, we can expect the resulting capital structure of Canadian ethanol companies to be similar to these. A review of the initial prospectuses of these companies uncovered some consistencies in the approach to financing of these companies. The strategy of all companies was to obtain the maximum senior debt financing and exhaust all possible equity sources before looking to subordinated debt financing. All of the above companies were successful in obtaining the necessary debt and equity financing and did not have to rely on subordinated debt financing. 117

148 Other observations that were made in reviewing the four entities identified above are as follows: All four entities are majority owned by primary producers or local investors/members. A profile of the ownership and average investment per member (where this information was available) is as follows: o Dakota Ethanol LLC 941 members Average member investment $16,589 50% of feedstocks supplied by members o Northern Growers LLC 650 members Average member investment $19,538 40% of feedstocks supplied by members o Chippewa Valley Ethanol Company 650 members Average member investment $15,385 It is not know what percentage of feedstocks are supplied by members. Badger State Ethanol LLC s original prospectus identified three possible scenarios with respect to its raising different amounts of capital. These scenarios are useful in demonstrating how subordinated debt might be used to leverage senior term debt. The three scenarios are identified in the following table: Table 8-3 Subordinated Debt Scenarios Scenario 1 Scenario 2 Scenario 3 Member equity $10,000,000 $15,000,000 $20,000,000 Subordinated debt $13,000,000 $7,000,000 $0 Senior term debt $32,000,000 $32,000,000 $32,000,000 Debt to equity ratio (Excluding subordinated debt as equity) Debt to Equity Ratio (Including subordinated debt as equity)

149 9. ETHANOL FINANCIAL MODEL 9.1 OVERVIEW A financial model for ethanol plants has been built that is flexible but detailed. The model allows for two years of project development and construction followed by ten years of operation. The model contains input sheets for the key ethanol production variables and for financing options and output sheets that include a balance sheet, statement of earnings, cash flows, financial ratios for each year of operation and the ability to perform sensitivity analysis on some of the major variables. The financial model that has been developed does not allow the user to choose the business structure for the plant. Instead, it is assumed that a corporate structure is adopted as it is this business structure that results in the presentation of financial statements in the manner that most closely parallels that of the economic unit concept, which is ultimately how a prospective investor will view their investment analysis and decision making process. Model results for each of the major types of feedstock are presented below, followed by a sensitivity analysis. 9.2 PROFITABILITY ANALYSIS There are many different options that could be envisioned for individual plants including feedstock used, size, location of production and location of sales, co-products produced, debt and equity structure, corporate structure, etc. A common set of assumptions is required to assess the profitability for ethanol. It will be assumed that grain ethanol plants of 120 million litres per year of capacity are employed. The feedstock costs will be the ten year average prices. Natural cost gas costs will be based on a five year average price. The cellulose ethanol plants will be 170 million litres in size. The plants will be financed with 50% equity and 50% debt with an interest rate of 6%. To start with, one plant for each feedstock will be chosen and then later in the sensitivity analysis the impact of location will be assessed. The ethanol will be sold in the province that it is produced in. The plants will operate at 90% of design capacity in year one and at 100% of design capacity in subsequent years. It will be assumed that there is a 2% sale commission to be paid on DDG sales but not on ethanol and carbon dioxide sales. An allowance of 0.5 cpl for ethanol freight to market has been made but no allowance has been made for DDG sales Corn Ethanol The corn ethanol plant will be assumed to be located in Ontario. It will be assumed that carbon dioxide is captured and sold as a raw gas for $15/tonne. The production input assumptions are made in the following table. 119

150 Table 9-1 Production Assumptions Corn Ethanol Rack price per litre - regular unleaded gasoline $ Federal tax abatement Provincial tax abatement Less discount to retailer (0.0200) Selling price per litre $ DDG selling price - per tonne $ Carbon Dioxide selling price - per tonne $ Feedstock cost - per tonne $ Ethanol freight per litre $ DDG freight per tonne $ - Enzymes $ Yeast Other chemicals Natural gas - GJ per litre price per GJ $ Electricity - kwh per litre cost per kwh $ # of employees 35 Average labour cost per employee (annual) $ 45,000 Employee benefits as a percentage of labour costs 15% Ethanol selling expenses - as a % of sales 0% DDG selling expenses - as a % of sales 2% Carbon dioxide selling expenses - as a % of sales 0% The first and second year statement of earnings is shown in the following table. 120

151 Table 9-2 Statement of Earnings Corn Ethanol Revenue Year 1 Year 2 Ethanol $ 56,587,587 $ $ 65,408,870 $ DDG 14,902, ,862, Carbon Dioxide 1,101, ,224, Total 72,591, ,495, Production costs Feedstocks 39,690, ,100, Processing supplies 3,240, ,600, Natural gas 7,144, ,938, Electrical 1,555, ,728, Denaturant 606, , Water 194, , Waste management 194, , Repairs & maintenance 537, , Salaries and wages 1,811, ,847, ,974, ,983, Add: opening inventory - - 2,095, Less: ending inventory (2,095,223) (0.4482) (2,347,056) (0.4519) 52,878, ,731, Income from operations 19,712, ,763, General and admin expenses 1,620, ,800, Selling expenses 298, , Freight expenses Freight - ethanol 540, , ,458, ,737, EBITDA 17,254, ,025, Amortization 2,889, ,913, EBIT 14,365, ,112, Interest expense 2,010, ,638, Net Income (loss) before taxes 12,354, ,474, Provision for income taxes Current taxes 1,566, ,421, Future taxes 2,592, ,796, Capital taxes 219, , ,378, ,457, Net Income (loss) after taxes 7,991,829 $ ,050,031 $ The ten year leveraged after tax Internal Rate of Return for this case is 20%. 121

152 9.2.2 Wheat Ethanol For the wheat ethanol plant as many of the assumptions are held the same as for the corn plant as possible. The plant size is 120 million litres per year and the capital structure is held the same. The same production schedule is used. The plant is assumed to be located in Saskatchewan and in this case, no carbon dioxide is captured and sold due to the small size of this market in Western Canada. Table 9-3 Production Assumptions Wheat Ethanol Rack price per litre - regular unleaded gasoline $ Federal tax abatement Provincial tax abatement Less discount to retailer (0.0200) Selling price per litre $ DDG selling price - per tonne $ Carbon Dioxide selling price - per tonne $ 0.00 Feedstock cost - per tonne $ Ethanol freight per litre $ DDG freight per tonne $ - Enzymes $ Yeast Other chemicals Natural gas - GJ per litre price per GJ $ 5.50 Electricity - kwh per litre cost per kwh $ # of employees 35 Average labour cost per employee (annual) $ 45,000 Employee benefits as a percentage of labour costs 15% Ethanol selling expenses - as a % of sales 0% DDG selling expenses - as a % of sales 2% Carbon dioxide selling expenses - as a % of sales 0% The first and second year statement of earnings is shown in the following table. 122

153 Table 9-4 Statement of Earnings Wheat Ethanol Revenue Year 1 Year 2 Ethanol $ 57,422,829 $ $ 66,374,314 $ DDG 24,348, ,551, Carbon Dioxide Total 81,771, ,925, Production costs Feedstocks 36,194, ,216, Processing supplies 3,618, ,020, Natural gas 6,534, ,260, Electrical 1,166, ,296, Denaturant 615, , Water 194, , Waste management 194, , Repairs & maintenance 591, , Salaries and wages 1,811, ,847, ,920, ,485, Add: opening inventory - - 1,830, Less: ending inventory (1,830,624) (0.3916) (2,057,308) (0.3961) 49,089, ,259, Income from operations 32,682, ,666, General and admin expenses 1,620, ,800, Selling expenses 486, , Freight expenses Freight - ethanol 540, , ,646, ,951, EBITDA 30,035, ,715, Amortization 3,218, ,244, EBIT 26,817, ,471, Interest expense 2,337, ,904, Net Income (loss) before taxes 24,479, ,566, Provision for income taxes Current taxes 4,997, ,475, Future taxes 2,776, ,937, Capital taxes 366, , ,141, ,760, Net Income (loss) after taxes 16,338,542 $ ,805,549 $ The ten year leveraged after tax Internal Rate of Return for this case is 35%. 123

154 9.2.3 Barley Ethanol The barley ethanol plant will also be located in Saskatchewan and will produce 120 million litres per year. The only differences between the barley and wheat plants are those caused by the feedstock. Table 9-5 Production Assumptions - Barley Ethanol Rack price per litre - regular unleaded gasoline $ Federal tax abatement Provincial tax abatement Less discount to retailer (0.0200) Selling price per litre $ DDG selling price - per tonne $ Carbon Dioxide selling price - per tonne $ 0.00 Feedstock cost - per tonne $ Ethanol freight per litre $ DDG freight per tonne $ - Enzymes $ Yeast Other chemicals Natural gas - GJ per litre price per GJ $ Electricity - kwh per litre cost per kwh $ # of employees 35 Average labour cost per employee (annual) $ 45,000 Employee benefits as a percentage of labour costs 15% Ethanol selling expenses - as a % of sales 0% DDG selling expenses - as a % of sales 2% Carbon dioxide selling expenses - as a % of sales 0% The first and second year statement of earnings is shown in the following table. 124

155 Table 9-6 Statement of Earnings- Barley Ethanol Revenue Year 1 Year 2 Ethanol $ 57,422,829 $ $ 66,374,314 $ DDG 19,344, ,888, Carbon Dioxide Total 76,767, ,262, Production costs Feedstocks 36,221, ,246, Processing supplies 4,158, ,620, Natural gas 8,019, ,910, Electrical 1,425, ,584, Denaturant 615, , Water 194, , Waste management 194, , Repairs & maintenance 699, , Salaries and wages 1,811, ,847, ,338, ,186, Add: opening inventory - - 1,976, Less: ending inventory (1,976,475) (0.4228) (2,218,358) (0.4271) 51,362, ,944, Income from operations 25,404, ,318, General and admin expenses 1,620, ,800, Selling expenses 386, , Freight expenses Freight - ethanol 540, , ,546, ,837, EBITDA 22,857, ,480, Amortization 3,805, ,836, EBIT 19,052, ,643, Interest expense 2,712, ,211, Net Income (loss) before taxes 16,339, ,432, Provision for income taxes Current taxes 1,840, ,799, Future taxes 3,299, ,658, Capital taxes 50, , ,590, ,893, Net Income (loss) after taxes 10,749,535 $ ,539,086 $ The ten year leveraged after tax Internal Rate of Return for this case is 20%. 125

156 9.2.4 Cellulosic Ethanol The cellulose ethanol plant is larger at 170 million litres/year. Rather than model the capital cost of the first plant the 5 th plant will be used and the capital cost will be reduced by $88 million. It will be assumed that it is located in Saskatchewan. The production inputs are as recommended in the previous section. Maintenance costs are initially 2% are rise to 3% in year ten. The capital structure is the same as the starch to ethanol plants with 50% equity and 50% debt but the debt amortization period has been extended from five to ten years. Given the state of development of this technology and the amount of information in the public domain there is a great deal more uncertainty about these input values. Table 9-7 Production Assumptions- Cellulosic Ethanol Rack price per litre - regular unleaded gasoline $ Federal tax abatement Provincial tax abatement Less discount to retailer (0.0200) Selling price per litre $ Other revenue - per litre $ Electricity sales- kwh/litre $ Electricity sales- cents/kwh 3.0 Feedstock cost - per tonne $ Ethanol freight per litre $ DDG freight per tonne $ - Enzymes $ Yeast Other chemicals Natural gas - GJ per litre 0 - price per GJ $ Electricity - kwh per litre cost per kwh $ # of employees 100 Average labour cost per employee (annual) $ 45,000 Employee benefits as a percentage of labour costs 15% Ethanol selling expenses - as a % of sales 0% DDG selling expenses - as a % of sales 2% Carbon dioxide selling expenses - as a % of sales 0% The first and second year statement of earnings is shown in the following table. 126

157 Table 9-8 Statement of Earnings- Cellulosic Ethanol Revenue Year 1 Year 2 Ethanol $ 81,349,007 $ $ 94,030,279 $ Electricity 463, , Other revenue 7,726, ,585, Total 89,539, ,130, Production costs Feedstocks 19,125, ,250, Processing supplies 18,115, ,128, Natural gas Electrical Denaturant 872, , Water 275, , Waste management 275, , Repairs & maintenance 4,715, ,530, Salaries and wages 5,175, ,278, ,553, ,768, Add: opening inventory - - 2,101, Less: ending inventory (2,101,687) (0.3173) (2,327,399) (0.3163) 46,452, ,542, Income from operations 43,086, ,587, General and admin expenses 2,295, ,550, Selling expenses 163, , Freight expenses Freight - ethanol 765, , ,223, ,582, EBITDA 39,863, ,005, Amortization 8,589, ,661, EBIT 31,273, ,344, Interest expense 6,311, ,880, Net Income (loss) before taxes 24,961, ,463, Provision for income taxes Current taxes 154, Future taxes 7,561, ,814, Capital taxes 1,251, ,208, ,967, ,023, Net Income (loss) after taxes 15,994,410 $ ,439,675 $ The ten year leveraged after tax Internal Rate of Return for this case is 14%. 127

158 9.2.5 Other Feedstocks Other feedstocks such as potatoes, rye, triticale are available in lower volumes than the primary crops analyzed above. Plants dedicated to these feedstocks will be smaller and the economics will be strongly influenced by plant size and specific site conditions. As a result, no attempt has been made to analyze a generic case for these feedstocks. Plant size is considered as part of the sensitivity analysis. 9.3 SENSITIVITY ANALYSIS There are several factors that could be analyzed to determine their impact on ethanol production economics. The ones considered here include location, plant size, capital costs, corporate structures, capital structures, and taxes Location There are differences in commodity prices and taxes between provinces. When the feedstock availability is also introduced into the equation then there are really only a few choices for location. Corn ethanol plants can be built in Ontario or Quebec, nowhere else in the rest of Canada is there sufficient domestic corn production on which to base an industry. Corn and DDG prices are both historically higher in Quebec than in Ontario with the net feedstock cost also being higher. Natural gas is higher cost but electrical power is less. The differences are relatively small and the financial results for year two of operation are summarized in the following table. In this case, it was assumed that the ethanol selling price was the same in the two regions. Table 9-9 Corn Ethanol Location Sensitivity Ontario Quebec $ $/litre $ $/litre Revenue 83,495, ,644, Production Cost 60,731, ,445, Income from 22,763, ,199, Operations G&A 2,737, ,760, EBITDA 20,025, ,439, Amortization 2,913, ,913, EBIT 17,112, ,526, Interest 1,638, ,649, Taxes 5,424, ,635, Net Income 10,050, ,241, IRR 20% 19% For wheat ethanol plants, the plants are likely to be built close to the feedstock, which would mean Alberta, Saskatchewan or Manitoba. The sensitivity to location is summarized in the following table. All inputs for the plants have been held constant except for feedstock cost, DDG price, energy costs and the Provincial specific taxes. The ethanol selling prices have also been held constant even though the provincial tax incentives do vary between provinces. 128

159 Table 9-10 Wheat Ethanol Location Sensitivity Saskatchewan Alberta Manitoba $ $/litre $/litre $ $/litre Revenue 93,925, ,278, ,818, Production 56,259, ,160, ,753, Cost Income from 37,666, ,117, ,064, Operations G&A 2,951, ,978, ,928, EBITDA 34,715, ,139, ,136, Amortization 3,244, ,205, ,164, EBIT 31,471, ,934, ,971, Interest 1,904, ,790, ,906, Taxes 9,760, ,462, ,433, Net Income 19,805, ,692, ,631, IRR 35% 37% 30% For these three cases, the lowest production cost is found in Saskatchewan but the highest IRR is found in Alberta, primarily because of the lack of Provincial sales tax on the plant equipment. Manitoba has the lowest Income from Operations and the highest taxes but the return on investment is still much higher than found with corn ethanol plants in Ontario and Quebec Plant Size The size of the production plant is a significant variable in the overall production economics. In the following table, a wheat ethanol plant in Saskatchewan has been chosen to model the impact of production size. All of the variables are held constant except for the plant size. The results are summarized in the following table. Table 9-11 Impact of Plant Size Plant Size, Million Litres/Year Net Income After Tax, cpl Leveraged IRR % The per litre after tax income is relatively constant after about 60 million litres per year but the investors IRR continues to increase as the plant sizes become larger. This is a function of the non-linear nature of the capital cost increase with size otherwise known as the economies of scale. 129

160 9.3.3 Capital Costs One of the success factors identified with the US ethanol plants was the low capital cost of the newest plants. It has also been identified that the capital cost of Canadian plants has been substantially higher and even the most recent proposed plants have some very high capital costs. To study the impact of the original capital cost on the project economics the Saskatchewan wheat plant will again be used as the model. The capital cost of the 120 million litre plant is estimated by the model to be $70.3 million with an additional $13.8 million required for pre-operating costs, working capital, and interest and taxes during construction. The impact of higher capital costs is shown in the following table. Table 9-12 Impact of Capital Cost Plant Capital Cost, $ Million Net Income After Tax, cpl Leveraged IRR % The capital cost does have an impact on the after tax income due to higher interest costs and some higher maintenance costs but the greatest impact is on the investors internal rate of return. Here the lower annual cash flow and the higher level of invested capital both drive the IRR down significantly as the capital costs increase Ownership Structures, Capital Structures and Income Taxes As discussed earlier, there are numerous types of ownership structures and variations therein that can be used in structuring the ownership of a business. The choice of ownership structure impacts the nature of the business s capital structure, the legal relationship between the owner/investor, other owners, the operating entity, and creditors of the business. Additionally, the ownership structure determines how the profits or losses of the business will be taxed. From a business economics perspective, the greatest implication of the ownership structure to the economics of the business is with respect to costs and or benefits associated with how the profits or losses of the business will be taxed, as well as the timing of such taxes. Experience shows that the business ownership structure chosen in the formation of new entities is influenced as much, if not more by considerations relating to the nature of the legal relationship of the owners/investors with other owners/investors and the operating entity, and the nature of the equity ownership instrument. Taxation considerations tend to more important in the decision making process where there are relatively few owners and/or where the ownerships group tends to be homogeneous and have similar investment objectives. While the following analysis focuses primarily on the taxation matters pertaining to the ownership structure, it should be emphasized that tax considerations are only one of the considerations in the overall decision process. Typically, the financial benefit or cost of alternative taxation scenarios are quantified by measuring by the net present value of the differences in cash flows between the alternatives of flowing through taxable income, deductions, or tax credits to the investors/owners as compared to retaining them within the operating entity for deduction against future taxable income or taxes payable. The net present value calculation typically also considers any tax 130

161 savings or additional costs that might be realized through having the earnings taxed at lower or higher tax rates. An incremental tax analysis has been incorporated within the financial model to assist users of the financial model in assessing the significance of the tax benefits or costs related to different ownership structures. The base line for the comparisons of the alternatives is the corporate ownership structure. As identified in the earlier tax analysis, manufacturing and processing income earned by a corporation is entitled to have its income in excess of $300,000 taxed at one of the lowest tax rates that is available to any type of entity or individual. A disadvantage of the conventional corporate ownership structure identified in the earlier tax analysis is the inability of a corporation to allocate tax losses or tax credits that it cannot immediately utilize to its owners. Another disadvantage is the possibility of corporation being subject to the large corporations capital tax, which is mainly a function of the amount of its assets, and the province or territory that it operates in. The model quantifies the financial benefits and/or costs by comparing four different scenarios to the base line assumed above. The specific scenarios developed are as follows: Scenario 1 - The flow through of available tax deductions and/or losses to investors. Scenario 2 The flow through of available tax deductions/losses as in Scenario 1 and the flow through of investment tax credits generated from the construction of the facility (if applicable) to investors. Scenario 3 The flow through of available tax deductions/losses as in Scenario 1 and using an ownership structure that is not subject to the application of capital taxes. Scenario 4 - The flow through of available tax deductions/losses and investment tax credits as in Scenario 1 and using an ownership structure that is not subject to the application of capital taxes. The model quantifies the amount of the financial savings or costs that might be realized in each of the above scenarios. The model has the flexibility to allow users to input the investor applicable tax rate, and the discount rate or investor s cost of capital rate to compute the net present value of the tax savings or costs in each scenario. Additionally, the model demonstrates the impact on the leveraged internal rate of return of each of the scenarios outlined above. It should be noted that the analysis assumes implicitly that once the maximum amount of tax benefits have been allocated to investors, that the taxable income would be taxed at corporate rates applicable to manufacturing and processing income. As noted earlier in the review of tax matters, the tax rate applicable to manufacturing and processing profits is generally one of the lowest rates of taxation that can be accessed. The following assumptions have been consistently used from scenario to scenario for purposes of the alternative scenario comparisons discussed below: Plant size and type 120 million litres wheat ethanol Production assumptions as per Table 9-3 Investor tax rate 45% Discount rate 10% Three provinces have been selected to demonstrate that the significance of the alternative scenarios varies not only by the type of ownership structure, but also by province or territory. 131

162 The significance of the three provinces selected in the scenarios analyzed below is as follows: Alberta o No provincial sales taxes on capital costs and no investment tax credits in respect of sales taxes paid on capital costs. o No provincial large corporations capital tax. Saskatchewan o Provincial sales taxes are applicable on capital costs and investment tax credits are earned in respect of sales taxes paid on capital costs. o Provincial large corporations capital tax is applicable. Ontario o Capital costs are exempt from provincial sales taxes. o Provincial large corporations capital tax is applicable. Table 9-13 Scenario 1 Flow through of Tax Deductions/Losses to Investors/Owners Province AB SK ON Total project capital and pre-operating costs $ 69,896,568 $ 75,160,341 $ 70,143,293 IRR - base line model 39% 35% 38% Losses and tax deductions available for flowthrough $ 2,316,624 $ 2,836,276 $ 2,565,607 NPV of differences in cashflows $ 305,112 $ 439,055 $ 327,172 IRR - Scenario 1 39% 35% 39% NPV of tax benefits as a percentage of total project costs 0.4% 0.6% 0.5% The above analysis shows that, based on the assumptions outlined above, the flow through of tax deductions and/or losses in the initial years of operations is not of a great significance due to the limited amounts available for flow through. This is largely due to the fact that the operation is projected to be profitable for tax purposes in its first few years of operations, thus the net present value difference between the alternatives is rather small relative to the size of the project. The net present value of the benefits between the two scenarios will increase as the profitability of the business decreases. The flow through of tax deductions/losses can be achieved by using ownership structures such as partnerships, joint ventures and/or some other form of unincorporated organizational structure. Equity instruments such as flow through shares or units in a limited partnership can also be used to achieve such flow throughs. 132

163 Table 9-14 Scenario 2 Flow through of Tax Deductions/Losses and Investment Tax Credits to Investors Province AB SK ON Total project capital and pre-operating $ 69,896,568 $ 75,160,341 $ 70,143,293 costs IRR - base line model 39% 36% 38% Losses and tax deductions available for flow-through $ 2,316,624 $ 2,836,276 $ 2,565,607 Investment tax credits available for flow $ - $ 4,600,389 $ - through NPV of differences in cashflows $ 305,112 $ 1,048,297 $ 327,172 IRR - Scenario 2 39% 38% 38% NPV of tax benefits as a percentage of total project costs 0.4% 2.2% 0.5% The above analysis demonstrates that the flow through of investment tax credits related to provincial sales taxes is only of significance in those provinces or territories that allow for the abatement of sales taxes in such a manner. It is important to recognize that the flow through of tax credits results in a dollar for dollar reduction in taxes otherwise payable. The flow through of tax losses and/or tax deductions only results in the investor having the ability to defer taxes at their marginal rate of tax. Most jurisdictions that presently allow for the creation of investment tax credits in respect of provincial sales taxes on prescribed capital costs only allow such credits to be use by a corporation. Thus in this scenario, the ownership structure would have to be either a joint venture, or a partnership and the investor/owner would have to be incorporated, or the operating entity would have to be a wholly owned unincorporated operating division of a larger company 133

164 Table 9-15 Scenario 3 Flow through of Tax Deductions/Losses to Investors and Non-Assessment of Capital Taxes Province AB SK ON Total project capital and pre-operating $ 69,896,568 $ 75,160,341 $ 70,143,293 costs IRR - base line model 39% 36% 38% Losses and tax deduction available for $ 2,316,624 $ 2,836,276 $ 2,565,607 flow-through Investment tax credits available for flow through n/a n/a n/a Capital tax savings (first 10 years of operations) $ 14,435 $ 3,266,518 $ 2,137,585 NPV of differences in cashflows $ 315,389 $ 2,280,449 $ 1,527,891 IRR - Scenario 3 39% 37% 39% NPV of tax benefits as a percentage of total project costs 0.5% 3.0% 2.2% The above analysis highlights the potential significance of provincial capital taxes where applicable to the overall economics of the business unit. The significance of provincial capital taxes (where applicable) varies in direct relation to the size of the asset base of the venture. All corporations are subject to capital taxes, unless specifically exempted from the application of such taxes. Co-operative corporations or new generation corporations are frequently exempted from capital taxes. Capital taxes related to non-incorporated ownership structures such as joint ventures, partnerships or limited liability partnerships are generally assessed at the owner/investor level. Non-incorporated owners/investors may be totally exempt from such taxes while incorporated owner/investors may possibly be entitled to their own capital tax exemption, both of which may reduce the overall capital tax liability. 134

165 Table 9-16 Scenario 4 Flow through of Tax Deductions/Losses and Investment Tax Credits to Investors and Non-Assessment of Capital Taxes Province AB SK ON Total project capital and pre-operating $ 69,896,568 $ 75,160,341 $ 70,143,293 costs IRR - base line model 39% 36% 38% Losses and tax deductions available for $ 2,316,624 $ 2,836,276 $ 2,565,607 flow-through Investment tax credits available for flow $ - $ 4,600,389 $ - through Capital tax savings (first 10 years of operations) $ 14,435 $ 3,266,518 $ 2,137,585 NPV of differences in cashflows $ 315,389 $ 2,889,681 $ 1,527,891 IRR - Scenario 4 39% 39% 39% NPV of tax benefits as a percentage of total project costs 0.5% 3.8% 2.2% The above analysis quantifies the maximum benefit that might be achieved, depending upon the province of residence and the applicability of each of the variations in the scenarios outlined above. It should be noted, that based on the assumptions outlined above, the greatest benefits are derived from the utilizing ownership structures that are not subject to provincial capital taxes and from having the ability to flow through investment tax credits to owners/investors. The significance of the possible benefit to be realized in provinces or territories where either or both of these items are applicable is directly related to the dollar cost of the venture and the profitability of the venture. With respect to the flow through of tax deductions and investment tax credits to owners/investors, it should be noted this generally results in the deferral of taxes otherwise payable. In the case of capital taxes, the benefits are more significant as they arise from an actual tax saving through the permanent reduction in taxes that would otherwise be payable. Readers are cautioned that the forgoing is a general commentary only. Additionally, readers and users of the financial model are cautioned that the financial model analysis in this regard, while useful, is simplistic and cannot be relied upon as a recommendation as each individuals tax circumstances will not be identical, thus the benefits and or costs of alternative scenarios will vary amongst investors and amongst individual circumstances Selling Prices Another interesting use of the model is to assess the relationship of crude oil prices and ethanol feedstock costs. The ethanol selling price is projected from the gasoline rack price. The relationship between the price of crude oil and the rack price of gasoline in Toronto is shown in the following figure. This refining margin or rack back margin has been increasing over time and is now approximately 10 cpl. The price of rack gasoline can therefore be estimated to be 10 cpl above the price of crude oil. 135

166 Figure 9-1 Rack Back Margin Toronto Jan-93 Jan-94 Jan-95 Rack Back Margin, Cents/Litre Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Rack Back Margin Linear (Rack Back Margin) In the following figure the feedstock price is plotted against both the US price of crude oil in US$/bbl and the ethanol price for the case that provides the same 20% IRR as the base case of 32 cpl gasoline ($28 US/bbl) plus tax incentives and $147/tonne corn cost. This is a single variable analysis. Corn ethanol produced in Ontario is the production scenario. 136

167 Figure 9-2 Crude Oil vs. Feedstock Costs Crude Oil Price US$/BBL Ethanol Price, cpl Can Feedstock, Can $/tonne Crude Oil Price Ethanol Price The previous analysis can be refined somewhat by also including the estimated impact of rising oil prices on the cost of natural gas. With the base case built on an oil price of $28 US/bbl and a combined incentive level of 24.2 cpl, and considering that production costs will increase as the oil price rises, then the cross over point for not requiring an incentive and producing the same IRR is approximately $64 US/bbl. The intermediate points can be estimated from the following figure. Note that the oil price as it is used here is the long term average price and not a temporary peak price. The oil industry is generally using a crude oil forecast price of $20 to $25/bbl for their capital decision making process. Oil prices need to have sustained periods of high prices before the long term forecasts can be increased. Investments in either new oil production fields or bioenergy facilities will have operating lives of 20 or more years and a long term view must be taken when deciding to make investments. 137

168 Figure 9-3 Oil Price Sensitivity Combined Incentive, cpl Crude Oil, US$/bbl Sensitivity Summary The following tornado diagram highlights the sensitivity of ethanol operations to feedstock costs and selling prices. In the diagram, an Ontario ethanol plant processing corn is used as the base case. The feedstock price is varied from a low of $110/tonne to a high of $200/tonne, with the base of $147/tonne. The ethanol selling price is moved from the base of 54.2 cpl to a low of 45 cpl and a high of 65 cpl. The plant size is changed from a low of 80 million litres per year to a high of 200 million litres per year and finally the impact of capital costs that range from a low of $50 million to a high of $90 million with the base case being $59.7 million. The base case produces a Net Income of $10,050,031 in the second year of operation (the first at full capacity). Note that the upper and lower estimates are not symmetrical for several of the variables. This figure has been prepared by altering a single variable. In reality two of the variables, feedstock cost and selling price probably have a secondary offsetting variable that is important. The DDG selling prices are correlated with feedstock costs but not perfectly. Higher feedstock costs would be partially offset by higher selling prices. Similarly, the natural gas costs and the ethanol selling prices have some correlation, which has not been considered in this single variable analysis. 138

169 Figure 9-4 Sensitivity to Key Variables Feedstock Cost Selling Price Plant Size "+$53 to -$37"/t "+/-" 10cpl "+80 to-40" million L Capital Cost "+$30 to- $10" million -5,000, ,000,000 10,000,000 15,000,000 20,000,000 Net Income Low Base High 139

170 10. FUEL ETHANOL SUPPLY COSTS This section of the report compares the Federal Government targets for ethanol production to the supply costs of producing the ethanol GOVERNMENT TARGETS The transportation sector represents the single largest source of Canada's greenhouse gas (GHG) emissions, accounting for about 27% of the total. Emissions from transportation are growing faster than the national average and are forecast to exceed the 1990 levels by over 25% in 2010 and 40% by Two transportation fuels that are manufactured from biomass feedstocks have been gaining momentum as suitable fuels for use in gasoline and diesel engines, either as neat fuels or in various blends. These fuels are ethanol, manufactured from grains and lignocellulosic feedstocks, and bio-diesel (methyl esters) manufactured from virgin vegetable oils, re-cycled oils, and animal fat. The 2003 Climate Change Plan for Canada included $154 million to be invested in measures to support Canada's efforts to reduce GHG emissions from transportation. The funds will support the industry to increase the supply of renewable alternative fuels, such as ethanol and bio-diesel, and the commercial transportation sector to make greater use of these fuels. The Federal Government included a production goal of 35% of Canadian gasoline to be blended with 10% ethanol by 2010 in its Climate Change Action plan. In 2010, this would likely require slightly more than 1.5 billion litres of ethanol. The following table summarizes the gasoline demand in Canada and projects the ethanol required to meet the target on a regional basis. It is recognized that the target could be reached by using more ethanol in some regions and less in other regions but at this stage of the analysis it is assumed that a uniform penetration rate is used in each province. Table 10-1 Gasoline Demand and Projected Ethanol Demand 2003 Gasoline Projected Gasoline Ethanol Demand Demand Demand 2010 million L million L million L British Columbia 4,630 5, Alberta 5,183 5, Saskatchewan 1,756 1, Manitoba 1,454 1, Ontario 15,388 17, Quebec 8,574 9, New Brunswick 1,060 1, Nova Scotia 1,239 1, Prince Edward Island Newfoundland Yukon North-West Territories Nunavut Canada 40,215 44,631 1,

171 10.2 SUPPLY COSTS A common set of assumptions is required to develop the supply costs for ethanol. It will be assumed that grain ethanol plants of 120 million litres per year of capacity are employed. The feedstock costs will be the ten year average prices. Natural cost gas costs will be based on a five year average price. The cellulose ethanol plants will be 170 million litres in size. Since we are interested in the supply cost a set of assumptions are required with respect to the financial structure. The plants will be financed with 50% equity and 50% debt with an interest rate of 6%. The ethanol selling price will be varied to provide an after tax rate of return on the shareholders initial investment of 10%. This rate of return is not likely high enough to attract the required equity and debt. The tax incentives provided by the Federal Government and some of the provinces are not a factor in the calculations since we are interested in the cost of ethanol production and not necessarily the ethanol selling prices Ethanol Supply Curve Using the financial models developed for the sensitivity analysis in the previous section and combining that information with the feedstock volumes identified earlier allows for the development of an ethanol supply curve. The data for the supply curve is summarized in the following table. Table 10-2 Ethanol Supply Data Province Feedstock Volume, million litres Supply Price, cpl Saskatchewan Wheat Alberta Wheat Manitoba Wheat Saskatchewan Barley Ontario Corn Quebec Corn All Cellulose 2, This information is shown graphically in the following figure. 141

172 Figure 10-1 Ethanol Supply Curve Ethanol Supply Cost, cpl ,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Ethanol Volume, million litres There are basically three portions to this curve. The initial low cost portion is ethanol produced from wheat in Western Canada, the middle portion is ethanol produced from barley and corn and the final portion is ethanol produced from cellulose. The cellulose portion costs can be expected to decline over time as more experience is gained with technology. The peak costs shown above represent the capital costs of the first plant and estimates of the operating costs obtained from the literature. The projected decline in costs as the volume increase reflects the expected reductions in capital costs for cellulose plants as experience is gained from building and operating the plants. The quality of the data used for estimating the cellulose ethanol costs is not as good as the quality of the data used to estimate the ethanol from starch costs. The target of 1.5 billion litres requires a long term average supply price of about 46 cents per litre. Due to the regional nature of the demand and the supply, a higher price of about 50 cents per litre would be required to account for transportation to market and regional production. It must also be noted that projects with a 10% after tax return in investors capital would likely have a difficult time raising debt finance. Due to the inherent volatility of commodity prices, investors and lenders are likely to require higher returns. 142

173 11. MARKET DEVELOPMENT Having developed an understanding of the fundamental economics of ethanol and a tool for assessing the profitability of ethanol plants, the focus now shifts to the development of a market for ethanol. The term market is used in the broadest sense in that it includes not only the consumption of the product but also the production. The ethanol market has been slower to develop in Canada than it has been in the United States. In order to understand the reasons for this it is first important to understand some of the fundamentals of market development. This is done in this chapter and then these fundamental approaches are assessed for the specific case of ethanol. Having done this, policy tools can then be developed and evaluated that will address the challenges that ethanol market development faces APPROACHES TO MARKET DEVELOPMENT The issue of creating markets for energy technologies has been the subject of considerable focus at the International Energy Agency over the past five years. In 2003, the IEA published a report Creating Markets for Energy Technologies that considered the process of market development. The technological and market developments required to transform the energy system will be conceived and implemented largely in the private sector. But success in this endeavour will not be determined exclusively by market forces. Governments that value the wider benefits of cleaner and more efficient energy technologies will work in partnership with market actors to ensure there are real opportunities for technologies to make the difficult transition from laboratory to market. This book is about the design and implementation of policies and programs for that purpose. Governments are motivated to assist not only because they have a responsibility for the pursuit of long-term societal goals and stewardship of the planet, but also because they understand that their policy settings help to determine whether markets develop and operate efficiently. Policymakers must therefore understand the markets concerned and they must have a highly developed capacity to mount effective programs. In both cases, experience is the best teacher. The IEA reviewed 22 case studies of what they determined where successful energy market developments in IEA countries over the past twenty years. In studying the cases, the IEA considered three perspectives on deployment policymaking. These three perspectives have developed over the last quarter of a century. The Research, Development and Deployment Perspective, which focuses on the innovation process, industry strategies and the learning that is associated with new technologies; The Market Barriers Perspective, which characterizes the adoption of a new technology as a market process, focuses on decisions made by investors and consumers, and applies the analytical tools of the economist; The Market Transformation Perspective, which considers the distribution chain from producer to user, focuses on the role of the actors in this chain in developing markets for new energy technologies, and applies the tools of the management sciences. In part, the three perspectives are three vocabularies for looking at the same issue but each adds something that the others are missing. The strength of the R&D plus Deployment 143

174 concept is its vision of the future and its focus on the technology itself, its costs and performance and the process of market entry through niche markets. The market barriers approach uses economic analysis to improve the understanding of the barriers to market entry and provides some discipline to the analysis of market intervention measures that could be used as policy tools. The Market Transformation perspective encourages sensitivity to the practical aspects of crafting policies that produce the desired effects. The IEA concluded that the adoption of clean energy technologies would not be likely to succeed unless all three perspective were considered and that it is necessary to: Invest in niche markets and learning in order to improve technology cost and performance; Remove or reduce barriers to market development that are based on instances of market failure; and Use market transformation techniques that address stakeholders' concerns in adopting new technologies and help to overcome market inertia that can unduly prolong the use of less effective technologies. Visually the IEA summarize the three perspectives as shown in the following figure. Figure 11-1 Overall Perspective on Technology Market Development Around this central theme, a close reading of the IEA case studies revealed more detailed messages about the nature of successful policy-making. Some key points are: 144

175 Deployment policy and programs are critical for the rapid development of cleaner, more sustainable energy technologies and markets. While technology and market development is driven by the private sector, government has a key role to play in sending clear signals to the market about the public good outcomes it wishes to achieve. Programs to assist in building new markets and transforming existing markets must engage stakeholders. Policy designers must understand the interests of those involved in the market concerned and there must be clear and continuous two-way communication between policy designers and all stakeholders. This calls for the assignment of adequate priorities and resources for this function by governments wishing to develop successful deployment initiatives. Programs must dare to set targets that take account of learning effects; i.e., go beyond what stakeholders focused on the here-and now may consider possible. The measures that make up a program must be coherent and harmonized both among themselves and with policies for industrial development, environmental control, taxation and other areas of government activity. Programs should stimulate learning investments from private sources and contain procedures for phasing out eventual government subsidies as technology improves and is picked up by the market. There is great potential for saving energy hidden in small-scale purchases, and therefore the gathering and focusing of purchasing power is important. Most consumers have little interest in energy issues per se, but would gladly respond to energy efficiency measures or use renewable fuels as part of a package with features they do care about. The three perspectives from the IEA have been considered here so that the issues that impede market development for ethanol and that require addressing from a policy perspective can be identified and addressed. In the rest of this chapter, the individual perspective is described in more detail and then the market development issues for ethanol are assessed from that perspective. The description of the different perspectives draws heavily on the IEA report but the tools found in each of the perspectives have been applied to the specific application of ethanol market development RESEARCH AND DEVELOPMENT + DEPLOYMENT Many groups consider product or technology development as a linear process which moves from research and development through to the end market as shown in the following figure, which is adapted from an Industry Canada discussion of the process. Figure 11-2 Stages of Development 145

176 In practice, the technology development process is cyclic in nature rather than linear with decisions being made at each stage having an influence on any eventual market success and in the later stages feedback between the market experiences and further technology development are very important. It is this feedback between deployment and R&D that is critical for success and that is why the IEA called this perspective Research & Development + Deployment. The market uptake of new bioenergy technologies has two positive effects. First, there is the physical effect of using renewable energy and the reductions in greenhouse gas emissions that would accompany this and the second effect is the learning effect of how to produce new energy sources less expensively and more effectively. It is the combined effect that produces the real impact for new technologies. In the case studies that the IEA considered they found that many government sponsored deployment programs defined success in terms of sales growth and market penetration. They found that this was too narrow a view and it neglected the link between the programs and private sector investment decisions. Decision makers in industry often consider the initial costs of market learning too high and too risky. Governments on the other hand have scarce public resources and can t bear the total cost of moving a new technology to market. However, in many of the case studies early government involvement in the deployment process played a crucial role in encouraging private sector involvement and in activating the learning process among the market participants. The IEA describes the process of the interaction between the governments and the private sector as shown in the following figure. Figure 11-3 Influences on the Learning Process from Public Policies Market 146

177 The figure summarizes how public sector and industry R&D interact to produce a virtuous cycle in which government support encourages corporations to try out new technologies in genuine market settings. The two vertical arrows represent the encouragement for industry R&D and production with a new technology brought about by government policies. Expanded output and sales stimulate the plus cycle in the diagram: industry R&D increases further, which enhances the technology stock, which in turn further stimulates production. The production increases also stimulate the learning process and the minus cycle in the diagram, resulting in reductions in the cost of production. This further stimulates sales and the cycle reinforces itself. The figure also indicates the role of experience and learning curves, which will be discussed next in this chapter. They provide a quantitative measure of market learning and the efficiency of the feed-back from market experience ( M ) to production and industry R&D, which leads to cost reductions and improved technology. The figure also provides a powerful argument in favour of government support for technology deployment, if government is supporting research it should also be supporting deployment. This argument has also made by several industry stakeholders. This gap between R&D funding and commercial funding is known as the Valley of Death and many consider it the largest barrier that new technology must overcome on the path to commercialization. The Valley of Death is not a phenomenon that is unique to Canada as references to it can be found in all of the developed countries Experience Curves There is overwhelming empirical evidence that deploying new technologies in competitive markets leads to technology learning, in which the cost of using a new technology falls and its technical performance improves as sales and operational experience accumulate. Experience and learning curves, which summarise the paths of falling technology costs and improving technical performance respectively, provide a robust and simple tool for analysing technology learning. Viewed from the Research, Development and Deployment (R&D + D) perspective, the curves provide a method to set targets and monitor programs; this includes a way of estimating program costs and providing a guide to phasing out programs as technologies mature and no longer require the support of deployment measures. The shape of the curves indicates that improvements follow a simple power law. This implies that relative improvements in price and technical performance remain the same over each doubling of cumulative sales or operational experience. As an example, the following figure shows that the prices of photovoltaic modules declined by more than 20 percent as each doubling of sales occurred during the period between 1976 and 1992 (IEA, 2000). Furthermore, the relationship remains the same over three orders of magnitude of sales. The experience curve is described mathematically as: Price at year t = P 0 * X -E where: P 0 = X = the price at one unit of cumulative production. the cumulative production of energy, sales, or a similar surrogate for the experience gained with the technology in year t. E = the experience parameter which characterizes the slope of the trend line when plotted on a log-log scale. 147

178 Progress in the reduction in energy price as technology travels down the experience curve is commonly reported in terms of the progress ratio, or PR. The PR is the energy price after double the cumulative production, as a fraction of the starting price at any point on the line and is calculated from the experience parameter (E) using the equation: PR = 2 -E. The Progress Ratio is usually presented as a percentage and in the PV case shown below, the progress ratio is 82%. Figure 11-4 Photovoltaic Experience Curve The straight line captures a very important feature of the experience curve. Anywhere along the line, an increase by a fixed percentage of the cumulative production gives a consistent percentage reduction in price. This means that for technologies having the same progress ratio, the same absolute increase in installed capacity will yield a greater cost decrease for young technologies (i.e., they learn faster) than old technologies. This also means that the same absolute increase in cumulative production will have more a dramatic effect at the beginning of a technology s deployment than it will later on. For well-established technology, such as oil refineries using conventional technology, the volume required to double cumulative sales may be of the order of 100 million bbls/day, so the experience effect will hardly be noticeable in stable markets. There is a significant amount of information on experience curves in the literature for many different technologies. Figure 11-5 shows the distribution of Progress Ratios for 108 case studies for a range of different products in the manufacturing sector (IEA, 2000). The average value of the progress ratio over these case studies was 82%. The consistency of the Progress Ratios over so many different technologies and products means that the approach can be used confidently, with some care, as a policy analysis tool for a range of technologies. 148

179 In the energy sector, experience curves have been prepared for many electricity production technologies in the European Union and that data is shown in Figure The dominant incumbent technologies have the lowest cost but interestingly the lowest progress ratios. This would suggest that over time, with the learning that arises from increased deployment and increased R&D that is driven by higher sales some of the new technologies will be able to challenge the incumbent fossil technologies on the basis of price while at the same time providing environmental benefits. Figure 11-5 Distribution of Progress Ratios for 108 Case Studies in the Manufacturing Sector 149

180 Figure 11-6 Electric Technologies in the EU, Note that Figure 11-4 uses the installed capacity of photovoltaic technologies for the quantity measure and Figure 11-6 uses the amount of electricity produced as the measure. The experience curves can be applied to both capital cost and the cost of production. The two measures may have different Progress Ratios, as there are costs other than capital (feedstock, operating costs, etc.) that influence the total production cost. The evidence from experience curves draws attention to the need to provide learning opportunities for new technologies in markets for energy services. That typically means that a supplier of energy services will have to incur costs that are greater than those incurred when incumbent technologies are used. Figure 11-7 illustrates the point with the experience curve for photovoltaic modules. 150

181 Figure 11-7 Projection of Break Even Points In this example, for photovoltaic systems to compete against currently used technologies in central power stations, the cost of modules has to be brought down to 0.5 US$/Wp, indicated by the horizontal line marked Price competition with incumbent technology in the diagram. The experience curve represents the price necessary for a producer of PV modules to cover the cost of production; however, in markets dominated by the incumbent technologies the producer will not obtain this price. Thus, the shaded triangle represents the extra cost, the learning investments, that will have to be covered from other sources if the market for PVelectricity is to expand and the cost of production with PV is to fall to the level of the current market price the breakeven point in the diagram. While not all technologies will require the same amount of money needed to reach the breakeven point for PV, it is clear that large sums of money are needed to finance learning investments. Should they come from investors in the private sector or government? The answer is probably both. The important point here is to be aware of the issues involved in efforts by government to activate private funding of learning investments and shorten the time horizon within which a technology will be considered a commercial endeavour. The magnitude of the learning investment may also be influenced by the economies of scale. For many of the conversion technologies where the capital cost of the infrastructure is a significant part of the overall product cost, large plants, with their inherent economies of scale, will have a lower required total learning investment than multiple small plants. This requires the development of large markets at the same time, feats that are not easy to synchronize for new products and new technologies. Note also that large is a relative term and different technologies may have different thresholds for large. A large biodiesel plant may produce less energy than a large ethanol plant for example. An interesting parallel could be drawn from the early oil sands development in Alberta. Government incentives in the form of reduced royalties and direct payments helped the plants survive in the early days when the production costs were over $40 per barrel, the experience that the plants obtained helped to drive down the production costs where they are now able to compete with much less government support. While no published experience 151

182 curves or progress ratio was found for the oil sands development there are a number or references to the concept of experience curves and cost reductions applied to oil sands in the literature. The IEA Creating Markets paper concludes its discussion of providing opportunities for technology learning with the following discussion of the role of private and public investments in deployment programs. As a matter of course, the private sector finances investment in some new technologies that have not yet reached the break-even point (for example, through venture capital). This can be understood by recognising the implications of the experience curve continuing to the right of the break-even point. The expectation is that the cost of using a new technology will fall below the current market price. Since incumbent technologies may still account for the larger market share, they will determine the market price for the energy service produced and the new technology will begin earning net profit that recovers the learning investments. However, existing firms tend to prefer incumbent technologies. Even if they are aware of opportunities for technology learning, they will often be cautious about investing in them and possibly for good reasons from their viewpoint. They may view the learning rate and the associated time path of learning benefits as too uncertain; and any given company may face the risk that some or all of the benefits of its learning investments can end up being captured by its competitors. Thus, if they make learning investments independently at all, they are likely to choose technologies that have already progressed substantially down the learning curve (though exceptions to this are plausible, such as in cases where new technologies have been developed through in-house R&D). Government deployment programs that provide assistance or incentives for private investment can thus make a crucial difference for major new technologies in the energy sector. Furthermore, the tendency towards inertia on the part of market actors creates a classic case for action from government an instance of what economists refer to as positive externalities. If private investors are not forthcoming to undertake learning investments in a technology that is judged to be market-ready, society will benefit if government (which may have a different risk profile and lower costs of capital) puts resources into encouraging and facilitating the investment in technology learning. For practical reasons governments are not in the habit of responding to this argument for just any technology, but in the case of new energy technologies that help to achieve the governmental goals of improving energy security and reducing greenhouse gas emissions, the case for action becomes very strong. This argument of course raises complex questions about picking winners and about how much cost governments should incur when it is not clear how large the future benefits will be and to whom they will accrue. This is a large subject and an exploration of it is beyond the scope of this book. As already noted, the case study project was focused on the design and implementation of successful deployment programs and was not intended to cover the process leading to decisions to establish programs in the first place. However, it is worth noting here that empirically-observed learning effects are helpful when benefit-cost analysis is used to establish whether there is a rationale for a specific deployment program. Some benefit-cost analyses neglect dynamic effects of this sort, in which case these analyses will be biased towards locking in existing technologies and their variants. As well, changes in a technology and organizational learning effects can bring about changes in the nature of an energy service, which means that price and cost observations for the new form of the service may not be directly comparable to prices and costs of the old form of the service. This can lead to inaccurate conclusions about the relative efficiencies of new and old technologies and could affect benefit-cost 152

183 calculations. Qualitative changes of this sort are also of interest because they can provide the basis for niche markets. As noted earlier it is important to consider that experience curves can be applied to different aspects of new technologies. One could consider the capital cost of the new technologies and how they might change as more plants are built or one could consider the cost of the energy product itself. This gives some insight in bioenergy opportunities because not all aspects of bioenergy are new. The biomass feedstock has generally been produced for many years and we are a long way down the learning curve for the production, harvesting and transportation of wheat or corn. This is not to say that further cost reductions are not possible but they will likely be slower than experienced with the conversion technology. With other feedstocks such as wood harvested from forest thinnings or straw and corn stover collection and transportation, there are still opportunities for learning for the collection, processing and transportation of these materials. Not all of the conversion technologies have reached the same stage of development so some have more potential for cost reductions than others do. The key point is that for emerging technologies the costs can change quite rapidly as the technology is developed. The current costs are not the same as the future costs. Given that the incumbent technologies have a much larger base, the rate of improvement in those technologies is slower than it is for new technologies and the price gap will be reduced over time Technology Diffusion Closely connected with the study of experience curves is the subject of technology diffusion, how new products and services move into the market place. There has been a significant amount of research and a number of publications concerning this subject in the past quarter century as well. The idea that the adoption of successful new products by buyers throughout an economy grows according to an S-shaped curve has long been used in the study of innovation. This S-Curve is illustrated in Figure

184 Figure 11-8 S Curves The determination of the actual shape of the S curve is quite complex. There are four main elements to the diffusion process. There is the innovation itself, the communication of the innovation, time and the social system that is attempting to adopt the new technology. Each element is critical to the successful diffusion of innovation or technology and is discussed briefly below. Innovations The characteristics of the technology, as perceived by the potential user, help to determine the rate at which the new technology is taken up. There are five important considerations to the adoption of new technology. The five factors are: the relative advantage of the new product, the degree to which it is consistent with the existing social values, the complexity of the innovation, the observability of the new product or system, and the ease with which the new system can be tried by potential users (trialability). The relative advantage of ethanol is the degree to which the ethanol is perceived to be better than the fuel it replaces. The degree of advantage can be measured in economic terms, but other factors such as social prestige, convenience and satisfaction also play a role in determining the perceived relative advantage. The true objective advantage is not as important as the perceived advantage. It is recognized and important to note that the expected continued improvement in the incumbent technology presents a moving target for new energy technologies and makes a relative advantage of an alternative technology more difficult to achieve and demonstrate. The relative advantage does and will change over time. Successful innovations must be consistent with the existing values, past experiences, and needs of potential adopters. Technologies that require changes with the values and norms of a society take much longer to adopt. The adoption of these incompatible innovations requires 154

185 the prior adoption of a new value system. For example, concern for the environment is a value that is becoming part of society s value system, but it is still a relatively small component of determining the relative advantage of a new technology. Innovations that are easy to understand by most members of society will be adopted quicker than difficult and complex technologies. For example, liquid biofuels that can be handled like gasoline and diesel are easier for the public to comprehend than a gaseous biofuel. Observability is another quality that influences the rate of adoption of new technologies. The easier it is for individuals to see the results of an innovation the more likely it is that they will adopt it. It is important for people to be able to try new things without making a permanent commitment. Innovations that are trialable generally are adopted quicker than those that are not. Bioenergy systems that are new and unproven will be slow to be adopted because of the high cost and high risk of a trial. These five qualities, relative advantage (real or perceived), compatibility, complexity, observability, and trialability have been identified by past diffusion research as the most important characteristics of innovations that determine their rate of adoption. Communications Communication is the process by which participants create and share information with one another in order to reach a mutual understanding. The essence of the diffusion process is the communication of a new idea from one individual to another. A communication channel is the means by which messages get from one participant to another. Mass media channels are effective at creating awareness of a new idea but interpersonal channels involving face to face exchanges are more effective at persuading individuals to accept a new idea. Research into the diffusion process has indicated that most individuals do not evaluate an innovation on the basis of scientific studies of its consequences. Instead, most people depend mainly upon a subjective evaluation of an innovation that is conveyed to them from other individuals like themselves who have previously adopted the innovation. This dependence on the experience of near peers suggests that the heart of the diffusion to potential adopters consists of modelling and imitation of those who have adopted previously. Therefore, diffusion is a very social process. Effective communications also has a financial component. Mass media awareness and interpersonal communications are expensive to implement but effective programs can be developed given sufficient financial resources. Some of the biofuels under consideration (biodiesel and ethanol for example) will require a very large number of people to become aware of the product and its relative advantages while others such as anaerobic digestion systems that produce electricity require a much more focussed communications strategy. The challenge of information dissemination for new technologies can be a real issue and many identify information dissemination as a potential role for government to play. Interestingly those stakeholders involved with ethanol and to a lesser degree biodiesel (products that will require mass communications) did not perceive this as a major barrier. Time Time is a third element in the diffusion process and a very important element. The time dimension is involved in diffusion in three ways: In the innovation decision process by which an individual passes from first knowledge of an innovation through its adoption or rejection, 155

186 in the relative earliness/lateness with which an innovation is adopted, and in an innovations rate of adoption in a system. The innovation decision process is the process through which an individual passes from first knowledge of innovation to forming an attitude toward the innovation, to a decision to adopt or reject, to implementation and use of the new idea, and to confirmation of this decision. There are therefore five main steps in the innovation decision process: knowledge, persuasion, decision, implementation, and confirmation. These five steps usually occur in time ordered sequence. There can be exceptions to the order such as when the decision that is taken before persuasion. Not all individuals proceed through the decision process at the same rate. An individual can be more or less innovative than another person. Individuals can be ranked in order of their innovativeness using the following five classes: innovators, early adopters, early majority, late majority, and laggards. Individuals within each class of innovators will have much in common. It is important to note that each class of innovator will rank the relative advantages of attributes differently, the relative importance of mass media communications vs. interpersonal communication, and whether they are active or passive information seekers. It should also be recognized that it is extremely difficult to develop innovations that appeal to the majority if the innovation does not also have some (but not necessarily the same) appeal to the innovators and early adopters. The sequential and social nature of the process makes it difficult and extremely unlikely that steps can be skipped to save time. Time is also an important parameter of the learning and experience curves. It is also an important aspect of the political and policy process but unfortunately, the time horizons of the diffusion process do not always align with the horizons of the political and policy process. This lack of alignment increases the complexity of the development process. Social System The social system is the fourth element of the diffusion process. The members of the social system are engaged in joint problem solving to accomplish a common goal. The members may be individuals, informal groups, or organizations. The most innovative members are not always influential in the decision making process as they often have low credibility due to their willingness to try all new things. Opinion leaders and change agents, people who are able to persuade others to change are the most influential members in the social system. New technologies will not be adopted without these members. The social system has another important influence on the diffusion of new ideas. Innovations can be accepted or rejected by one individual, by the entire system, by a collective, or authoritative decision. The individual optional innovative decisions are made independent of 156

187 other members. These decisions are the classical means by which new ideas have spread through society. Collective decisions are made by consensus of the members of a group. The establishment of car pools would be an example of a collective decision. Authority decisions are those made by a few individuals who have the power, status, or technical expertise to make decisions for all members of the society. Individuals have little or no influence on the decision. Relevant examples would be the establishment of new standards for fuels or vehicle fuel economy, or the use of biodiesel blends in a companies diesel fuel products. The fourth type of decision is contingent decision, this is a sequential decision of two or more of the other types of decisions. This type can be made only after another decision has been made. They tend to have long implementation times. They are also typical of the type found with alternative fuels that require both new fuels and vehicles to be introduced at the same time. Specific characteristics of new technologies can add value that makes potential buyers with special needs ready to pay extra for energy services produced with them instead of with incumbent technologies. Examples of characteristics (relative advantages) that may provide the basis for a niche market are low emissions or better performance. These early buyers are often called innovators or early adopters as shown in the figure. The niche markets may be small relative to the total potential for a technology, but they can be important from the viewpoint of providing learning opportunities. Making use of them in deployment programs can help both to shorten the time before a new technology will be viewed as a viable commercial endeavour and provide a source of business funding for learning investments. Market leaders often use a niche market in developing a challenger to an existing technology, viewing it as a stepping stone towards a mass market. The fact that these early adopters are willing to pay more for products that meets their needs means that less money must be invested in the learning investments by governments and industry. Ideally, there is a match between the size of the niche market and a commercial production facility. This allows one or more facilities to be constructed to satisfy just the niche market. In many cases, this is not possible and the niche market opportunity can absorb only a small portion of a commercial plant output and little benefit can be gained from the niche. This is more of a problem in Canada, with its small geographically diverse markets, than it is in the United States or Europe with their much larger markets. These larger markets offer better opportunities for matching the size of niche markets with volume of products produced at a commercial production scale. Figure 11-9 illustrates how a niche market can lead to earlier commercialisation of a technology and that the bill for learning investments can be split between public and private sources. 157

188 Figure 11-9 Experience Curves and Niche Markets Consider the following scenario. In the situation marked by A, the cost of the challengertechnology is still higher than the willingness to pay in the niche market. A financial incentive can provide the difference between the actual cost and the price in the niche market. As demand at the upper end of the niche market is satisfied, the price on the niche market is reduced, but learning has also reduced the cost of providing the product. In situation 'B, cost is below the willingness-to-pay in the niche market and no public money is needed to finance learning investments, though it may still be necessary to assist with indirect support (e.g., labelling schemes and other information devices). In situations C and D, the market leader may be in the enviable position of being able both to brand his products for a niche market that is very profitable (C) and to let one of his lesser brands feature a low-price version of the product that competes with the incumbent technology (D). The characteristics of the actors in the diffusion curve shown above are summarized in the following table. It is the innovators and early adopter characteristics that are of particular interest since those are the proponents that are willing to pay more and can help to drive the experience curve. 158

189 Table 11-1 Innovators enthusiast Consumer Characteristics Adopter Type Characteristic Role And Size Venturesome; Enjoys the risk of Market drivers. Want more being on the cutting edge; Demands technology, better technology. performance. Early Adopters visionaries Well connected; Integrated in the main-stream of social system; Project oriented; Risk takers; Willing to experiment; Self-sufficient; Horizontally connected and acts as their peers. Large Difference between groups above and below. Early majority pragmatists Late majority conservatives Laggards sceptics Deliberate; Process oriented; Risk averse; Want proven applications; May need significant support; Vertically connected and acts as their superiors. Sceptical; Does not like change in general. Changes under pressure from the majority. Traditional; Point of reference is the good old days ; Actively resists innovations. Followers of the market. Want solutions and convenience. Economic/ power interest different from status quo? Creating and exploiting niche markets is an efficient strategy for a deployment program, both to provide learning investments from private sources and to stimulate organisational learning among market actors Ethanol Market Development from a R&D + D Perspective The development of an ethanol market in Canada can be evaluated from the R&D + D perspective. The application of the key aspects of this perspective are discussed below Experience Curves The potential for learning experiences should be considered from both a plant capital and operating cost perspective and a feedstock perspective. From a plant perspective, the different technologies for ethanol production have different potentials for cost reductions. Fuel ethanol from starch or sugar has grown rapidly in the United States and Brazil over the past two decades. In both cases, there have been large reductions in plant capital costs and production costs. In the United States, for example, a 190 million litre per year ethanol plant cost about $150 million (1980) dollars to build in the early 1980 s. Today a 140 million litre per year plant can be built for about $50 million (US 2004) dollars. There is insufficient information available to develop a full curve but data is available for 1980, 1982, 1994, 1996, 1998 and 2003 and that data is plotted against the cumulative production the progress ratio from the data points is 84%, exactly what one would have expected. Some (SRI, 2004) have found that for the chemical industry the experience curve 159

190 is more accurate if cumulative production rather than cumulative capacity is plotted against capital cost. This is a result of the capacity data being notoriously inaccurate. Figure US Ethanol Experience Curve 10 Capital Cost, US$/USG y = x Cumulative Production, Million L The Brazilians have published their own experiences curves for fuel ethanol as shown in the following figure. This particular curve includes currency fluctuations between Brazil and the United States and the impact of feedstock costs. Here the production cost is plotted against the cumulative capacity. The Progress Ratio is 82% for the most recent part of the curve. Figure Brazilian Ethanol Experience Curve In Canada, we have only built a few ethanol plants in the last decade. The capital cost for the CAI Chatham plant was approximately $150 million for a 150 million litre per plant. This is far 160