CHEMINFO
Ethanol Production in Alberta
Final Report
April 2000
Prepared For:
Interdepartmental Ethanol Committee
Government of Alberta
CHEMINFO
Ethanol Production in Alberta
Final Report
April 2000
Prepared For:
Interdepartmental Ethanol Committee
Government of Alberta
c/o Alberta Grain Commission
Alberta Agriculture, Food and Rural Development
#305, 7000-113 Street
Edmonton, Alberta
T6H 5T6
Prepared By:
Cheminfo Services Inc.
1706 Avenue Rd., Suite 4
Toronto, ON
L3R 7W5
Telephone: (416) 785-9051
Fax: (416) 785-9876
e-mail: Proestos@netcom.ca
In association with:
(S&T)2 Consultants Inc.
Vancouver, BC
and
Cemcorp Ltd.
Mississauga, ON
CHEMINFO
Table of Contents
1.
EXECUTIVE SUMMARY................................................................................................................. 1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2.
INTRODUCTION..............................................................................................................................22
2.1
2.2
3.
OVERALL ETHANOL INDUSTRY STRUCTURE ....................................................................................24
GOVERNMENT INFLUENCES .............................................................................................................24
ALBERTA’S UNIQUE ECONOMIC CONTEXT ......................................................................................27
ETHANOL MARKET OVERVIEW ........................................................................................................33
WHEAT GLUTEN MARKET OVERVIEW .............................................................................................54
COMPARISON OF FUEL ALTERNATIVES ...............................................................................57
4.1
4.2
4.3
4.4
4.5
4.6
4.7
5.
BACKGROUND..................................................................................................................................22
OVERVIEW OF RESEARCH METHODOLOGY ......................................................................................23
ETHANOL BUSINESS SYSTEM ....................................................................................................24
3.1
3.2
3.3
3.4
3.5
4.
INTRODUCTION ................................................................................................................................. 1
SUMMARY OF CONCLUSIONS ............................................................................................................ 1
ETHANOL MARKET OVERVIEW ......................................................................................................... 6
PRODUCTION, ENERGY, AND ENVIRONMENTAL EMISSIONS .............................................................. 7
COMPARISON OF FUEL ALTERNATIVES ............................................................................................15
ETHANOL PLANT ECONOMICS..........................................................................................................15
SUMMARY OF SOCIO-ECONOMIC STUDIES .......................................................................................17
POTENTIAL SOCIO-ECONOMIC IMPACTS FOR ALBERTA ...................................................................18
STAKEHOLDER POLICY INPUT AND ADDITIONAL CONSIDERATIONS ................................................19
SUMMARY ........................................................................................................................................57
VEHICLE TECHNOLOGIES AND EMISSION STANDARDS .....................................................................57
GASOLINE AND HYDROCARBON BLENDING COMPONENTS ..............................................................59
OXYGENATES ...................................................................................................................................66
PROPANE..........................................................................................................................................70
NATURAL GAS .................................................................................................................................72
BIODIESEL........................................................................................................................................73
ETHANOL PRODUCTION TECHNOLOGY ...............................................................................76
5.1
5.2
5.3
5.4
5.5
ETHANOL PRODUCTION MODELS .....................................................................................................76
RAW MATERIALS .............................................................................................................................78
ETHANOL PRODUCTION MODELS FOR ALBERTA ..............................................................................84
ETHANOL PLANT ECONOMICS..........................................................................................................89
TECHNOLOGY DEVELOPMENTS ........................................................................................................96
6.
ETHANOL LIFECYCLE ANALYSIS FOR ENERGY AND GREENHOUSE GAS
EMISSIONS .................................................................................................................................................98
6.1
6.2
6.3
6.4
INTRODUCTION ................................................................................................................................98
GREENHOUSE GAS EMISSIONS .......................................................................................................102
ENERGY INPUTS AND OUTPUTS ......................................................................................................121
OTHER ENVIRONMENTAL CONSIDERATIONS ..................................................................................129
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7.
REVIEW OF ETHANOL SOCIO-ECONOMIC STUDIES ........................................................148
7.1
7.2
7.3
7.4
8.
SUMMARY ......................................................................................................................................148
UNITED STATES STUDIES ...............................................................................................................148
CANADIAN STUDIES .......................................................................................................................156
STUDIES IN OTHER COUNTRIES ......................................................................................................159
POTENTIAL SOCIO-ECONOMIC IMPACTS FOR ALBERTA .............................................161
8.1
8.2
8.3
8.4
8.5
8.6
8.7
8.8
8.9
8.10
8.11
9.
SUMMARY ......................................................................................................................................161
SCOPE AND METHODOLOGY ..........................................................................................................163
IMPACTS ON AGRICULTURAL SECTOR............................................................................................166
IMPACTS FROM ETHANOL PRODUCTION .........................................................................................170
IMPACTS FROM CAPITAL CONSTRUCTION ......................................................................................172
IMPACTS FROM GOVERNMENT EXPENDITURES ..............................................................................173
IMPACTS ON CONSUMERS ..............................................................................................................173
IMPACTS ON OIL, REFINING AND GASOLINE MARKETING SECTOR ................................................174
NET IMPACTS ON ECONOMIC ACTIVITY .........................................................................................176
EMPLOYMENT ...........................................................................................................................176
GOVERNMENT REVENUES .........................................................................................................177
ETHANOL POLICIES IN NORTH AMERICA ..........................................................................180
9.1
10.
STAKEHOLDER INPUT AND ADDITIONAL CONSIDERATIONS ......................................187
10.1
10.2
10.3
10.4
10.5
10.6
11.
ETHANOL PROGRAMS IN THE UNITED STATES AND CANADA.........................................................180
INTRODUCTION..........................................................................................................................187
SCOPE OF ANALYSIS..................................................................................................................188
ENVIRONMENT PERSPECTIVES ..................................................................................................189
REFINERY, WHOLESALER, RETAILER CONSIDERATIONS ...........................................................190
INCENTIVES AND ETHANOL PLANT FINANCING .........................................................................197
ECONOMIC AND TRADE CONSIDERATIONS ................................................................................203
REFERENCES .................................................................................................................................213
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Table of Tables
TABLE 1: SUMMARY OF RESULTS AND CONCLUSIONS OF THIS STUDY ........................................................... 3
TABLE 2: NORTH AMERICAN SUPPLY AND DEMAND TRENDS FOR ETHANOL .................................................. 6
TABLE 3. SUMMARY OF ENERGY REQUIREMENTS AND GREENHOUSE GAS EMISSIONS FROM GRAIN
PRODUCTION ......................................................................................................................................... 8
TABLE 4. FULL CYCLE ENERGY BALANCES FOR TRANSPORTATION FUELS ..................................................... 9
TABLE 5. SUMMARY OF GREENHOUSE GAS EMISSIONS FROM ALTERNATIVE FUELS ...................................... 9
TABLE 6. SUMMARY OF GREENHOUSE GAS EMISSIONS FOR GASOLINE AND ETHANOL .................................11
TABLE 7. SUMMARY OF GREENHOUSE GAS EMISSIONS FROM 10% ETHANOL BLENDS ..................................12
TABLE 8. SUMMARY OF THE ENVIRONMENTAL IMPACTS OF A 10% ETHANOL BLEND ..................................13
TABLE 9: AMBIENT AIR QUALITY IN EDMONTON AND CALGARY ..................................................................13
TABLE 10: SUMMARY OF KEY PROPERTIES OF GASOLINE BLENDING COMPONENTS .....................................15
TABLE 11: SIZE AND DESCRIPTION OF MODEL FACILITIES .............................................................................16
TABLE 12: SUMMARY OF REVENUES AND OPERATING EXPENSES FOR MODEL PLANTS .................................16
TABLE 13: SUMMARY OF SOCIO-ECONOMIC IMPACTS ....................................................................................18
TABLE 14: ECONOMIC DATA FOR ALBERTA AND COMPARISON TO CANADA .................................................29
TABLE 15: OIL PRODUCTION IN ALBERTA ......................................................................................................30
TABLE 16: ALBERTA’S OIL & GAS ENERGY PRODUCTION AND CONSUMPTION .............................................30
TABLE 17: MAJOR PARTICIPANTS IN ALBERTA OIL AND GAS, PETROLEUM REFINING AND FUELS MARKETING
INDUSTRIES...........................................................................................................................................31
TABLE 18: ALBERTA’S MAJOR PETROCHEMICAL INDUSTRY PARTICIPANTS ..................................................33
TABLE 19: ECONOMIC DATA ON ALBERTA’S AGRICULTURE SECTOR ............................................................33
TABLE 20: NORTH AMERICAN CAPACITY, DEMAND TRENDS FOR ETHANOL .................................................34
TABLE 21: GROWTH IN GLOBAL ETHANOL PRODUCTION...............................................................................35
TABLE 22: NORTH AMERICAN ETHANOL ANNUAL CAPACITY TREND............................................................37
TABLE 23: TOTAL NORTH AMERICAN ETHANOL DEMAND ............................................................................38
TABLE 24: POSITION OF ETHANOL IN THE ESTIMATED NORTH AMERICAN GASOLINE-OXYGENATE MARKET
.............................................................................................................................................................39
TABLE 25: REGIONAL U.S. ETHANOL CAPACITY TRENDS ..............................................................................39
TABLE 26: YEAR 2000 CAPACITY OF U.S. ETHANOL PRODUCERS .................................................................40
TABLE 27: TREND IN UNITED STATES ETHANOL DEMAND.............................................................................42
TABLE 28: POSITION OF ETHANOL IN THE U.S. GASOLINE-OXYGENATE MARKET ........................................43
TABLE 29: POSITION OF ETHANOL IN TOTAL ON-ROAD PLUS OFF-ROAD FUEL MARKETS ...........................43
TABLE 30: TREND IN REGIONAL CANADIAN ETHANOL CAPACITY .................................................................44
TABLE 31: CANADIAN ETHANOL PLANT CAPACITIES.....................................................................................45
TABLE 32: TREND IN CANADIAN ETHANOL DEMAND ....................................................................................45
TABLE 33: POSITION OF ETHANOL IN THE ESTIMATED CANADIAN GASOLINE-OXYGENATE MARKET ..........46
TABLE 34: PROVINCIAL RATIOS OF GASOLINE USE FOR PASSENGER CARS VERSUS FARM VEHICLES ...........47
TABLE 35: PROJECTED TREND IN VEHICLE POPULATION IN ALBERTA ...........................................................47
TABLE 36: TRENDS IN TRANSPORTATION FUEL DEMAND IN ALBERTA ..........................................................48
TABLE 37: APPROXIMATE NUMBER OF RETAIL STATIONS IN PRAIRIE PROVINCES, 1997 ..............................48
TABLE 38: TREND IN CANADIAN ETHANOL TRADE ........................................................................................49
TABLE 39: ETHANOL TRADE NOVEMBER 1999 YEAR-TO-DATE ....................................................................49
TABLE 40: CANADIAN ETHANOL EXPORTS BY DESTINATION, 1998 ...............................................................50
TABLE 41: TREND IN DEMAND FOR ETHANOL IN PNW ..................................................................................51
TABLE 42: ETHANOL CAPACITY IN PNW .......................................................................................................51
TABLE 43: SOME ETHANOL PRODUCERS IN PNW ..........................................................................................51
TABLE 44: PROPOSED ETHANOL CAPACITY IN THE PNW...............................................................................52
TABLE 45: CANADIAN PRICING DATA FOR ETHANOL.....................................................................................54
TABLE 46: UNITED STATES IMPORTS OF WHEAT GLUTEN .............................................................................55
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TABLE 47: IDENTIFIED US GLUTEN/ETHANOL PRODUCERS ...........................................................................56
TABLE 48: SUMMARY OF KEY PROPERTIES OF GASOLINE BLENDING COMPONENTS .....................................57
TABLE 49. LIGHT-DUTY GASOLINE VEHICLE STANDARDS IN CANADA EXHAUST EMISSIONS (G/KM) ...........58
TABLE 50. CALIFORNIA LOW EMISSION VEHICLE STANDARDS ......................................................................59
TABLE 51: TYPICAL CHARACTERISTICS OF REFINERY STREAMS ....................................................................62
TABLE 52: EMISSION RESPONSE TO FUEL PARAMETER CHANGES ..................................................................62
TABLE 53: US EPA SULPHUR REDUCTIONS ...................................................................................................66
TABLE 54: INFORMATION ON GASOLINE OXYGENATES ..................................................................................66
TABLE 55: US COMPLEX MODEL RESULTS FOR BASELINE GASOLINE WITH AND WITHOUT 11% MTBE .....67
TABLE 56: US COMPLEX MODEL RESULTS FOR BASELINE GASOLINE WITH AND WITHOUT 12.5% ETBE ...68
TABLE 57: US COMPLEX MODEL RESULTS FOR BASELINE GASOLINE WITH AND WITHOUT 5.7% ETHANOL 70
TABLE 58: IMPACT OF BIODIESEL ON EXHAUST EMISSIONS ...........................................................................75
TABLE 59: TYPICAL PROPERTIES OF DIESEL FUEL AND BIODIESELS ..............................................................76
TABLE 60: EXAMPLES OF PRODUCTION/BUSINESS MODELS IN ETHANOL INDUSTRY ....................................77
TABLE 61: AGRONOMIC DATA FOR ALBERTA CROPS COMPARED TO CORN...................................................80
TABLE 62: ENERGY REQUIREMENTS FOR CROP PRODUCTION ........................................................................82
TABLE 63: GREENHOUSE GAS EMISSIONS FOR WHEAT, BARLEY AND CORN PRODUCTION ...........................83
TABLE 64: ENERGY REQUIREMENTS FOR CPS WHEAT WITH AND WITHOUT MANURE.................................83
TABLE 65: GREENHOUSE GAS EMISSIONS FOR WHEAT AND CORN PRODUCTION ..........................................83
TABLE 66: SUMMARY OF ETHANOL PLANT INPUTS AND OUTPUTS.................................................................85
TABLE 67: SUMMARY OF REVENUES AND OPERATING EXPENSES FOR MODEL PLANTS .................................89
TABLE 68: SIZE AND DESCRIPTION OF MODEL FACILITIES .............................................................................90
TABLE 69: ESTIMATED CAPITAL AND CONSTRUCTION EMPLOYMENT ...........................................................92
TABLE 70: REVENUES FOR MODEL PLANTS ...................................................................................................93
TABLE 71: WHEAT REQUIREMENTS FOR MODEL PLANTS ..............................................................................93
TABLE 72: PERMANENT EMPLOYMENT ..........................................................................................................95
TABLE 73: UTILITY REQUIREMENTS FOR MODEL PLANTS..............................................................................95
TABLE 74: BASELINE VEHICLE FUEL ECONOMY FOR MODELLING USE .......................................................103
TABLE 75: CRUDE OIL SLATE MODELED .....................................................................................................104
TABLE 76: COMPARISON OF GREENHOUSE GAS EMISSIONS FROM THREE STUDIES.....................................104
TABLE 77: GREENHOUSE GAS EMISSIONS FROM SYNTHETIC CRUDE PRODUCTION .....................................105
TABLE 78: CO2 EQUIVALENT EMISSIONS FOR GASOLINE AND LOW SULPHUR GASOLINE FOR 2000 ............105
TABLE 79: CO2 EQUIVALENT EMISSIONS FOR GASOLINE AND LOW SULPHUR GASOLINE ............................106
TABLE 80: EMISSION FACTORS IMPACTING LAND USE EMISSIONS ..............................................................107
TABLE 81: CO2 EQUIVALENT UPSTREAM EMISSIONS FOR GASOLINE AND ETHANOL FROM AN INTEGRATED
CATTLE FEEDING OPERATION ............................................................................................................108
TABLE 82: CO2 EQUIVALENT VEHICLE EMISSIONS FOR GASOLINE AND ETHANOL FROM AN INTEGRATED
CATTLE FEEDING OPERATION ............................................................................................................109
TABLE 83: CO2 EQUIVALENT UPSTREAM EMISSIONS FOR GASOLINE AND ETHANOL FROM A CONVENTIONAL
DRY MILL ETHANOL PLANT ...............................................................................................................110
TABLE 84: CO2 EQUIVALENT VEHICLE EMISSIONS FOR GASOLINE AND ETHANOL FROM A CONVENTIONAL
DRY MILL ETHANOL PLANT ...............................................................................................................111
TABLE 85: CO2 EQUIVALENT UPSTREAM EMISSIONS FOR GASOLINE AND ETHANOL FROM A COMBINED
ETHANOL AND GLUTEN OPERATION ...................................................................................................112
TABLE 86: CO2 EQUIVALENT FULL CYCLE EMISSIONS FOR GASOLINE AND ETHANOL FROM A COMBINED
ETHANOL AND GLUTEN OPERATION ...................................................................................................113
TABLE 87: IMPACT OF MANURE USE AND METHANE CREDIT FROM DG ......................................................113
TABLE 88: IMPACT OF LOWER EXHAUST EMISSIONS OF CARBON MONOXIDE AND HYDROCARBONS ON FULL
CYCLE EMISSIONS ..............................................................................................................................114
TABLE 89: SUMMARY AND COMPARISON .....................................................................................................115
TABLE 90: CO2 EQUIVALENT EMISSIONS FOR NATURAL GAS AND GASOLINE .............................................116
TABLE 91: CO2 EQUIVALENT EMISSIONS FOR PROPANE AND GASOLINE .....................................................117
TABLE 92: CO2 EQUIVALENT EMISSIONS FOR GASOLINE, DIESEL AND METHANOL FOR 2000 .....................118
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TABLE 93: CO2 EQUIVALENT EMISSIONS FOR A METHANOL FUEL CELL VEHICLE AND GASOLINE. ............118
TABLE 94: CO2 EQUIVALENT EMISSIONS FOR DIESEL, BIODIESEL FOR 2000 ...............................................120
TABLE 95: CO2 EQUIVALENT EMISSIONS FOR DIESEL AND BIODIESEL IN A HEAVY-DUTY TRUCK ..............120
TABLE 96: ENERGY DISTRIBUTION OF ENERGY USED IN CRUDE OIL PRODUCTION ....................................122
TABLE 97: ENERGY CONSUMED IN THE PRODUCTION OF GASOLINE AND DIESEL FUEL ...............................122
TABLE 98: ENERGY BALANCE FOR INTEGRATED ETHANOL PLANT FEEDLOT COMPARED TO GASOLINE. ....123
TABLE 99: ENERGY BALANCE FOR A CONVENTIONAL DRY MILL ETHANOL PLANT ...................................123
TABLE 100: ENERGY BALANCE FOR GLUTEN AND ETHANOL PLANTS COMPARED TO GASOLINE ................125
TABLE 101: ENERGY BALANCE SUMMARY ..................................................................................................126
TABLE 102: ENERGY CONSUMED IN THE PRODUCTION OF GASOLINE AND COMPRESSED NATURAL GAS. ...127
TABLE 103: ENERGY CONSUMED IN THE PRODUCTION OF GASOLINE AND PROPANE ..................................127
TABLE 104: ENERGY CONSUMED IN THE PRODUCTION OF GASOLINE AND METHANOL ..............................128
TABLE 105: ENERGY CONSUMED IN THE PRODUCTION OF BIODIESEL AND DIESEL FUEL ............................128
TABLE 106: 1995 EMISSIONS FROM GASOLINE VEHICLES IN ALBERTA........................................................130
TABLE 107: CALCULATED 1995 VEHICLE EMISSION RATES ........................................................................131
TABLE 108: COMPARISON OF ENVIRONMENT CANADA EMISSION RATES AND RATES CALCULATED BY
CALIBRATED DELUCCHI MODEL ........................................................................................................132
TABLE 109: AIR TOXICS EMISSION RATES ...................................................................................................134
TABLE 110: FULL CYCLE EMISSIONS OF INDIVIDUAL GHG AND POLLUTANTS ............................................135
TABLE 111: EPA CONCLUSIONS ON CO EFFECTS FROM THE USE OF OXYGENATED GASOLINE ON LIGHT
DUTY GASOLINE POWERED VEHICLES ...............................................................................................137
TABLE 112: EPA CONCLUSIONS ON HC EFFECTS FROM THE USE OF 10% ETHANOL ON LIGHT DUTY
GASOLINE POWERED VEHICLES..........................................................................................................138
TABLE 113. COMBINED IMPACT OF 10% ETHANOL WITH ONE PSI HIGHER VAPOUR PRESSURE ON TOTAL
HYDROCARBON EMISSIONS. ...............................................................................................................142
TABLE 114: US COMPLEX MODEL RESULTS FOR BASELINE GASOLINE WITH AND WITHOUT 10% ETHANOL
...........................................................................................................................................................143
TABLE 115. PARTICULATE MATTER EMISSIONS FOR TIER 0 AND TIER 1 VEHICLES ....................................143
TABLE 116. FULL CYCLE EMISSIONS OF INDIVIDUAL GASES AND POLLUTANTS ..........................................145
TABLE 117: EMISSION TESTING OF CME/DIESEL BLENDS ...........................................................................146
TABLE 118: SUMMARY OF SOCIO-ECONOMIC IMPACTS ................................................................................162
TABLE 119: SUMMARY OF AGRICULTURAL SECTOR IMPACTS .....................................................................166
TABLE 120. CHANGES IN GROSS FARM INCOME FROM ETHANOL PRODUCTION IN ALBERTA ......................167
TABLE 121: TOTAL FARM ECONOMIC ACTIVITY ..........................................................................................170
TABLE 122: ETHANOL PLANT EXPENDITURES..............................................................................................171
TABLE 123: ECONOMIC ACTIVITY FROM ETHANOL PRODUCTION ................................................................172
TABLE 124. ECONOMIC ACTIVITY FROM ETHANOL PLANT CONSTRUCTION ................................................172
TABLE 125: SUMMARY OF ECONOMIC ACTIVITY FROM ETHANOL PRODUCTION IN ALBERTA .....................176
TABLE 126. CALCULATED EMPLOYMENT IMPACTS ......................................................................................177
TABLE 127: KEY ALBERTA 1999 ECONOMIC DATA .....................................................................................177
TABLE 128: IMPACT OF AN EXPANDED ETHANOL PROGRAM ON GOVERNMENT REVENUES ........................179
TABLE 129: U.S. STATE GOVERNMENT POLICIES SUPPORTING ETHANOL ...................................................181
TABLE 130: PROVINCIAL TAX EXEMPTIONS FOR ETHANOL TRANSPORTATION FUEL ..................................185
TABLE 131: CPPI MEMBER COMPANIES – 1999 ...........................................................................................188
TABLE 132: AMBIENT AIR QUALITY IN EDMONTON AND CALGARY ............................................................190
TABLE 133: CURRENT AND PROPOSED CANADIAN AIR QUALITY STANDARDS ............................................190
TABLE 134: CANADIAN MARKET APPLICATION FOR PROPANE AND BUTANE ..............................................191
TABLE 135: HISTORICAL USES FOR BUTANE AND PROPANE ........................................................................192
TABLE 136: OCTANE RATINGS AND U.S. PRICES FOR SOME OCTANE PRODUCTS .......................................193
TABLE 137: PROJECTED OF GASOLINE AND DIESEL CONSUMPTION FOR ALBERTA AND G/D RATIOS FOR
MAJOR PROVINCES .............................................................................................................................194
TABLE 138: APPROXIMATE ALBERTA GASOLINE DELIVERY ECONOMICS ....................................................204
TABLE 139: ESTIMATED ETHANOL DELIVERY COSTS TO RETAIL.................................................................204
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TABLE 140: WHOLESALER INCENTIVE TO HANDLE, DISTRIBUTE ETHANOL AT DIFFERENT CRUDE OIL AND
RELATED GASOLINE RETAIL PRICES ..................................................................................................205
TABLE 141: AVERAGE ETHANOL PROFITS FOR MINNESOTA BETWEEN 1994 AND 1996 .............................206
Table of Figures
FIGURE 1: MAJOR COMPONENTS OF ETHANOL BUSINESS SYSTEM .................................................................25
FIGURE 2. GASOLINE PROCESSING IN A MODERN REFINERY ..........................................................................61
FIGURE 3: BIODIESEL PRODUCTION PROCESS.................................................................................................73
FIGURE 4: FULL CYCLE INCLUDING FUEL AND VEHICLE CYCLES ..................................................................98
FIGURE 5: GRAIN TO ETHANOL AND PETROLEUM TO GASOLINE FUEL CYCLES .............................................98
FIGURE 6. CORN PRICE EQUATION ...............................................................................................................169
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1. Executive Summary
1.1 Introduction
The Alberta Ministry of Agriculture, Food and Rural Development has had an “ethanol policy” since 1993.
The policy offers a guarantee that the exemption of Provincial fuel tax payable on vehicle fuel will continue
for a period of five years after the start-up of an ethanol production plant. The exemption is currently 9
¢/litre of ethanol sold in the province. The policy is being reviewed in 2000. The Interdepartmental Ethanol
Committee has been established to review the need for a new policy and to make recommendations to the
Provincial Government of Alberta. The committee consists of representatives from Alberta Agriculture,
Food and Rural Development, Alberta Grain Commission, Alberta Economic Development, Alberta
Environment, Alberta Infrastructure, and Alberta Resource Development. This report provides information
and analyses on the following elements to assist in the committee’s policy review process:






energy and greenhouse gas (GHG) emissions comparison of transportation fuels, on
lifecycle basis;
environmental emissions comparison of fuels (particulates, ground level ozone,
hazardous air pollutants);
market and business structure overviews for ethanol and other fuels;
production technology and typical ethanol plant economics;
socio-economic impacts of expanded ethanol production and use in Alberta; and
input for consideration from stakeholders.
A lifecycle approach using a Canadianized version of the Delucchi 1 model was applied in this study to
analyze the direct and indirect energy and environmental impacts in context of ethanol as an alternative
transportation fuel.
Alberta ethanol policy-makers face a complex North American policy environment and a dynamic business
system. Information and analyses provided in this study lead to conclusions on most of the criteria that
policy-makers can weigh in reviewing the current ethanol policy. However, this study was not conducted in
the context of any predetermined or desired ethanol policy outcome (favouring or not favouring ethanol tax
exemptions or other incentives) with defined objectives. Neither does this study attempt to take on the role
of policy-makers by placing weight of importance on any of the elements to be considered in reviewing the
ethanol policy. Any inference of such weighting and correspondingly any inference to a preference for any
specific ethanol policy are unintentional. This report does not make recommendations on ethanol policy.
1.2 Summary of Conclusions
The current market for transportation fuel ethanol in Alberta is less than 1% of the total gasoline market in
the province. Most, although not all, Canadian integrated oil refiners and wholesalers currently view
ethanol as uneconomical for their businesses. Alberta’s single ethanol producer therefore enjoys the
benefits of the provincial tax exemption for only a minor portion of its total ethanol sales. The company
exports nearly all its output to the United States.
1
A partial Canadianization of the Delucchi model, which was completed by Delucchi (1998) for Natural Resources Canada (NRCan) in March, 1999
was further developed by Levelton and (S&T)2 for NRCan. (S&T)2 has applied this latest Canadianized version as the starting point for this study. It is
considered to yield the most rigorous life cycle analysis of both greenhouse and non-greenhouse gases from alternative motor fuels, and has the
advantage of incorporating functional capabilities and data for analysis of Canada and Alberta specifically.
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Demand for ethanol/gasoline blends for transportation is spread across Canada. There are approximately
1000 retail outlets selling ethanol blends. Canadian consumption is concentrated in Ontario where one
major oil refiner/wholesaler blends ethanol with its gasoline. There are other Canadian gasoline suppliers
selling ethanol blends in western Canada. Demand in the U.S. has been growing rapidly in context of
environmental regulations requiring minimum oxygenate levels in gasoline in regions where ambient air
quality standards are not being attained. Ethanol competes mainly with methyl tertiary butyl ether (MTBE)
as a gasoline oxygenate additive in the United States. Little MTBE is blended with motor gasoline that is
consumed in Canada.
MTBE has now been targeted by the US Environmental Protection Agency (EPA) as well as the State of
California for phase-out due to soil and water contamination from underground leaking fuel storage tanks.
The EPA is seeking to phase-out MTBE. However, corresponding mandatory minimal oxygenate levels in
gasoline may be eliminated. Although the U.S. EPA and Department of Agriculture (DA) have proposed
the development of a “Renewable Fuels Standard”, which favours ethanol, the form of this new program
(or regulation) has yet to be defined by the U.S. Administration. The market position of ethanol as an
environmental tool is therefore uncertain. In California some ethanol will likely be required to meet the
gasoline standards. That is, California refiners may not have enough “clean-burning” components to make
all of the gasoline (meeting standards) needed for the state without the use of oxygenates. However, there is
uncertainty regarding how large the ethanol requirement will be in California as well as other states.
Ethanol offers Alberta a renewable fuel source with a positive energy balance, even on a lifecycle basis.
That is, more energy is contained in ethanol produced from wheat grown in the province than the total
amount of energy inputs required for its production. However, the ratio of total energy output to input is
greater for gasoline and some other fuels.
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Table 1: Summary of Results and Conclusions of This Study
Study Area
Market Factors
Quantitative or Qualitative Conclusion
Current market in western Canada is too
small to support 200 million/year production.

Potential in U.S. market as a result of MTBE
phase-out.

Market uncertainty due to legislated
oxygenate requirements in US gasoline being
eliminated. Uncertain form of new
“Renewable Fuels Standard” favouring
ethanol.

Energy and Environmental Factors (as transportation fuel)
Energy Balance

Ethanol offers positive energy balance (i.e.,
output>input) on lifecycle basis.

Gasoline offers higher net energy ratio
(output/input) versus ethanol (and most
transportation fuel alternatives).
Criteria Air Contaminants (CAC)

Ethanol blended with gasoline offers
emission reductions for exhaust carbon
monoxide (CO), hydrocarbons (VOCs),
particulates (PM), sulphur (SOx), with small
increases for nitrogen oxides (NOx), and
greater increases for aldehyde. Can result in
greater evaporative VOC emissions if fuel
vapour pressure not adjusted.

Urban environmental quality in Alberta
meets existing air quality standards, and
likely to meet future proposed Canada-Wide
Standards for PM and ozone most of the
time.
Greenhouse gases (GHG)

Ethanol is a renewable fuel that yields lower
GHG emissions than gasoline, on lifecycle
basis.

It is premature to determine ethanol's priority
as a GHG reduction option in Alberta.
Socio-economic Considerations (200 million litre/year more production in Alberta)
Employment

Net increase in employment between 200 to
700.
Economic Development

An increase in total economic activity in the
province on an ongoing basis of $104 to $132
million/year. One time plant construction
impact of $245 to $280 million.
Government Revenues

Neutral to small increase in total provincial
tax revenue.

Less fuel tax revenue offset by higher income
tax and other government revenues.
Stakeholder Input and Additional Considerations
Tax Exemptions, Producer Subsidies

Fuel tax exemptions and/or investor/producer
incentives available in many U.S. states and
Canadian provinces.

Magnitude of ethanol incentives and duration
periods not harmonized across Canadian
provinces.

Ethanol stakeholders and potential investors
prefer longer (8 to 10 years) periods and
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

Refinery, Transportation Logistics


Trade Issues


Consumer/Retailer Concerns

harmonized incentives.
Gasoline suppliers concerned regarding long
term support for “uneconomical”, competitor
ethanol businesses.
Costs to accommodate ethanol are oil
refiner/wholesaler-specific. Most do not view
ethanol as economical. Some do.
Requires co-operation and optimization
among interested business parties to make
ethanol “work” in fuel system.
Subsidized exports vulnerable to countervail
trade actions.
Requires expert assessment in context of
specific policy design and trade implication
details.
Historical issues resolved, mostly related to
moisture.
Currently very few consumer and retailer
complaints.
Since ethanol is derived from renewable biomass, carbon dioxide (greenhouse gas) emissions released
during combustion are essentially captured during in the grain from which the ethanol was derived.
Therefore, ethanol offers potential GHG emission benefits versus non-renewable fuels such as gasoline,
even on a lifecycle basis. There are many technologies2 available to reduce GHG emissions from
transportation and other sources. Alberta as well as other provinces are engaged with the Federal
government in the National Climate Change Process (NCCP) that has the objective of providing
recommendations for Ministers of Energy and the Environment to consider in formulating a strategy to
address Canada’s Kyoto Protocol commitments. The Kyoto Protocol would require Canada to reduce its
GHG emissions between 2008 and 2012 to a level that is 6% less than 1990 emissions. For Alberta
Environment's Bureau of Climate Change, involved in identifying climate change solutions for the
province, it is premature to determine the priority of ethanol as a technology tool.
Ethanol blended at a level of 10% with gasoline provides reduced vehicle emissions for most criteria air
contaminants (CAC)3 versus straight gasoline. Ethanol blends offer reduction in exhaust carbon monoxide
(CO), hydrocarbons (VOCs), particulates (PM), sulphur (SOx), but small increases in nitrogen oxides
(NOx) emissions and substantial increases in aldehyde emissons. Ethanol can result in greater evaporative
VOC emissions if vapour pressure of the fuel is not appropriately adjusted. Adjusting vapour pressure of
fuels can present refinery-specific operations or blending issues. Evaporative emissions typically constitute
the minor portion of total vehicle emissions.
Urban (i.e., Calgary and Edmonton) environmental air quality in Alberta meets existing National Air
Quality standards for ground level ozone (resulting from CAC precursors) and is likely to meet future
proposed Canada-Wide Standards for PM and ozone most of the time. While ethanol offers environmental
benefits, these are not necessarily required to achieve ambient air quality objectives.
The potential construction of two 100 million/year ethanol plants in Alberta would have overall positive
socio-economic benefits for the province. Beyond one-time construction employment and capital
investment of between $245 and $280 million, there would be hundreds of permanent jobs, the exact
number depending on plant sizes and business profiles. These potential businesses would generate an
The term “technologies” in context of climate change response used in this study includes application of
fuels, equipment, process changes, as well as behavioural changes (e.g., driving at speed limit, turning off
lights) that can result in reduced GHG emissions.
3
The CACs include particulates (PMTotal, PM10, PM2.5), nitrogen oxides (NOx), sulphur oxides (SOx),
volatile organic compounds (VOC) and carbon monoxide (CO).
2
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additional $104 to $132 million of net economic activity for the province. This estimate includes major
positive economic contributions from grain and ethanol producers. It is assumed that the amount of oil
production in the province would not be materially affected, in that any crude oil displaced from domestic
consumption of ethanol would be exported from the province at international prices. However, ethanol
would result in lower economic contributions from oil refiners if they decided to use 200 million/year of
ethanol potentially produced in Alberta. The impact on provincial government revenues, in context of a
continued provincial tax exemption of 9 ¢/litre for 200 million litres/year of ethanol potentially sold in the
province, is essentially neutral. That is, while tax revenues would be lost as a result of the exemption, these
are made up through increased income taxes and other government revenue source that would be associated
with the ethanol businesses.
Fuel tax exemptions and/or producer subsidies are available in many U.S. states to attract ethanol
investments. Some of the more attractive, co-ordinated and proactively promoted ethanol incentive
programs are in states that grow large amounts of corn, such as Minnesota. In Canada, most of the
provinces offer tax exemptions for ethanol made and/or sold within their province. These incentives are
additional to the 10 ¢/litre federal government excise tax exemption that is available in all provinces. In
general, provincial programs have been primarily motivated by the prospects of regional economic
development, with positive environmental (CAC and GHG reductions) contribution viewed as a collateral
benefit.
The magnitude of ethanol incentives and their duration periods are not harmonized across Canadian
provinces (or within the United States) such that potential ethanol investors seek out the most attractive
state or provincial programs to support their business and reduce investment risk. Stakeholders favouring
ethanol and potential investors in new plants interviewed in this study prefer longer (e.g., 8 to 10 years)
periods and harmonized incentive programs across the provinces, if possible. In comparison, some oil
refiners and gasoline wholesalers stakeholders have major concerns regarding incentives for ethanol
businesses that they believe are not economical and self-supporting over the long term.
Although this study covers a broad range of elements that should be considered when reviewing the ethanol
policy, its scope is limited. Further analyses that may be required and are excluded from the scope of this
study include: assessment of market feasibility for ethanol plant(s); business feasibility and risk assessment
for plants in Alberta; oil refinery production and blending impacts in context of using ethanol;
ethanol/gasoline blends delivery logistics optimization; comparison of a broad range of alternative
economic development opportunities to assist the agricultural and other communities; comparison of
ethanol in context of other climate change options for Alberta; and analysis of potential trade actions
against ethanol in context of specific policy designs.
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1.3 Ethanol Market Overview
The trend toward cleaner, reformulated gasoline in North America has been largely responsible for the
burgeoning ethanol industry. Demand for ethanol has increased substantially in recent years for use in
ethanol/gasoline blends. Ethanol production capacity in North America has been growing as a result. Most
of the existing and new capacity has been installed in the U.S. mid-west corn-producing states where over
90% of the North American capacity is located. Canada’s ethanol capacity is concentrated in south-western
Ontario where one major producer relies largely on locally grown corn for raw material. Approximately
95% of producers use corn as the raw material in fermentation processes to produce ethanol.
Table 2: North American Supply and Demand Trends for
Ethanol4
(billion litres)
Capacity
Production
Domestic Demand:
Transport fuels
All other uses
Total
1990
5.8
4.6
1998
8.6
5.5
2005
9.8
6.7
3.7
1.1
4.8
4.9
1.0
5.9
6.0
1.2
7.2
* Production may not equal demand due to inventory changes and trade.
The market for ethanol in the Pacific Northwest (PNW)5 region of North America (including north-western
US states and western Canadian provinces and excluding California) constitutes approximately 6% of the
North American total. The PNW would represent the primary regional market for any potential new
Alberta capacity because of proximity and related transportation costs. The region is a net importer of
ethanol, with customers importing from mid-west plants and to a lesser degree from outside North
America. While ethanol production capacity in the region is currently not sufficient to support local
demand, the potential construction of new, large plants that have been announced or are under
consideration for Washington, Montana, Alberta and Oregon could boost capacity to exceed demand in the
PNW (not for total North America). Beyond the regional market, proponents of these new ethanol plants
have expectations of substantial growth in the California transportation fuel oxygenate market. The growth
in the California market is largely contingent on the phase-out of MTBE6 as an oxygenate in transportation
fuel and the potential switch to ethanol to meet fuel standards. However, there are other options available to
meet gasoline specifications for at least a portion of the State’s gasoline supply.
The US EPA’s and the US Department of Agriculture’s (USDA) recent joint announcement on MTBE and
ethanol may provide some uncertainty for ethanol investors. On the one hand the phase out of MTBE
seems more certain. However, it has come in the context of eliminating the Clean Air Act’s 2% oxygenate
requirement in gasoline.7 This may have removed the environmental legislative underpinning of the ethanol
4
Camford Information Services: CPI Product Profiles, Ethanol 1999 and Renewable Fuels Association.
PNW includes Washington, Montana, Idaho, Oregon, Nevada, British Columbia, Saskatchewan, Alberta
6
Methyl tertiary butyl ether
7
U.S. EPA, U.S. DA MARCH 20, 2000, Clinton-Gore Administration Acts To Eliminate MTBE, Boost
Ethanol, March 20, 2000
5
6
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as well as other oxygenates market. One implication of this change is that states may use alternative control
options to achieve environment standards. These options may or may not include oxygenates for
transportation fuels.
On the other hand the USDA’s remarks sound positive for ethanol suppliers. That is, “Ethanol will play an
important role in ensuring that we maintain the air quality gains we have achieved to date, and the
renewable fuels standard will encourage substantial new growth in the use of ethanol and other renewable
fuels across the country. That's good news for our farmers, for our energy security, and for the
environment." However, the form or nature of this renewable standard is not evident. It may present legal
difficulties in context of environmental requirements (considering the elimination of the mandated
oxygenate requirement). The standard may indeed have climate change underpinnings, although this is not
yet clear.
1.4 Production, Energy, and Environmental Emissions
Similar to the existing ethanol producer in Alberta, an expanded industry in Alberta would use wheat as the
raw material. The most likely class would be Canadian Prairie Spring (CPS) wheat due to its high yield and
lower protein content. Different ethanol production concepts have been used as reference points for
analysis in this study, namely: an ethanol plant integrated with a cattle feedlot; a stand alone dry mill
ethanol plant; and an ethanol plant gluten operation which could process either CPS wheat or Hard Red
Spring (HRS) wheat.
The energy requirements and greenhouse gas emissions resulting from the production of CPS wheat are net
positive and compare favourably with those from the production of corn in Ontario as shown in the
following table.
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Table 3. Summary of Energy Requirements and Greenhouse Gas
Emissions from Grain Production
Energy
Units
Fertilizer Manufacture
Pesticide Manufacture
Field Operations
CPS Wheat
CWRS Wheat
Barley
Corn
BTU/56 lbs.
35,681
643
8,754
BTU/56 lbs.
43,723
750
11,671
BTU/56 lbs.
40,360
643
9,482
BTU/56 lbs.
21,360
998
22,894
56,144
50,485
45,252
Grams CO2/
million BTU
8,672
-304
15,709
24,077
87.5
Grams CO2/
million BTU
7,890
-3,123
16,112
20,879
69.9
Grams CO2/
million BTU
8,912
908
6,654
16,474
66.5
Total
45,078
Greenhouse Gas Emissions
Units
Grams CO2/
million BTU
Farming
6,504
Land Use and Cultivation
-1,807
Fertilizer Manufacture
12,824
Total
17,521
Total grams CO2/lb grain
65.5
The analyses of energy requirements and greenhouse gas emissions have been performed assuming that all
chemical fertilizers are used in Alberta. It is known that some manure is used to supply a portion of the
nitrogen requirements. No accurate estimation of the quantity of manure used was available thus it was
assumed that no manure was used. The use of manure is less energy intensive than chemical sources of
nitrogen and thus the energy balances and greenhouse gas emissions calculated are known to be
conservative.
Ethanol/gasoline blends yield overall reductions in criteria air contaminants as well as variety of hazardous
air pollutants, some which are toxic. However, ethanol blends can also result in higher emissions of NOx as
well as some hazardous substances such as aldehydes. Estimates of the overall magnitude of these benefits
in emission reductions is subject to ongoing improvement and can be regionally as well as seasonally
specific. This study provides estimates of the effects of ethanol blends in context of conditions in Alberta.
1.4.1 Lifecycle Analysis for Energy and GHG Emissions
A lifecycle analysis is required to assess the net energy used and consumed for ethanol and alternatives.
The full cycle concept of analyses considers all inputs into the production and use of a fuel. It combines the
fuel production, vehicle manufacture and fuel use in a single analysis. It is also referred to as the fuel cycle
by some authors. The ultimate result is a value that can be used for comparison of different commodities on
the same basis, such as per unit of fuel energy or per kilometre driven. Greenhouse gas emissions over the
full cycle include all significant sources of these emissions from production of the energy source (i.e. crude
oil, biomass, natural gas, etc.), through fuel processing, distribution, and onward to combustion in a motor
vehicle for motive power. A life cycle analysis should also include greenhouse gas emissions from vehicle
material and assembly as these emissions are affected by the choice of alternative fuel/vehicle technology.
Wide ranges of emission sources are involved in the production and distribution of fuels, and these vary
depending on the type of fuel.
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1.4.1.1 Energy Balance Summary
All of the fuels studied have a positive full cycle energy balance. That is, there is more energy contained in
the fuel than that required to make the fuel. The table below is a summary of the ratio between energy out
and energy in. The higher the number, the more favourable the energy balance. These energy balance ratios
are sensitive to the input assumptions. The values do not represent a single refinery or ethanol plant but are
representative of the whole industry for existing operations and for typical modern ethanol plants that
would be located in Alberta.
Table 4. Full Cycle Energy Balances for Transportation Fuels
Fuel
Gasoline
Propane
Diesel
Methanol
Biodiesel
Integrated Feedlot-Ethanol Plant
Conventional Dry Mill Ethanol Plant
Gluten –Ethanol Plant CPS Wheat Feedstock
Gluten –Ethanol Plant HRS Wheat Feedstock
Energy output/Energy input
4.34
14.8
13.5
1.44
2.85
2.08
2.02
2.60
2.15
1.4.1.2 Greenhouse Gas Emissions Summary
The greenhouse gases included in the calculations for this report are carbon dioxide (CO 2), methane (CH4)
and nitrous oxide (N2O). The emissions have been weighted according to Intergovernmental Panel on
Climate Change (IPCC) guidelines where CO 2 has a weighting factor of 1.0, CH4 is assigned a value of 21.0
and N2O has a weighting factor of 310. These are the 100-year global warming potential (GWP) multipliers
recommended by the IPCC. Throughout the report we will report primarily CO 2 equivalent values. This
will be the weighted sum of the three greenhouse gases. In some areas this will be further broken down to
provide detail on the separate gases.
All of the alternative fuels considered produce fewer greenhouse gases on a full cycle basis than gasoline or
diesel. The greenhouse gas emission benefits from the biofuels ethanol and biodiesel depend on the
renewable carbon credit that comes from burning these fuel and displacing the gasoline that would have
otherwise be combusted. Methanol fuel cell vehicles derive their greenhouse gas benefit from the higher
vehicle efficiency. Propane and natural gas have lower greenhouse gas emissions due to requiring less
energy in their production processes and having a lower carbon content in the fuels. The following table
summarizes the greenhouse gas emissions from the alternative fuels other than ethanol. The gasoline,
propane, natural gas, and methanol are assumed to be light duty vehicles while the diesel and biodiesel are
representative of class 8 heavy duty trucks.
Table 5. Summary of Greenhouse Gas Emissions from
Alternative Fuels
Gasoline
Propane
Natural Gas
9
Methanol
Fuel Cell
Diesel
Biodiesel
CHEMINFO
Units
Grams
CO2 eq/mile
Vehicle
356.6
Operation
Fuel
150.7
production
Vehicle
36.8
assembly
and
materials
Total
544.1
Percent change vs. gasoline
Grams
CO2 eq/mile
Grams
CO2 eq/mile
Grams
CO2 eq/mile
Grams
CO2 eq/mile
Grams
CO2 eq/mile
327.7
309.7
262.5
1715.4
41.9
48.5
76.0
148.4
556.0
912.8
37.0
37.7
38.9
94.7
98.1
413.2
-24.1%
423.4
-22.2%
449.8
-17.3%
2366.1
1052.8
-55.5%
The following table compares ethanol from the various production concepts considered to gasoline. The
carbon in the fuel is added to the production emissions so that an equivalent comparison can be made. This
table does not consider the impact of higher energy efficiency from the combustion of low level ethanol
blends.
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Table 6. Summary of Greenhouse Gas Emissions for Gasoline
and Ethanol
Units
Gasoline
Integrated Feedlot-Ethanol Plant
Conventional Dry Mill Ethanol Plant
Gluten –Ethanol Plant CPS Wheat
Feedstock
Gluten –Ethanol Plant HRS Wheat
Feedstock
Greenhouse Gas Emissions
including the Carbon in the Fuel
Grams CO2 equivalent per million
BTU
92,673
50,950
52,498
34,711
Percent Change
compared to gasoline
43,740
-52.8%
-45.0%
-43.4%
-62.5%
If ethanol is used as a 10% blend with gasoline approximately 6.5% of the energy will be supplied from the
ethanol with the remainder from the gasoline. The percent reductions in greenhouse gas emissions from a
10% blend need to be kept in perspective with the relative amount of energy supplied by the ethanol. It has
been assumed that a 10% ethanol blend achieves 1% better energy specific fuel economy. This assumption
is supported by test data available from the literature. Part of the reason for this is more complete
combustion of the fuel and lower emissions of carbon monoxide and unburned hydrocarbons. The change
in efficiency is therefore a function of how clean the emissions are from the test vehicles.
The data used to support the 1% improvement was developed from vehicles that produce lower exhaust
emissions than the Alberta fleet does. It is highly likely that the Alberta fleet will achieve a greater than 1%
fuel economy benefit from the more complete combustion that the 10% ethanol blend promotes. There is
no test data available on fleets with similar emissions to the Alberta fleet. The following table summarizes
the greenhouse gas emissions for 10% ethanol blends with the 1% better fuel economy applied to both the
existing Alberta fleet and a fleet with lower exhaust emissions and less unburned fuel. There is a significant
difference in the full cycle emissions reductions that this uncertainty introduces. However, even the most
conservative assumptions result in greenhouse gas emission benefits.
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Table 7. Summary of Greenhouse Gas Emissions from 10%
Ethanol Blends
Ethanol
Source
Units
Vehicle
Operation
Fuel
production
Vehicle
Assembly and
Materials
Total
% reduction
with Alberta
fleet emissions
% reduction
with lower
exhaust
emissions
Gasoline
10% Ethanol
Integrated
Feedlot
10% Ethanol
Dry Mill
10% Ethanol
Gluten with
CPS wheat
10% Ethanol
Gluten with
CWRS wheat
g CO2 eq/mile
g CO2 eq/mile
g CO2 eq/mile
g CO2 eq/mile
g CO2 eq/mile
356.6
357.6
357.6
357.6
357.6
150.7
132.6
133.2
126.9
130.1
36.8
36.8
36.8
36.8
36.8
544.1
527.0
3.1
527.6
3.0
521.3
4.2
524.5
3.6
3.5
3.4
4.6
4.0
1.4.2 Ethanol as a Climate Change Tool
All provinces and the federal government are actively engaged in the National Climate Change Process
(NCCP) that is developing a strategy to address Canada’s Kyoto Protocol commitment for a 6% reduction
in greenhouse gas emissions over the period 2008 to 2012, versus 1990. Alberta has taken proactive steps
in establishing the Bureau of Climate Change (within Alberta Environment) as well as Climate Change
Central, which is made up of representatives from the Alberta government, industry and other stakeholders.
These groups will identify GHG emission reduction opportunities and recommend measures to address
Alberta’s future obligations. One Alberta Environment representative on the Bureau indicated that it was
premature to determine the role of ethanol, in relation to other alternative fuels, in addressing GHG
emission from transportation within the province's overall climate change strategy, at this time.
Technologies that reduce GHG emissions would likely have positive collateral environmental effects for
CAC emissions. The context of this study does not include the influence of potential application of many
possible technologies to achieve GHG emission reductions (and associated energy consumption).
1.4.3 Criteria Air Contaminant, Hazardous Air Pollutant Emissions
The emissions of criteria air contaminants from vehicles in Alberta for 1995 (as reported by Environment
Canada8) are relatively high due to the age of the Alberta fleet, the high altitude and the cold weather.
These emissions are expected to decline over time as a result of: an increase in the rate of vehicle turnover
8
Environment Canada, 1995 Criteria Air Contaminant Emissions for Canada, Jan. 1999. Data sheet only.
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(with more efficient and lower emitting vehicles replacing older vehicles); new Environment Canada
Lower Sulphur in Gasoline Regulations9; and improving environmental standards for vehicles.
Table 8. Summary of the Environmental Impacts of a
10% Ethanol Blend
Parameter
CO
VOC
PM
CACs
NOx
Carbon Monoxide
Exhaust Hydrocarbons
Particulate Emissions
Full cycle ozone forming potential
Oxides of Nitrogen
Total Air Toxics10
Aldehyde emissions
Evaporative Emissions with Matched RVP
Evaporative Emissions with Higher RVP
VOC
VOC
Percent Change
-12.3%
-15%
-35%
-10%
+5%
-3.8%
+150%
0%
0 to 100%
depending on season
The use of ethanol as a blending component of gasoline will lower the emissions of carbon monoxide and
exhaust hydrocarbons (including some hazardous and toxic organic air pollutants). There will be small
increases in exhaust nitrogen oxides, substantial icnreases aldehyde emissions, as well as evaporative
hydrocarbon emissions if the vapour pressure of the gasoline is not adjusted. The increase in aldehyde
emissions is not expected to cause increased ambient air quality problems, as secondary aldehyde formation
in the atmosphere is larger than the primary emissions. Calculations of the full cycle ozone forming
potential of 10% ethanol blends when the vapour pressure is adjusted show a 10% reduction compared to
gasoline. A summary of the environmental impacts of 10% ethanol blend is shown in the above table.
Evaporative emissions of VOCs will be higher if the vapour pressure of the gasoline is not adjusted.
Currently, ethanol does not represent a priority environmental air quality management tool to address
particulate and ground level ozone (smog) levels for Alberta Environment or Environment Canada. One
issue is the degree of environmental air quality improvement required in Alberta. While 10% ethanol
blends can provide some environmental improvements, these may be not be required to meet current
environmental standards, or these standards may be achieved in alternative ways in Alberta.
Alberta’s urban centres such as Calgary and Edmonton are generally meeting current National Air Quality
Objectives, as reflected by the Air Quality Index. This does not mean that ethanol would not be
environmentally favoured if used in gasoline blends since improvements in air quality would be expected,
even though general objectives are being met most of the time. Ethanol blends would improve air quality
for some contaminants (e.g., carbon monoxide), but may not improve with respect to some other
contaminants (i.e., NOx, aldehydes).
Table 9: Ambient Air Quality in Edmonton and Calgary
(percentage of time achieved during year)
9
Environment Canada, Lower levels of sulphur in gasoline will result in cleaner air for all Canadians,
Press Release, June 7, 1999.
10
The use of the term “toxics” in this report relates to a variety of hazardous air pollutants. These pollutants
have not necessarily been declared “Toxic” under the Canadian Environmental Protection Act (CEPA).
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Air Quality Index
Good
Edmonton
1998
1999
93.58%
98.63%
Calgary
1998
1999%
99.49%
99.78%
(Lower than 50% of standard)
Fair
6.3%
1.37%
0.51%
0.22%
0.06
0%
0%
0%
(Between 50 and 100% of standard)
Poor
(Exceeds standard)
Source: Alberta Environment
The province is also expected to be able to meet the new proposed Canada-Wide Standards (CWS) for
particulate and ozone concentrations that are due to come into effect in 2010 and 2015, respectively. The
new proposed CWS standard for ozone of 65 part-per-billion–8 hour period is essentially equivalent to the
current National Objective of 82 ppb-1 hour standard that is being achieved most of the time. 11
11
Personal conversation with Long Fu, Alberta Environment, Environmental Sciences
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1.5 Comparison of Fuel Alternatives
Ethanol can be considered both as an alternative fuel and as a gasoline blending component. As a gasoline
component it competes with hydrocarbons such as alkylates, olefins, aromatics and with other oxygenates
such as MTBE. Each component has its own unique attributes and each can have an impact on the exhaust
emissions that a vehicle produces. A summary of the attributes and impact on exhaust emissions is shown
in the following table. In this table ethanol is considered in context of a low level blend and not as a high
level fuel or a diesel fuel component. Ethanol is the only component in this table made from a renewable
resource.
Ethanol
MTBE
ETBE
Alkylate
Aromatics
Olefins
115
110
112
92.6
~110
~90
18.0
9.0
4.0
3.0
~3
~7
52.2
70.5
68.1
84
90.0
85.7
34.4
18.2
15.7
0
0
0
+
0
0
0
0
0
+
-
Impact on NOx
Emissions
Impact on HC
Emissions*
Impact on CO
Emissions
Impact on Fuel
Economy
Oxygen
Content, wt%
Carbon
Content,
Wt %
Blending
Vapour
Pressure, psi
Blending
Octane
R+M/2
Table 10: Summary of Key Properties of Gasoline Blending
Components
+
0 to +
0 to +
0
+
+
- DENOTES A DECREASE, + IS AN INCREASE.
* Assumes vapour pressure adjustments to gasoline. HC emissions may increase if VP is not adjusted.
Methanol is not being widely used as a fuel for internal combustion engines in North America, currently. It
is being tested in blends with diesel fuel in Europe and South America. It is a leading candidate for the fuel
in fuel cell vehicle engines.
Biodiesel is made from animal or vegetable oils. It can be used as a blending component for diesel or as
fuel on its own. Blends of 20% biodiesel and 80% petroleum diesel can be used in unmodified engines.
100% biodiesel may require some engine optimization to maximize the benefits of the fuel. Biodiesel neat
or as a blend generally reduces exhaust emissions from diesel engines, it has good lubricity properties but it
has poor cold weather properties and would need to be treated with additives to perform adequately in
Canadian winters.
Propane and natural gas are gaseous fuels that have been used for many years in Canada. Most of the
vehicles on the road today have been aftermarket conversions. The rate of conversions has dropped in
recent years but an increasing number of natural gas and propane powered vehicles are being offered by the
Original Equipment Manufacturers (OEMs). These vehicles generally have very low exhaust emissions.
1.6 Ethanol Plant Economics
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Cost models are useful for providing approximate estimates of capital costs, employment, revenues,
operating expenses, income taxes and profits associated with different sized plants with alternative business
profiles. Microeconomic parameters are estimated based on the assumption of construction of “greenfield”
facilities and the following profiles. These models are used in subsequent socio-economic analysis.
Table 11: Size and Description of Model Facilities
Model
Ethanol
Capacity
Plant Profile
(million litres/year)
A
25
B
100
C
100
D
100
Dry mill CPS wheat with adjacent cattle feedlot.
No drying of wet grains
Dry milling with DDG for sale.
CPS wheat.
Gluten Production with ethanol by-product.
CPS wheat.
Gluten Production with ethanol by-product.
HRS wheat.
Ethanol plant revenues and profits are dependent on many factors, including: size of plant; configuration
and co-products (or by-products) made; and the price of raw material – in this case wheat; and co-product
revenues. For smaller plants the ability to sell ethanol (at above gasoline producers’ value – i.e., around 40
cents per litre) as well as animal feed to regional customers are important factors for profitable operations.
Without tax incentives directly influencing ethanol prices, some plants cannot be profitable. Given wheat
raw material price at $100 per tonne, and co-product DDG animal feed price at $160 per tonne, the
breakeven ethanol price for a 100 million litre per year facility is approximately 28 cents per litre (includes
additional simplifying assumptions for financing, etc.). For larger ethanol plants co-producing wheat
gluten, the ability to actually sell the gluten (at required prices) is a necessary component of the
profitability shown in model plant economics. Under actual business conditions, market barriers in the
wheat gluten market may affect the ability to achieve the revenues and profits assumed for these model
plants.
Table 12: Summary of Revenues and Operating Expenses for
Model Plants
Dry mill
CPS wheat,
with feedlot,
no drying
Ethanol capacity (million
litre/yr)
($ million)
Revenue (ethanol only)
(at 40 cents/litre)
Dry mill CPS, Gluten/Ethanol Gluten/Ethanol
with DDG
CPS
HRS
Model A
25
Model B
100
Model 3
100
Model 4
100
$10.0
$40.0
$40.0
$40.0
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Net raw material cost
$3.0
$11.8
$(36.1)
$(46.4)
Energy (electricity, natural gas)
Labour
Maintenance & overheads
$0.8
$1.0
$1.2
$4.3
$1.0
$4.2
$9.2
$2.8
$6.8
$9.4
$2.8
$6.8
Total expenses
Interest on debt
$5.9
$1.4
$22.3
$4.7
$(17.3)
$7.7
$(27.4)
$7.7
Income before income tax
Income tax rate*
Income tax payable
$2.7
38%
$1.0
$12.9
38%
$4.9
$49.6
38%
$18.8
$59.7
38%
$22.7
Net income
Return on Investment
$1.7
9%
$8.0
11%
$30.7
27%
$37.0
32%
(credits applied for by-products – feed and/or gluten)
(assumed 25:75 debt to equity, 9% interest changes)
(Annual net income divided by total capital
employed *)
* Excludes capital cost allowances (CCA), which would result in reduced income taxes, and
greater returns on investment.
1.7 Summary of Socio-Economic Studies
Twenty socio-economic studies of ethanol were identified and reviewed. The studies covered the United
States, Canada and Brazil. The studies had different scopes and used a variety of approaches and
methodologies such that a variety of conclusions were reached. Most studies were related to ethanol from
corn and carried out for areas of the United States while a few were undertaken for Canada.
Most of the analyses concluded that the extra demand for feed grains (mostly corn) had some upward
impact on feed grain prices. The amount of the increase varies year by year due to changes in the overall
supply-demand balance. The studies that considered the whole US market have price increases for corn of
20 to 45 cents per bushel due to the demand created by ethanol production. Due to the interdependent
nature of North American feed grain markets Canadian producers have also received some benefit from this
extra demand.
Most of the studies reported an increase in the number of jobs due to the production of ethanol. These jobs
are weighted towards the rural sector of the economy but indirect benefits accrue to all sectors of the
economy. Most of the studies also report an increase in Gross Domestic Product (GDP) related to the
demand for grain and the production of ethanol. However, these results are mostly in regions that have
large rural populations, and lack an oil refining industry.
The studies are not consistent in their determination of overall costs and benefits to the economy. As a
result the conclusions of the reports vary with respect to the costs and benefits of ethanol development and
use. Some conclude that the costs to governments and society outweigh the benefits and others reach the
opposite conclusion. That is, the benefits are greater than the costs and that government expenditures drop
as a result of ethanol fuel tax exemptions. Some studies are also internally inconsistent in how they treat
issues such as ethanol’s lower energy content. They calculate the lost government revenue from the ethanol
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portion of fuels but do not include the extra fuel tax revenue from the extra gasoline sales caused by the
lower fuel economy.
1.8 Potential Socio-Economic Impacts for Alberta
This study’s analysis of potential socio-economic impacts related to ethanol production in Alberta has
attempted to be: consistent with the treatment of costs and benefits in other studies; consistent in
assumptions with respect to GHG modelling; and to be as complete as possible (although the scope of
socio-economic impacts analysis is limited). The reference for the analysis was the assumption that 200
million litres per year of ethanol would be produced and used in Alberta. Although the analysis reflects
potential increased ethanol usage in Alberta, it does not mean to imply any mandatory requirement for oil
refiners, wholesalers, retailers or consumers to adopt ethanol. The analysis estimates the economic
implications if these entities were to voluntarily adopt ethanol. Negative economic consequences identified
in this study for some of these entities may relate to the lack of a large ethanol fuel market in Alberta.
Economic analysis is not an exact science. In the review of the literature on socio-economic impact of
ethanol production different economists have taken different approaches to the subject. One approach was
used for this study. It is similar to the approach taken by some of the more detailed studies found in the
literature.
Two production scenarios were examined. In one scenario the ethanol was produced in two large dry mill
ethanol plants, while in the other production was at eight smaller facilities that were integrated with cattle
feedlots. The costs, benefits, employment impacts, government revenue impacts were calculated for each
scenario. The results are summarized in the following table.
Table 13: Summary of Socio-economic Impacts
Assumptions
Size of plant (million litres/year)
Number of proposed plants
Total ethanol production (million litres per year)
Economic Impacts
Grain Producers
Ethanol Manufacturers
Government Expenditures
Consumer Spending
Oil Producers
Oil Refiners and Marketers
Net Annual Impacts
Plant Construction Impact (one time)
Small Scale Plant
Integrated to
Cattle Feeding
25
8
200
Large Dry
Milling plant
($ million)
($ million)
78.9
108.8
-18.0
-33.9
0
-3.3
132.5
280
29.1
129.7
-18.0
-33.9
0
-3.3
103.6
245
-13.77
9.31
7.65
3.2
-13.77
7.66
6.29
0.18
100
2
200
Impacts on Provincial Revenues
Provincial Tax Exemption
Provincial Income Tax
Other taxes and revenue
Net Annual Impact
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Related to Plant Construction Impact (one time)
29.4
25.7
Employment Impacts
875
323
Ethanol plant employment, direct and indirect
414
492
Other sectors
-600
-600
Net Impact
689
215
There is an estimated increase in total economic activity under both ethanol production scenarios and an
increase in net employment across the whole economy. The impact on provincial government revenue is
estimated to be essentially neutral with tax exemptions for ethanol fuel offset by increases in income taxes
and other government taxes and fees.
Farm employment, direct and indirect
1.9 Stakeholder Policy Input and Additional Considerations
This section summarizes stakeholder input and related analysis of additional policy considerations. 12
Stakeholders provided written submissions and verbal input, 13 which the Committee should consider in its
review of the ethanol policy. There was a diverse set of perceptions surrounding ethanol among the
stakeholders contacted. Therefore, for most issues identified by stakeholders, the consultant conducted
follow-up research and analysis to clarify input and provide additional context to benefit the committee.
However, the depth of analysis may be limited in some areas, since the number of issues and divergence of
stakeholder input was in some cases substantial and could not be resolved in the context of this study. To
address and resolve some technical, economic and other issues identified by stakeholders further focused
and detailed analysis, well beyond the scope, purpose and resources available for this study may be
required. Areas where further research could be conducted have been identified.
Input was received from the following stakeholder groups: The Canadian Petroleum Producers Institute
(CPPI) representing most Canadian oil refiners and some marketers; ethanol producers; gasoline
wholesalers/retailers; farm co-operatives; Alberta Environment; Saskatchewan Wheat Pool; Alberta
Economic Development; and some related Associations and other government departments.
1.9.1 Environment Considerations
Although not unanimous, the general consensus among stakeholders interviewed for this project was that
ethanol provides overall environmental benefits. The CPPI points out that there are both positive and
negative aspects ethanol as a transportation fuel as it relates to VOC, NOx, CO, PM, SOx (the criteria air
contaminants or CAC), greenhouse gases and toxics emissions. However, there exists conflicting
information and perceptions even among CPPI members as well as other stakeholders interviewed in this
study with respect to the magnitude and accuracy of environmental advantages of ethanol. One Alberta
Environment representative on the Bureau of Climate Change indicated that it was premature to determine
the role of ethanol, in relation to other alternative fuels and other options, in addressing GHG emissions
from transportation within the province's overall climate change strategy, at this time. Although, ethanol
does yield overall reductions in criteria air contaminants (CAC) and GHG emissions, there are other
options to be evaluated for achieving environmental results. One consideration is the degree of air quality
improvement required in Alberta. Urban centres such as Calgary and Edmonton are generally meeting
current National Air Quality Objectives, as reflected by the Air Quality Index. This does not mean that
ethanol would not be environmentally favoured if used in gasoline blends since improvements in air quality
would be expected, even though general objectives are being met most of the time. Ethanol blends would
12
13
Additional to any environment, energy and socio-economic factors covered in previous sections.
Telephone interviews conducted for this study.
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improve air quality for some contaminants (e.g., carbon monoxide), but may not improve with respect to
some other contaminants (i.e., NOx, aldehydes).
1.9.2 Refinery, Wholesaler, Retailer Considerations
There are technical and related economic considerations associated with any potential changes involving
blending ethanol with gasoline. These considerations embrace the complete fuel production and delivery
system, including oil refinery, blending, transportation, storage and retail operations. In general, the
technical issues and magnitude of costs or potential benefits associated with incorporating ethanol into
gasoline are company specific. Oil refiners, wholesalers and retailers that are not using ethanol have
technical and economic concerns. Refiners, wholesalers and retailers that are using ethanol have overcome
the technical and economic hurdles. The study provides input from both types of stakeholders. However, it
is beyond the scope of this study to undertake any company-specific analysis of the merits or drawbacks of
ethanol.
1.9.3 Incentives and Ethanol Plant Financing
Incentives or subsidies for ethanol are prevalent and are likely to be continued in most jurisdictions
interested in attracting ethanol investments and creating value-added business in agricultural communities.
Ethanol investors are seeking the most preferable locations for new facilities. Criteria used to identify these
locations include the magnitude of incentives or subsidies that are available. Governments interested in
attracting such investments need to have competitive inducements versus governments in other
jurisdictions.
The ethanol “industry” in Alberta and Canada is relatively small in comparison to the US ethanol industry
and in comparison to the oil refining and gasoline industries. Although a new plant was built in Alberta
during the last decade, the size of the provincial industry has not substantially increased relative to the
North American total. Given the small size of the industry and incentives available to producers in other
jurisdictions, Alberta producers would likely require similar support to remain competitive. Whether
incentives or subsidies would be required given a much large industry with competitive scale and scope
requires detailed and focused feasibility analysis.
Stakeholders interviewed in this project who were interested in ethanol stated that the duration of any
incentive would need to be long enough to cover financing periods and providing time for accruing returns
to any investments. This would reduce the risks associated with making an ethanol investment in Alberta.
That period was identified as between 8 to 10 years, or more.
1.9.4 Economic and Trade Considerations
Oil refiners and gasoline wholesalers interviewed for this study indicated that, at a minimum, ethanol needs
to be competitive with the rack price of gasoline. Some stakeholders pointed out that it may even need to be
lower than the rack price of gasoline to overcome any additional handling, transportation, storage and
retailing costs. The rack price of gasoline can be considered to represent the full cost (including returns on
equity) of making gasoline. It is also an indication of the value at which refiners are willing to sell gasoline
to wholesalers/retailers or purchase gasoline from other refiners to meet their market requirements.
Some oil refiners and gasoline wholesalers have concerns about the long-term viability of ethanol, as well
as their own business risks (in the context of losing ethanol supply if they had made a commitment to
blend, wholesale and retail ethanol). The scope of this report does not include a business feasibility analysis
for ethanol production in Alberta, which would address Alberta-specific business viability, risks, and
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opportunities. This study provides limited anecdotal information and results of other studies that considered
risks and opportunities14.
For new ethanol plants in Alberta or elsewhere in North America, the risks associated with relying solely
on environmentally driven markets and supporting legislation for business success over a long period of
time are evident. One case in point is Alberta’s MTBE plant which is heavily reliant on mandated demand
for oxygenates in gasoline in the United States. The prospects of phasing out MTBE have resulted in
uncertainty for the Edmonton producer. Similarly, methanol production which feeds MTBE plants across
North America is vulnerable.
The business risks for any potential Canadian ethanol production destined for U.S. markets may be high. If
the yet-to-be-defined “renewable fuels standard” is oriented toward “promoting” agriculture businesses and
assisting farmers, or is a climate change response (i.e., using “renewable” resources) for the United States
(and not linked to any mandated renewable or oxygenate level for gasoline to address ambient air quality
environment standards), then ethanol made in Canada may not fit the U.S. policy framework and its
objectives. If in “promoting” the development of ethanol, the US government provides increased levels of
financial assistance to domestic ethanol producers, it would make it more difficult for Canadian exports to
compete. In addition, if the US is developing ethanol to support farmers or address climate change,
subsidized ethanol produced in Canada may be more prone to countervailing trade actions under these
circumstances.
14
State of Minnesota, Office of the Legislative Auditor, Ethanol Programs: A Program Evaluation Report,
Report #97-04, Feb., 1997.
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2. Introduction
2.1 Background
The Ministry of Agriculture, Food and Rural Development has had an “ethanol policy” since 1993. The
policy offers a guarantee that the exemption of the Provincial fuel tax payable on vehicle fuel will continue
for a period of five years after the start-up of an ethanol plant. Currently the exemption is 9 ¢/litre of
ethanol. The policy will be reviewed in 2000. The Interdepartmental Ethanol Committee has been
established to review the need for a new policy and to make recommendations to the Provincial
Government of Alberta. The committee consists of representatives from: Alberta Agriculture, Food and
Rural Development; Alberta Grain Commission; Alberta Economic Development; Alberta Environment;
Alberta Infrastructure; and Alberta Resource Development.
The committee requires up-to-date information and analysis on a variety of issues that are applicable to the
Alberta situation where ethanol would be manufactured from cereal grains other than corn. It is recognized
that a successful ethanol industry requires that the production and use of ethanol have positive net energy
balance implications, environmental benefits, favourable economical and social benefits for Alberta as a
whole. A delineation of the energy, environmental and major socio-economic impacts is necessary input
into the committee’s deliberations. Developing a comprehensive understanding of these elements is
complex and requires a holistic analysis of the impacts that additional ethanol produced and consumed in
Alberta could have. This analysis includes a lifecycle approach to understand the direct as well as many
indirect advantages and disadvantages that ethanol offers as a transportation fuel alternative. The report
also provides information on ethanol markets, wheat gluten markets, plant capital costs, revenues and
operating expenses.
There are a variety of ethanol stakeholders within Alberta and outside of the province that have interest in
the committee’s policy decisions. These stakeholders include: grain growers, ethanol producers, oil & gas
and petroleum producers, suppliers of alternative fuels, octane and oxygenate producers, fuel distributors
and retailers, environmental groups, and governments. This study provides analysis related to most of these
and other possible stakeholders of Alberta’s ethanol policy options. However for some issues, the analysis
may not be to the level of detail or accuracy required by some stakeholders. Areas where further analysis
may be required in addressing some stakeholders’ interests have been identified.
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2.2 Overview of Research Methodology
The methodology applied in this study involved: gathering and reviewing literature; obtaining energy and
environment data from industry and government sources; internet searches; computer modelling
(assumptions and details described in relevant sections below); and obtaining information and input from
telephone interviews of ethanol industry and government stakeholders. Methodological details are
described in each section.
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3. Ethanol Business System
3.1 Overall Ethanol Industry Structure
The ethanol fuel business system is complex and involves key linkages to the grain growing segment of the
agriculture sector, the livestock feed business, the vehicle fuels market, as well as connections to the food
processing and transportation sectors. In addition, the business system features government involvement,
the degree of which varies by jurisdictions, as well as influence by stakeholders concerned about the
environment. The North American ethanol industry is also quite dynamic such that traditional relationships
between business entities have been evolving. In some market areas, the traditional supplier-customer and
competitive boundaries have changed and blurred. For example, in Minnesota, corn growers have formed
co-operatives that own ethanol plants. In Ontario, the major ethanol producer has a supply arrangement,
rather than a competitive relationship, with a major oil refiner/gasoline retailer.
3.2 Government Influences
Federal, state/provincial and municipal governments influence the ethanol business system in different
ways and to varying degrees through the value-adding chain. In some U.S. states, there are substantial
incentives to entice ethanol producers to invest in new plants within their states. In other states and
Canadian provinces, the incentives are aimed more directly at fuel wholesalers/retailers to increase their
purchases of ethanol for environmental reasons as well as to support the agriculture community. In many
jurisdictions, there are no policies favouring ethanol production or ethanol use for transportation fuel. This
variation in policy orientation in part relates to the influence that stakeholders may exert with regional
elected government representatives, who in turn influence ethanol policies. For example, in the mid-west
United States, corn growers and ethanol producers are important stakeholders in the regional economy that
can influence favourable state government policies for ethanol.
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Figure 1: Major Components of Ethanol Business System
Transportation Sector
(Rail, Trucks, Passenger Vehicles)
Livestock
Producers
(Agriculture)
Food Wholesalers
Food
Processors
Food
Retailers
Public
Consumers
Corn, Wheat
Growers
(Agriculture)
Fuel Ethanol
Producers
Transportation
Fuel (gasoline)
Wholesalers
Transportation
Retailers
Fuel
Retailers
Oil Refiners/
Gasoline
Producers
Other
Transportation
Fuel Producers
Oil Explorers
Developers
Governments
(Municipal, Provincial, Federal, Agencies)
Agriculture, Natural Resources, Environment, Transportation, Business Development/Industry, Trade, Health, Finance)
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Government influences are significantly different between countries, states/provinces and specific
economic regions. In addition, government influence has occurred for different reasons. Whereas the
Brazilian government has strongly influenced ethanol production as a means to reduce its dependence on
imported oil, many countries have no similar explicit ethanol policies. Environmental factors regarding
ground level ozone (smog) have influenced the market for oxygenates and government policies toward
ethanol specifically. In the United States, favourable state policies to promote the establishment of ethanol
plants have been implemented mostly in states where there has been a strong corn growing agricultural
community. Although, environmental benefits have played a role, regional economic development and
diversification in agriculture communities have been collateral objectives. Minnesota, North Dakota,
Missouri and Montana are among the U.S. States that have some of the most favourable ethanol policies.
Apart from policies aimed at ethanol production and transportation fuel use, government policies also
influence other components of the ethanol business system. Some of the government influences within the
business system relate to:




transportation fuel taxes;
incentives for oil and gas exploration and development;
agriculture business development and diversification incentives; and
environment (e.g., smog, climate change, hazardous and toxics substances).
Transportation fuel taxes are an important source of federal, and state/provincial revenues that in many
jurisdictions they are used to support the transportation infrastructure (new roads, bridges, road
maintenance, etc.). These taxes are relatively high in comparison to the total cost or wholesale price of
transportation fuels. However in general, North American taxes are lower than in most European countries,
which are more heavily dependent on imported supplies of crude oil. Governments can use transportation
fuel taxes to influence conservation, improve crude oil and petroleum product trade balances, as well as
achieve environmental objectives.
3.2.1 Agriculture
There are a large number of government programs in many jurisdictions that are oriented toward improving
the economic conditions of agriculture communities as well as fostering economic diversification. These
programs can take the form of farm income stabilization, transportation subsidies, enhanced capital
depreciation, investment and production subsidies, loan programs and other mechanisms. In some
jurisdictions, ethanol policies have been aimed at enhancing grain grower economics as well as achieving
economic diversification through ethanol production. The design of the ethanol incentive policy can
determine the nature of ethanol development. For example, the ethanol policy in Minnesota features
producer incentives for ethanol production less than 56 million litres per year. In part, this has encouraged
the development of relatively small ethanol plants in the state. Corn is supplied by growers whose
ownership of the ethanol business is tied the bushels of corn delivered as raw material to the facility.
3.2.2 Oil and Gas
Governments also provide financial incentives for oil and gas exploration, development and research.
These incentives have the general objective of increasing the supply of crude oil and natural gas, thereby
improving trade balances and ultimately lowering prices for fuel consumers. Alberta’s oil and gas industry
is influenced by a relatively complex royalty regime that in part reduces business risk due to unanticipated
commodity prices. Allowances and incentives are in place to encourage production of oil and gas that is
more expensive to develop and produce. For example, the Enhanced Recovery of Oil Royalty Reduction
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Regulation provides for the Crown sharing in the incremental costs of tertiary production.15 Federal
government also offers accelerated capital cost allowances (CCA) for exploration and development. There
are also programs to encourage and enhance the development of Alberta’s oil sands.
3.2.3 Environmental Influence
Environmental factors have had and are likely to continue to have a strong influence on the ethanol
business system. Policies addressing smog have favoured the use of oxygenates. The U.S. EPA and state
government environmental departments have set minimum oxygenate levels for gasoline in areas where
ambient air quality standards are not being attained. The result has been that ethanol, along with other
oxygenates such as MTBE have been increasingly adopted for gasoline blending. Some jurisdictions have
extended gasoline oxygenate requirements in regions or during seasons where ambient air standards are
being satisfied.
Environmental-related climate change policies enhance the prospects for ethanol, since the fuel is derived
from renewable sources and on a lifecycle basis offers lower greenhouse gas emissions versus nonrenewable fossil fuels. However, climate change policies have yet to take hold, such that their influence on
the ethanol fuel business system are minor to date. Climate change policy in Canada is currently under
development. The potential impacts on ethanol may be positive (e.g., induce greater usage of renewable
transportation fuels) or negative (e.g., induce improved automobile efficiency or fuels other than ethanol).
The Transportation Table of Canada’s National Climate Change Process (NCCP) identified ethanol (10%
and 85% blends in gasoline) as one of a large number of possible GHG-emission reduction alternatives.
Ethanol was not identified as one of the Transportation Table’s “Most Promising” options, although it was
classified as a “Promising” option. Most promising options include technology solutions or behaviours
(e.g., not driving in excess of the speed limit) that are: cost-effective (generally have positive benefits or
cost less than 10 $/tonne CO2 reduced); easy to implement; do not involve significant resource sectors; and
they may require additional analysis and design. Promising measures have potential for various levels of
GHG reductions at low to modest cost, or which are included to complement other measures in the
package. They may need some additional analysis or development. The Transportation Table also identified
many Less Promising Measures and Unlikely Measures, the definitions and descriptions of which are
contained in the Transportation Climate Change Table’s options paper16.
In Alberta, ambient air quality is in compliance with existing National Air Quality ozone standards most of
the time, such that oxygenates for gasoline are not currently necessary to meet standards. New proposed
Canada-Wide Standards (CWS) for ground level ozone and particulate matter (PM) may require further
reduction of criteria air contaminants (CAC) emissions, a portion of which come from transportation fuel
combustion.
3.3 Alberta’s Unique Economic Context
Alberta is somewhat unique versus other provinces in Canada and U.S. states in that it contains
representation from most of the entities in the ethanol business system. That is, there is a strong agricultural
industry, which includes grain growing as well as beef cattle production. Similarly, Alberta has by far the
most oil and gas production in Canada and close to one third of the national oil refining capacity.
Furthermore, a portion of its petrochemical capacity is dedicated to production of oxygenates, namely
15
Alberta Resource Development, Oil and Gas Fiscal Regimes of the Western Canadian Provinces and
Territories, Royalty and Tenure Branch, June 1999.
16
Transportation Climate Change Table, Transportation and Climate Change: Options for Action: Options
Paper for the Transportation Climate Change Table, National Climate Change Secretariat, November 1999
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MTBE and methanol. Alberta also has one ethanol producer. With production quantities of grain, cattle, oil
and gas, ethanol, petrochemicals and refined petroleum products well in excess of its own industrial and
population needs, Alberta is heavily dependent on export markets. A feature of the Alberta’s economy is
that it lacks the manufacturing breadth and diversity of Ontario or Quebec economies.
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Table 14: Economic Data for Alberta and Comparison to Canada
Alberta
1990
2.6
0.9
Population (million)
Households (thousands)
Canada
1997
2.8
1.0
1997
30.3
11.6
Alberta
Portion
1997
9%
9%
62
77
570
14%
Total GDP ($1986 Billions)
Total Agriculture GDP
2.2
2.6
11.8
22%
Total Industrial GDP
20.5
28.1
164.8
17%
Value of Output: ($1986 Millions)
Oil & Gas Production, Other Mining
22.0
30.2
48.9
62%
Construction
10.4
11.8
74.2
16%
Agriculture17
7.2
8.3
34.0
24%
Petroleum Refining
4.8
6.2
18.2
34%
Petrochemicals and Other Chemicals
2.6
4.0
9.3
43%
Pulp & Paper
1.0
1.9
26.0
7%
Forestry
0.3
0.6
7.6
8%
Smelting & Refining
03
0.4
10.5
3%
Iron & Steel
0.1
0.2
9.7
2%
Cement
0.1
0.2
0.7
22%
Other Manufacturing
9.9
15.1
272.0
6%
Sources: Natural Resources Canada, Industry Canada, Agriculture and Agri-Foods Canada
3.3.1 Oil & Gas, Petroleum Refining
Alberta’s oil & gas production and oil refining sectors are large and important contributors to the
province’s economy. The value of economic output for the oil & gas industry is sensitive to international
prices for crude oil and the North American price for natural gas, which have both recently been subject to
significant price fluctuations. Production of conventional crude oil is more mature than the development of
synthetic oil from tar sands, which is expected to grow in the near term with substantial new investments
for increased capacity.
17
Agriculture and Agri-Foods Canada, Economic Overview of Farm Incomes, 1996. 1996 data used for
1997 column. 1990 estimated.
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Table 15: Oil Production in Alberta
(thousands barrels per day)
Oil Type
Conventional*
Synthetic
Heavy Oil: Conventional
Heavy Oil: In-Situ and Bitumen
Pentanes
1990
738
208
174
135
110
1997
647
289
267
236
182
Total Oil From Alberta
1,366
*Conventional includes enhanced oil recovery.
Source: Natural Resources Canada
1,622
The natural gas production sector in Alberta is also quite important in that it not only provides heating fuel
for domestic and export markets, it also provides most of the raw materials for the province’s
petrochemical industry, namely methane, ethane and butane. The province’s petrochemical industry
expanded rapidly during the 1980s and 1990s. This assisted in diversifying the Alberta’s economy, and
contributed to large export sales and employment. The petrochemical industry continues to grow with
construction of major new plants underway (see Petrochemicals below).
Table 16: Alberta’s Oil & Gas Energy Production and
Consumption
Production
1997
(Petajoule)
3,660
4,307
Oil Production
Natural Gas Production
Total Oil and Gas
Alberta Consumption
Refined Petroleum Products
Natural Gas
Liquid petroleum gases (LPGs)
7,967
Total oil and gas products demand
1,271
Alberta’s consumption as portion of production
Source: Natural Resources Canada
16%
466
607
197
Alberta’s oil & gas production and oil refining sectors are largely dependent on export markets. Total oil
refining capacity is close to 415,000 barrels per day while oil production is close to 1,600,000 barrels per
day. Alberta’s oil refineries largely supply the western Canadian markets for refined petroleum products.
These include motor gasoline, diesel, heat oils and asphalt. Alberta consumes approximately 16% of the
energy contained in the total oil and gas the province produces. Most of its oil and gas production is
exported, along with a portion of its motor gasoline, diesel and other refined petroleum products.
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Some oil producers operating in Alberta are vertically integrated to oil refining, as well as wholesale and
retail fuels marketing. Integrated oil producers that have refineries are: Imperial Oil; Shell Canada; and
Petro-Canada. Husky in Lloydminster, AB upgrades raw material provided from the adjacent heavy oil upgrader located across the border in Saskatchewan to make asphalt products. Parkland Refining uses natural
gas condensates to produce and retail gasoline and other fuel products.
Table 17: Major Participants in Alberta Oil and Gas, Petroleum
Refining and Fuels Marketing Industries
Company
Location
Crude
Capacity
Bulk Fuel
Outlets ##
(thousands barrels/day)
Imperial Oil Ltd. #
Petro-Canada Inc. #
Shell Canada #
Husky Oil Canada Ltd. *
Parkland Refining Ltd. *
Edmonton
Edmonton
Fort Saskatchewan
Lloydminster
Bowden
Per cent of total
Binks Petroleum Inc.
Federated Cooperative
Tempo
United Farmers of Alberta (UFA)
180
116
89
24*
6
415
100%
86
53
20
9
1
169
55%
1
26
1
112
Total
415
309
Source: Oil & Gas Journal18. Notes: # Oil producers. * No crude charge for Husky Oil in Alberta. It
operates an asphalt plant using raw material from the Saskatchewan heavy oil upgrader. ## The number of
bulk fuel outlets may not be representative of the amount or type of fuel sold by the company.
Integrated producers of transportation fuels (e.g., gasoline, diesel) make optimal supply decisions based on
vertical-integration economics. Depending on the quantities and company-specific operating and marketing
situations, these can be quite different than non-integrated economics. Independent wholesalers/retailers of
gasoline will tend to make purchasing decisions on the purchase cost of fuels available from refiners or
other sources. They will not need to take into account integrated profitability related to oil refining or oil
production, as may integrated operators.
The level of integration in Alberta is generally higher than in most U.S. states and other Canadian
provinces. A major factor is the presence of oil in Alberta and competitive costs for oil refining. The
competitiveness of Alberta’s oil refining industry is enhanced by the abundant availability of nearby
sources of crude oil. However, Alberta has to overcome the lack of large nearby markets by incurring
higher distribution and transportation costs than refiners that are located in proximity to large markets.
Most states and provinces do not have crude oil production and refineries. U.S. states that have favourable
ethanol policies generally have a smaller or no oil refining sectors.
3.3.2 Petrochemical Industry
18
Oil & Gas Journal, Dec. 21, 1998
31
CHEMINFO
Alberta’s petrochemical industry mostly upgrades methane, ethane and butanes contained in natural gas.
Benzene, produced from oil refining operations, is also used as a raw material by the province’s single
styrene producer – Shell Canada. Methane, the major constituent of natural gas, is used to make ammonia,
which can be sold as a liquid fertilizer or reacted to form other fertilizers, such as urea 19, ammoniumsulphate and ammonium-phosphate. Methane also supports the production of the oxygenate methanol.
Methanol is largely exported, although an important Alberta use is in MTBE production. MTBE uses
methanol and butane as basic raw materials.
Alberta’s petrochemical industry continues to grow rapidly. Nova, in conjunction with Union Carbide, is
installing a new 900 kilotonnes/year ethylene/polyethylene complex in Alberta that will be operational in the
year 2000. Meanwhile, Dow Chemical will expand its existing facility at Fort Saskatchewan. Amoco has
announced construction of a linear olefins plant in the province. Imperial Oil Ltd. has considered making an
ethylene investment in the province since the early 1980s but as yet has no capacity in the province. Shell’s
petrochemical investment in Alberta is presently in styrene production. Its plant exports to global markets.
19
Urea is made by reacting ammonia with carbon dioxide.
32
CHEMINFO
Table 18: Alberta’s Major Petrochemical Industry Participants
Company
Products
1997
2000
(kilotonnes/year)
(capacity of bolded product only)
Oxygenates
Methanex
Celanese
Alberta Envirofuels
Methanol
Methanol, Acetic acid
MTBE
830
850
770
570
850
770
Ethylene/Polyethylene
Ethylene/Polyethylene
/VCM, Ethylene glycol
Styrene
1,700
550
2,600*
900*
Ethylene &
Derivatives
Nova Inc.
Dow Chemical
Shell Chemical
450
450
Fertilizers
Agrium
Ammonia, Urea, etc.
2,280
2,280
Canadian Fertilizers
Ammonia, Urea, etc.
1,045
1045
Sources: Cheminfo Services, Camford Information Services. * Expansions under construction.
3.3.3 Alberta’s Agriculture Sector
Two major products from Alberta agriculture sector are wheat grain and beef cattle. Alberta produces a
total of 6.5 to 8 million tonnes of wheat grain annually or approximately 28% of Canada’s total. The
province also contains 5.6 million or 38% of Canada’s beef cattle population. There are also cattle
slaughtering and value-added meat processing facilities in the province.
Table 19: Economic Data on Alberta’s Agriculture Sector20
Economic Data
Number of farms
Total Farm Cash Receipts, 1997
Wheat production (tonnes) 1997
Cattle and calves (head) July 1997
Cattle slaughtered
International Exports
Wheat
Live cattle
Beef and veal
Alberta
Canada
59,007
$6.3 billion
6,839,000
5,605,000
1,909,000
276,548
$29.7 billion
24,270,000
14,912,800
3,480,060
Alberta as
% Canada
21%
21%
28%
38%
61%
$1.38 billion
$661 million
$691 million
$4.3 billion
$1.3 billion
$1.0 billion
32%
50%
68%
Alberta’s production of wheat, beef and meat products exceeds the province’s domestic consumption, such
that grain grower and meat producers are export market oriented. Alberta accounts for approximately one
third of the value of Canadian wheat exports, and close to two thirds of beef and veal exports.
3.4 Ethanol Market Overview
20
Alberta Agricultural Statistics Yearbook 1996.
33
CHEMINFO
The trend toward cleaner, reformulated gasoline in North America has been largely responsible for the
burgeoning ethanol industry. Consumption for ethanol has increased substantially in recent years for use in
ethanol/gasoline blends. Ethanol production capacity in North America has been expanding as a result,
increasing by approximately 2 billion litres per year between 1990 and 1999. Close to 90% of the U.S.
capacity is located in the mid-west corn producing states. Approximately 95% of the industry uses corn as a
raw material in fermentation processes to produce ethanol.
Table 20: North American Capacity, Demand Trends for
Ethanol21
(billion litres)
Capacity
Demand
Transport fuels
Other uses
Total Demand
Canada,
1990
5.9
1995
7.1
1999*
7.9
2005
9.8
3.6
1.1
4.2
1.1
5.0
1.0
6.0
1.1
4.7
5.3
6.0
7.1
Notes: * Start of year 2000 capacity shown. Figures are rounded. Estimates from data provided by Natural Resource
U.S. Energy Information Administration, Camford Information Services, and Cheminfo Services.
The market for ethanol in the Pacific Northwest (PNW) region of North America (including north-western
US states and western Canadian provinces and excluding California) constitutes approximately 6% of the
North American total. The PNW would represent the primary regional market for any potential new
Alberta capacity because of proximity and related transportation costs. The region is a net importer of
ethanol, with customers purchasing from mid-west plants and to a lesser degree from offshore imports.
While ethanol production capacity in the region is currently not sufficient to support local demand, the
potential construction of new, large plants that have been announced or are under consideration for
Washington, Montana, Alberta and Oregon could boost capacity to exceed demand in the PNW (not for
total North America). Beyond the regional market, proponents of these new ethanol plants have
expectations of substantial growth in the California transportation fuel oxygenate market. The growth in the
California market is largely contingent on the phase-out of MTBE22 as an oxygenate in transportation fuel
and the potential switch to ethanol as the preferred oxygenate to meet Federal and California gasoline
standards. Changes in these standards such as the elimination of an oxygen requirement would reduce but
probably not eliminate the growth of ethanol in the California market.
Ethanol is traditionally used as a blending ingredient usually at 5-10% concentrations (termed E5 and E10)
in gasoline or as a raw material to produce high octane fuel ether additives, such as ethyl tertiary butyl ether
(i.e. ETBE). Ethanol may be used in light duty vehicles without engine modification. Ethanol can also be
used in high percentage blends (e.g. E85 - 85% ethanol, 15% gasoline), or even in pure form in vehicles
with modified engines and components.
Ethanol blends of up to 10% in gasoline are approved under the warranties of all major auto manufacturers,
domestic and foreign, marketing vehicles in Canada and the United States. Currently, Ford and
DaimlerChrysler produce flexible fuel vehicles (FFVs) including the Ford Taurus, Ford Ranger Pickup and
21
22
Camford Information Services: CPI Product Profiles, Ethanol 1999 and Renewable Fuels Association.
Methyl tertiary butyl ether
34
CHEMINFO
DaimlerChrysler 3.3 L minivan, that can operate on high level ethanol blends. These vehicles are available
to fleet managers and the general public, at either the same cost or less than the cost of a conventionally
fueled vehicle. One of the largest purchases of FFVs was recently made by the US Postal Service, which
bought 10‚000 E85 FFVs. It has been estimated that in ten years, as many as 5 million vehicles may be
using on non-petroleum motor fuels for a portion of their requirements in the United States. Heavy duty
vehicles have also operated on blends of 90% ethanol and 100% ethanol in successful demonstration
projects.
Ethanol-blended fuels have been used in small engines and other non-automotive gasoline engines since
they first came into the marketplace over 25 years ago. Practically, all mainstream manufacturers of power
equipment, motorcycles, snowmobiles and outboard motors permit the use of ethanol blends in their
products.
3.4.1 Global Market
The growth in global demand for ethanol has been 3 to 4% per year on an average annual basis since the
mid-1980s. Growth in Brazil and the United States has been nearly double that rate at approximately 7%
per year. Canada has seen the installation of new capacity, including a large new facility focused on
supplying the transportation fuel market. This new plant, completed in 1998, practically doubled Canada’s
capacity. Nearly all of the growth in ethanol demand has been in the transportation fuel market. Ethanol
demand for solvent, chemical intermediates, cosmetics and other applications have been growing more
slowly and in some cases declining.
Table 21: Growth in Global Ethanol Production23
(billion litres)
1985
1993
1998
AAG24
1985-98
Canada
United States
Brazil
Other areas
0.1
2.3
5.5
0.1
0.1
4.8
11.7
0.1
0.2
5.5
13.5
0.2
5.5%
6.9%
7.2%
5.5%
Total Americas
8.0
16.7
19.4
7.1%
Europe & Asia
All other areas
10.9
0.3
10.3
0.5
10.3
0.6
(0.4)%
5.4%
Total global
19.2
27.5
30.3
3.6%
Notes: Figures are rounded. U.S. Energy Information Administration, Camford Information Services,
Cheminfo Services.
Growth in world ethanol production will be largely dependent on the development of the transportation fuel
alcohol market. An important driver for expanding ethanol in some nations (such as Brazil) has been the
objective of reducing reliance on oil imports and related international oil pricing. This factor is less
important in Canada and on a near-term practical basis in the United States, where the amount of import oil
23
24
U.S. Energy Information Administration, Renewable Fuels Association and F.O. Licht
Average annual growth rate.
35
CHEMINFO
is very large, such that domestic ethanol production in the foreseeable future would have only a minor
impact on such imports. While, global output of ethanol jumped in the early 1980s and growth rates were
strong up to the mid-1990s, future growth is expected to be slower. In North America, the potential for 2.8
billion litres per year of additional demand in the California oxygenate market will depend on the
continuation of an oxygen content in Federal Reformulated Gasoline and the pace of the State’s phase out
of MTBE. This in part may relate to legal challenges regarding the environmental and health problems
associated with MTBE and the benefits of its phase out. There are many other factors that can affect the
growth of ethanol in North America. These include: the price of crude oil; state provincial and federal
environmental regulations; fuel taxes; along with governments’ support for agricultural communities and
ethanol production.
3.4.1.1 Brazil
Brazil is the world’s largest national producer of ethanol, making approximately 12.5 billion litres per year
of ethanol based on sugar cane as raw material. In 1998, ethanol production fell from 1997 levels due to a
crisis in the Brazilian alcohol industry. However, historically, the industry has grown rapidly. Ethanol
production in the country grew from 0.6 billion litres per year in 1975 to 15.3 billion litres per year in
1997/98, an average annual growth rate of 16%. Brazil began looking for alternative fuel sources in the late
1960s and early 1970s mostly to address the country’s high dependency on crude oil imports. Ethanol
production from sugar cane was chosen as the main alternative. The National Alcohol Program
(PROALCOOL) was started in 1975 to increase the use of ethanol as a fuel substitute for gasoline and to
increase ethanol production for industrial uses. Brazil now has a reported annual capacity for ethanol of
approximately 16 billion litres per year or twice the capacity in North America.
With the recent upturn in crude oil prices25, the low price of ethanol in Brazil has the country’s motorists
turning more and more to the sugar cane-based product to fuel their vehicles. Demand for ethanol vehicles
and gasoline-to-ethanol engine conversions have grown very rapidly in Brazil, according to industry
observers. Producer ethanol prices are about half the current price of gasoline. Pump prices for ethanol in
Brazil are running less than half of what is charged for gasoline.
Fuel ethanol is either anhydrous alcohol that by law is mixed in a 24% blend with every gallon of gasoline,
or 100% alcohol for fueling vehicles that run exclusively on ethanol. While total demand for ethanol blends
has increased, over the years demand had been sliding for 100% ethanol vehicles. Less than 1% of new car
sales were vehicles able to run on 100% alcohol.
The government is considering measures to further encourage ethanol demand, although in 1999, the
Brazilian government scrapped its ethanol price supports and implemented programs that encourage the
200,000 taxis and 80,000 government vehicles in Brazil to renew their fleets with ethanol-only
transportation. Officials are studying plans to boost ethanol blending in gasoline from 24% to 26% and are
considering the feasibility of a 3% blend for diesel fuel. In general, overall production and demand is
expected to continue to grow but a more modest pace than recorded in recent years.
3.4.1.2 United States
Ethanol production and use in the U.S. has also grown significantly since the late 1970s to present day.
Ethanol has been promoted as a solution for a variety of complex problems including addressing the U.S.
dependence on foreign oil supplies, which came to light with the two oil crisis in the 1970s. The Clean Air
Act of 1977 initiated the reduction of leaded gasoline, and ethanol was touted as a replacement for boosting
octane. Ethanol was also promoted to counteract low farm incomes caused by the grain surplus in wake of
25
February 2000 prices nearly 30 US$/barrel.
36
CHEMINFO
the Soviet embargo. Ethanol for fuel use is also being promoted to address environmental issues such as
smog pollution problems. Amendments to the Clean Air Act in 1990 included provisions that certain
regions where required to use oxygenated reformulated gasoline during certain months when ground level
ozone levels (smog) were high. Consideration was also given that a certain percentage of oxygenates be
derived from renewable sources. Ethanol became an oxygenate of choice for much of the market. However,
the oxygenate market in California was effectively closed to ethanol in 1996 when reformulated gasoline
was introduced to the market. As discussed elsewhere in this report, US EPA’s mandated requirements for
oxygenates has changed, along with the potential position of ethanol.
3.4.1.3 Western Europe and Asia
Western Europe produces about 2 billion litres of ethanol per year. Only about 100 million per year or 5%
of that is used for fuel. The European Union has a long-term goal of achieving a 12% share for renewable
fuels by 2010. The European Union decided in 1994 to allow tax concessions for pilot plants producing
renewable fuels such as ethanol. As a result, a number of projects have been announced. Production in
eastern Europe is dominated by the Russian Federation, which estimated capacity of 1 billion litres per year
(excluding beverage alcohol of 1.5 billion litres per year). China is the largest ethanol producer in Asia
followed by India with about 2.7 billion litres of capacity. The slight trend to a drop in production in the
region is the result of inconclusive data from Russia and other regions of the former Soviet Union. The
ethanol industry in these areas is in part “underground”, such that statistics are unreliable.
3.4.2 North American Ethanol Industry
Most of the ethanol consumed in North America is now used for motor fuel, which is the driving force
behind the growth in the industry’s capacity. Nearly 83% of demand is in the transportation market. Other
uses for ethanol are cosmetics, hair sprays, other toiletries, pharmaceutical manufacture, coatings,
adhesives and liquid detergents. Demand for ethanol in North America is concentrated in the eastern half of
the continent. Demand in the U.S. Pacific Northwest, California and the western provinces constitutes less
than 10% of the North American total. However, demand in the California market may expand very
rapidly, depending on the potential phase-out of MTBE and the continued use of oxygenates to achieve
environmental standards.
There are close to 55 ethanol plants in North America. The capacity of these vary tremendously in size,
ranging from 1 million litres per year to approximately 800 million litres per year. The 9 large plants
exceeding 250 million litres per year in capacity account for approximately 60% of total North American
capacity, while 23 facilities with over 100 million litres per year capacity account for 90% of total capacity.
Over 95% of North American capacity is located in the United States. The ethanol industries in the U.S.
and Canada have no common producers. Trade between the two countries as well as with offshore
countries has traditionally been minimal.
Table 22: North American Ethanol Annual Capacity Trend
(billion litres - rounded)
1990
5.8
1995
7.0
2000
7.6
% of total
96%
Canada
0.1
0.1
0.3
4%
Total North America
5.9
7.1
7.9
100%
United States
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CHEMINFO
In the United States, passing of the “Transport Efficiency Act of the 21 st Century” in 1998, which is an
extension of ethanol tax incentives through 2007, along with other incentive programs in the context of
increased growth in demand, has resulted in new ethanol projects being announced. There have also been
proposals for new capacity in Canada.
Prior to the 1970s, ethanol production by fermentation (excluding that for beverages) had been declining in
the U.S. since synthetic ethanol was introduced in the 1930s, because of the low cost and assured
availability of “synthetic” raw material ethylene. The quadrupling of the selling price of crude petroleum
by OPEC in 1973 had a profound impact on fermentation processes for producing ethanol. The U.S. Dept
of Energy set objectives to develop methods to derive fuels economically from sugar crops and corn, to
evaluate the potential feasibility of the various methods, and to suggest means of practical application. This
program resulted in many economic studies and laboratory research programs. Interest then waned as the
price of oil dropped, until 1979 when the Islamic revolution in Iran caused another oil crisis. State and
federal tax subsidies and loan guarantees fueled the growth of fermentation ethanol capacity in the early
1980s. In 1980, loan guarantees of nearly US$342,000,000 from the Farmers Home Administration were
approved for 15 new plants in 14 states to produce 931 million litres per year for fuel as part of the synfuels
program. In the mid-1980s the phase-out of lead as an octane enhancer in gasoline kept the fuel ethanol
program moving forward. The 1990 Clean Air Act requirements for oxygenates and renewal of the Federal
tax rebates worth approximately US$ 0.16 per litre of ethanol pumped new life into the fuel ethanol
program in the late 1980s.
A small portion of ethanol production in North America continues to be made synthetically from ethylene.
The synthetic route supplies most of the industrial market in the United States. However, the proportion of
ethanol made from ethylene has been declining over the last two decades. Most recently, Eastman
Chemical Company closed its closed its 102 million litre/yr synthetic ethanol plant in Longview, TX early
in 2000. The plant was closed because it was outdated and antiquated, according to the company. Another
factor in the closure of the plant is a pricing trend toward fermentation-based ethanol and away from
synthetic ethanol. Eastman believes that presently and in the future, fermentation-based ethanol will be the
price leader. Commercial Alcohols closed its synthetic ethylene-based ethanol plant in Varennes, QC in the
1980s.
Close to 83% of ethanol demand in North America is for transportation fuel. Use in solvent, chemical
intermediates, pharmaceuticals and other applications are a minor and slower growing portion of demand.
Table 23: Total North American Ethanol Demand26
(billion litres)
Applications
Transportation fuels
Solvents
Chemical intermediates
Other uses
26
1990
3.6
0.5
0.3
0.3
1995
4.2
0.5
0.3
0.3
1999
5.0
0.4
0.3
0.3
% of total
83%
7%
5%
5%
Total demand North America
4.8
5.3
6.0
100%
United States Consumption
4.7
5.2
5.8
97%
Camford Information Services: CPI Product Profiles, and Chemical Marketing Reporter
38
CHEMINFO
Canadian Consumption
0.1
0.1
0.2
3%
Notes: Figures are rounded. Estimates from data provided by Natural Resource Canada, U.S. Energy Information
Administration, Camford Information Services, and Cheminfo Services.
Ethanol currently accounts for approximately 1% of the gasoline and blended gasoline market in North
America. Ethanol competes with other oxygenates and octane boosters for reformulated gasoline. The
major competitive oxygenate is MTBE. Competitive octane enhancing products include MTBE, other
oxygenates as well as the manganese based additive MMT.
Table 24: Position of Ethanol in the Estimated North American
Gasoline-Oxygenate Market27
(billion litres - 1999)
Gasoline (only)
MTBE
Ethanol
ETBE and TAME
Methanol
North America
486
16
5
0.04
0.01
% of total
96%
3%
1%
<<0.1
<<0.1
507
100%
Total (rounded)
Note: Figures are rounded. Estimates from data provided by Natural Resource Canada, U.S. Energy Information Administration,
Camford Information Services, and Cheminfo Services. Does not include diesel and other transportation fuels.
3.4.2.1 U.S. Ethanol Capacity
There are approximately 40 ethanol producers in the United States operating close to 50 plants. Archer
Daniels Midland (ADM) stands out as the dominant ethanol producer with upwards of one third of the total
capacity. ADM is a broad, diversified corporation heavily involved in agricultural related businesses (i.e.,
feeds, seeds, oils, etc.). Petrochemical firms are not well represented in the ethanol industry, Equistar being
an exception that makes ethanol from ethylene. Eastman recently closed its synthetic ethanol plant.
Table 25: Regional U.S. Ethanol Capacity Trends
(billion litres)
Region
Mid-west states
1990
4.8
1995
6.0
2000
6.7
% of Total
88%
0.5
0.2
0.03
0.5
0.2
0.04
0.5
0.2
0.04
5%
3%
<1%
California
Other States
0.03
0.2
0.03
0.2
0.03
0.2
<1%
3%
Total U.S. Capacity
5.8
7.0
7.6
100%
(IA, IL, MN, SD, ND, KS, KY)
Texas(practically all synthetic from ethylene)
Ohio
U.S. Pacific Northwest
(WA, MT, ID, OR, NV)
27
Natural Resources Canada, Camford Information Services, U.S. Energy Information Administration
39
CHEMINFO
Source: Cheminfo Services. Camford Information Services.
Table 26: Year 2000 Capacity of U.S. Ethanol Producers
Company
Location
State
Feed
Archer-Daniels-Midland (ADM)
Archer-Daniels-Midland (ADM)
Archer-Daniels-Midland (ADM)
Archer-Daniels-Midland (ADM)
Union Carbide
Williams Energy Services
New Energy
Minnesota Corn Processors
Cargill
South Point Ethanol
Grain Processing
Midwest Grain Products
Midwest Grain Products
Equistar Chemical
AGP
A E Staley
High Plains Corp.
Minnesota Corn Processors
Cargill
Williams Energy Services
Archer-Daniels-Midland (ADM)
Chief Ethanol Fuels
High Plains Corp.
Corn Plus
CVEC
Heartland Corn Products
Al-Corn
Central Minnesota
Ethanol2000
Minnesota Energy
Agri-Energy, LLC
Alchem
Reeve Agri-Energy
Pro-Corn
High Plains Corp.
Morris Ag Energy
Heartland Grain Fuel
Broin Enterprises
Parallel Products
Parallel Products
Georgia Pacific
Golden Cheese Co. of California
J.R. Simpot
J.R. Simpot
Kraft Inc.
MMI/ETOH
Minnesota Clean Fuels
ESE Alcohol
Kor Ethanol
Jonton Alcohol
Miller Brewing
Vienna Correctional
Decatur
Peoria
Cedar Rapids
Clinton
Texas City
Perkin
South Bend
Columbus
Blair
South Point
Muscatine
Perkin
Atchison
Tuscola
Hastings
Loudon
York
Marshall
Eddyville
Aurora
Walhalla
Hastings
Colwich
Winnebago
Benson
Winthrop
Claremont
Little Falls
Bingham Lake
Buffalo Lake
Luverne
Grafton
Garden City
Preston
Portales
Morris
Aberdeen
Scotland
Rancho Cucamonga
Louisville
Bellingham
Corona
Caldwell
Burley
Melrose
Golden
Dundas
Leoti
White
Edinburg
Olympia
Vienna
IL
IL
IA
IA
TX
IL
IN
NE
NE
OH
IA
IL
KS
IL
NE
TN
NE
MN
IA
NE
ND
NE
KS
MN
MN
MN
MN
MN
MN
MN
MN
ND
KS
MN
NM
MN
SD
ND
CA
KY
WA
CA
ID
ID
MN
CO
MN
KS
SD
TX
WA
IL
Corn
Corn
Corn
Corn
Ethylene
Corn
Corn
Corn
Corn
Corn
Corn
Corn/wheat Starch
Corn/wheat Starch
Ethylene
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Corn
Food waste
Food waste
Paper waste
Whey
Potato waste
Potato waste
Whey
Brewery waste
Waste sucrose
Corn
Wheat
Corn
Brewery waste
Corn
Total capacity
kilotonnes
million litres
640
610
608
485
360
300
255
216
200
195
180
155
155
150
135
135
125
105
100
100
90
90
50
50
50
48
45
45
45
36
35
32
30
30
30
25
24
21
15
15
10
9
9
9
9
5
5
3
3
3
2
1
800
760
760
608
450
375
319
270
250
244
225
194
194
188
169
169
156
131
125
125
115
113
63
63
63
60
56
56
56
45
44
40
38
38
38
31
30
26
19
19
13
11
11
11
11
6
6
4
4
4
3
1
million US
gallons
211
200
200
160
118
99
84
71
66
64
59
51
51
49
44
44
41
34
33
33
30
30
17
17
17
16
15
15
15
12
12
11
10
10
10
8
8
7
5
5
3
3
3
3
3
2
2
1
1
1
1
0.3
6,083
7,610
2,005
Sources: Cheminfo Services Inc., Camford Information Services Inc., Bryan & Bryan Inc., California
Energy Commission28
28
California Energy Commission Report, Evaluation of Biomass-to-Ethanol Fuel Potential in California,
Draft Report August 1999.
40
CHEMINFO
Practically all of the fermentation ethanol in the United States is produced in the mid-west, close to the
growing of the raw material corn. Texas boasts one large ethanol plant but it is based on ethylene raw
material and generally serves the industrial chemicals market. There is practically no capacity in California
and the Pacific North-western states, which together account for less than 1% of U.S. capacity.
More than 40 new plants are being considered in the United States, although it is unlikely that all of these
potential facilities will be constructed. The interest in new ethanol capacity is in context of favourable
investment and market factors. Major factors in the United States include:






probable phase-out of MTBE in California blended-gasoline market;
continuation of federal tax exemptions to the year 2007;
state and local government tax exemptions and investment incentives;
accessible gasoline distribution channels through non-integrated gasoline wholesalers and
retailers;
continued environmental pressures on transportation emissions (including greenhouse
gases); and
mid-west corn grower stakeholders possess significant influence with regional
governments.
On the negative side, US EPA recently eliminated the mandated requirement for oxygenates in gasoline.
States can apply other technology solutions to achieve air quality standards, which may use of ethanol. The
new “Renewable Fuels Standard” has been proposed that favours ethanol, although the form of this
standard is not available and consequently presents business uncertainty for ethanol suppliers.
Some of these favourable factors are not present in the Canadian market. For example, implementation
plans (or regulations) for reduction of ground level ozone have yet to be developed in Canada. As a result,
it is unclear whether governments in Canada will regulate oxygenate levels in gasoline to address regions
that are not in achievement of existing or new proposed air quality standards. Therefore, environmental
pressures for increased use of oxygenates in gasoline are less in Canada. The ethanol market in the United
States has more accessible wholesalers and retailers that are not integrated to gasoline production (i.e.,
crude oil refining) There are more independent fuel wholesalers in the U.S. who are the main buyers of
ethanol for splash blending into gasoline. In Canada, blending and distribution of gasoline is more
concentrated among the major oil refining companies.
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CHEMINFO
3.4.2.2 U.S. Ethanol Demand
Over 80% of the ethanol made in the United States is consumed in motor gasoline blends. The requirement
of the Clean Air Act amendments require minimum levels of oxygenates be incorporated in areas where
minimal standards of air quality are not in attainment (i.e., non-attainment areas). The use of ethanol as a
fuel in the U.S. has grown dramatically, starting in the 1980s, when annual growth rates were reported to be
around 25%. Fuel use has continued in the 1990s, with growth rates of 3% per year range.
Table 27: Trend in United States Ethanol Demand29
(billion litres)
Transportation fuels
Solvents
Chemical intermediates
Other uses
Total U.S. demand.
Totals may not add due to rounding.
1990
3.7
0.5
0.3
0.3
1995
4.2
0.4
0.3
0.3
1999
4.8
0.4
0.3
0.3
4.7
5.2
5.8
In the United States, the rationale underlying ethanol use as a transportation fuel has evolved over time. It
has shifted in emphasis from an energy substitute for imported crude oil replacement, to use as an
oxygenate (to achieve ground level ozone air quality standards), and more recently it is receiving attention
as a renewable fuel that can achieve greenhouse gas emission reductions. Ethanol is currently entrenched in
the oxygenate fuel market, competing mostly with MTBE in most U.S. markets. However, depending on
the nature of future environmental regulations, this position may change.
29
Camford Information Services: CPI Product Profiles, and Chemical Marketing Reporter
42
CHEMINFO
Table 28: Position of Ethanol in the U.S.
Gasoline-Oxygenate Market30
(billion litres)
Gasoline (only)
MTBE
Ethanol
ETBE and TAME
Methanol
Total (rounded)
United States
450
16
4.8
0.04
0.01
% of total
96%
3%
1%
<<0.1
<<0.1
471
100%
Note: Figures are estimated and rounded. Estimates from data provided U.S. Energy Information Administration, Camford
Information Services, and Cheminfo Services. Does not include diesel and other transportation fuels.
In 1997, ethanol made up approximately 1% of the amount of gasoline used in the United States. Initially
the value of E10 was seen as a gasoline extender that helped to reduce dependence on imported petroleum
while stimulating the U.S. economy, especially in the rural areas. With regulations on the composition of
gasoline in areas where air pollution has been a problem, fuel ethanol has taken on a role as an oxygenated
gasoline additive. Additionally, the use of ethanol as an antiknock additive to replace tetra-ethyl-lead (TEL)
formerly added to premium gasoline has also been recognized.
In California, regulatory policies of the California Air Resources Board (CARB)
essentially precluded ethanol from the oxygenate market for California reformulated
gasoline (CA RFG). CARB policy limited the amount of oxygen in California RFG to a
maximum of 2% oxygen (corresponding to 10% ethanol), thus preventing the utilization
of vapour pressure allowance for ethanol. (Although this limit is now removed). Refiners
were unwilling and in some cases incapable of producing a base gasoline that can be
combined with ethanol at 2% oxygen content and meet the vapour pressure requirement
of CA RFG without the vapour pressure allowance. However, ethanol now can be used in
California gasoline up to 10% as long as it meets all of the requirements of California
Clean Burning Gasoline. Blending ethanol at less than 10% by volume also reduced the
value of federal tax incentive, which effectively increases the cost of ethanol.
Consequently, ethanol (which historically enjoyed a significant market presence in
California) has not been used in California for a period around 1996 since CA RFG was
introduced. This created a dominant position for MTBE in California. It was reported by
the California Environmental Protection Agency that in 1998 ethanol accounted for only
about 3% of the oxygenates in gasoline in the state.
Table 29: Position of Ethanol in Total On-Road Plus
Off-Road Fuel Markets31
(1997 Gasoline Equivalent Basis for US)
30
31
Natural Resources Canada, Camford Information Services, U.S. Energy Information Administration
U.S. Energy Information Administration, U.S. Department of Energy
43
CHEMINFO
United States
97.3%
0.5%
2.0%
0.15%
0.04%
0.001%
0.01%
Gasoline plus diesel
Ethanol in gasohol
MTBE
Liquefied Petroleum Gases (LPG)
Natural Gas (compressed & liquefied)
Methanol (M8532 &M100)
Biodiesel
3.4.2.3 Canadian Ethanol Capacity
There are five ethanol producers in Canada operating six plants. Commercial Alcohols with two plants in
Ontario accounts for 70% of Canadian capacity. Commercial Alcohols shifted its production from synthetic
ethanol made from ethylene in Quebec (in the 1970s and 1980s) to fermentation ethanol in Ontario based
on using corn grown in the province. Ontario accounts for approximately 80% of Canada’s corn
production. Three relatively small producers in Alberta, Saskatchewan and Manitoba account for 20% of
Canada’s remaining production. Tembec remains the only producer in Quebec. The company makes
ethanol based on waste products from its pulp mill located in Temiscaming.
Table 30: Trend in Regional Canadian Ethanol Capacity
(billion litres)
Province
Ontario
Quebec
Western Canada (MB, SK, AB)
1990
0.01
0.09
0.01
1995
0.02
0.03
0.02
2000
0.17
0.03
0.05
Canada Total
0.11
0.07
0.25
In 1998, Commercial Alcohols completed construction of a fermentation based ethanol plant at Chatham,
ON. The Chatham site was selected because of its proximity to Ontario corn production and major Ontario
oil refineries, where ethanol could be blended with gasoline. The local Kent County corn-growers
community and the municipality of Chatham were actively engaged in assessing the feasibility of the plant
and promoting the location. The facility has a capacity for 150 million litres/yr (120 kilotonnes, 40 million
US gallons). Output is sold in the eastern Canadian and the north-eastern United States gasoline fuel
market. Much of the DDG is exported to the United States.
In Canada, engineering work has commenced on a new 150-million-litre/yr ethanol plant to be built by
Commercial Alcohols at Varennes, QC. The Quebec government helped make the $105-million project
possible when it announced plans to reduce its tax on fuel ethanol. Commercial Alcohols and the
Federation des Producteurs de Cultures Commerciales du Quebec (FPCCQ) were to be the main partners.
Petro-Canada indicates it has signed an agreement to take a portion of the output. Commercial Alcohols
had considered doubling the capacity of its Chatham, ON plant, although the state of that expansion is now
uncertain.
32
The remaining portion of 85% methanol is gasoline. Consumption data includes the gasoline portion of
the fuel.
44
CHEMINFO
Table 31: Canadian Ethanol Plant Capacities
(million litres)
Company
Commercial Alcohols
Commercial Alcohols
Temeco Enterprises
API Grain Processing
Pound-Maker Agventures
Mohawk Oil
Commercial Alcohols
St Lawrence Starch
Ontario Paper
North West
Location
Chatham, ON
Kincardine, ON
Temiscaming, PQ
Red Deer, AB
Lanigan, SK
Minnedosa, MB
Varennes, PQ
Mississauga, ON
Thorold, ON
Kerrobert, SK
1976
1980
70
15
4
Total
89
1990
1995
12
18
25
25
4
70
9
70
4
3
3
81
112
10
10
2000
150
25
25
22
13
10
70
245
Source: Camford Information Services, Cheminfo Services Inc.
Metalore Resources, Sunthetic Energy, Canadian Agra, Seaway Valley Farmers Energy Co-operative and
Plains Foods Fibre are among the companies that have considered constructing ethanol plants in Canada.
3.4.2.4 Canadian Ethanol Demand
The substantial jump in Canadian demand for ethanol in the period 1998-1999 was largely a result of
Sunoco’s decision to blend the oxygenate into gasoline it retailed in Ontario. Use of ethanol for fuel in the
rest of Canada as well as other applications have been growing more slowly. Demand for ethanol as a
solvent in some applications has been declining, in part a result of environmental factors. Ethanol is
considered a volatile organic compound (VOC) precursor to formation of ground level ozone. Some
Canadian environment initiatives as well as spill-over effects from US environmental regulatory programs
have negatively influenced demand in coatings, adhesives and other solvent applications.
Table 32: Trend in Canadian Ethanol Demand33
(million litres – 100% Ethanol basis)
Fuels
Solvent uses
Vinegar
Liquid detergents & cleaners
Miscellaneous
Total domestic demand
33
1976
0
25
5
2
2
1981
4
30
5
2
2
1990
11
25
5
2
2
1993
24
28
6
2
2
1999
150
27
8
3
2
34
43
45
62
188
Camford Information Services: CPI Product Profiles, and Chemical Marketing Reporter
45
CHEMINFO
Export sales
31
39
6
0
15
Total disappearance
65
82
51
62
213
Source:
Camford Information Services, Cheminfo Services Inc.
1999 exports based on November year-to-date total pro-rated for 12 months.
Canadian export sales of ethanol have dropped to low levels since Commercial Alcohols closed down its
large synthetic ethanol plant in Varennes, PQ.
3.4.2.5 Canadian Use of Ethanol Gasoline Blends
The level of consumption of fuel ethanol in Canada for 1998/1999 is estimated to be nearly 150 million
litres per year34. Across Canada, there are approximately 929 retail outlets for ethanol-blended fuels
(November, 1998), excluding those that are not listed with the Canadian Renewable Fuels Association.
Ethanol blends are usually sold at approximately the same price as conventional gasoline fuel.
The first Canadian commercial venture into renewable ethanol fuel in Canada was in the early 1980s by
Mohawk Oil Company, a B.C. based firm. Mohawk renovated a distillery in Minnedosa, MB and began
retailing wheat-based ethanol blends in Manitoba in 1981. The program was expanded to include all
Mohawk premium gasoline in western Canada in 1988. In 1992 an ethanol blended regular grade gasoline
was introduced at all Mohawk stations outside of Manitoba. In 1992, UCO Petroleum (now UPI Inc) first
launched ethanol blends in Ontario. Retailers in Ontario, where production is based on corn, are now the
national leaders in selling ethanol blends. 35 The province of Quebec began retailing ethanol blends in 1995
and now has the second largest retailing base in the country.
Mohawk Oil is presently selling ethanol blends at over 290 stations in B.C., Alberta, Saskatchewan,
Manitoba, the Yukon and northern Ontario. Across southern Ontario, UPI retails ethanol blends at over 60
UPI, FS and Co-op gas bars and card locks. It is available in all grades of gasoline and for on-farm
delivery. On January 1, 1998 Sunoco launched ethanol-enhanced fuels at all of its 275 retail outlets in
Ontario. The company ramped up sales in 1998 with supply from Commercial Alcohols’ new Chatham,
ON ethanol facility. In eastern Ontario and western Quebec, MacEwen Petroleum is retailing ethanol
blends at over 60 locations. Fuel ethanol retailing has expanded into Quebec with over 100 Sonic stations
and other independent retail outlets. Other companies that have joined in the retailing of ethanol-blended
fuels include Mr. Gas, Pioneer Petroleum, Frances Fuels, Stinson Petroleum and Sunys.
Table 33: Position of Ethanol in the Estimated Canadian
Gasoline-Oxygenate Market36
(billion litres)
Gasoline
Ethanol
ETBE and TAME
Methanol
MTBE
Canada
36
0.15
0
0
0
% of total
99.6%
0.4%
<<0.1
<<0.1
<<0.1
36.2
100%
Total (rounded)
34
Camford Information Services, CPI Product Profiles: Ethanol May 1999.
Canadian Renewable Fuels Association
36
Natural Resources Canada, Camford Information Services, U.S. Energy Information Administration
35
46
CHEMINFO
Note: Figures are rounded. Estimates from data provided by Natural Resource Canada,
Camford Information Services and Cheminfo Services. Does not include diesel and other transportation fuels.
3.4.3 Alberta Transportation Fuels Market
The market for on-road and off-road transportation fuels in Alberta in comprised of approximately 1.9
million vehicles that consume 10 to 11 billion litres per year of liquid fuels. These include gasoline, diesel,
propane, natural gas and ethanol.
The transportation fuels business in Alberta is somewhat different than most other provinces (especially
non-prairie provinces), with respect to considering the potential and economic value of ethanol. Important
features of the Alberta fuels market related to ethanol are:

greater weighting on agricultural segments of the market;

greater presence of farm co-operatives in wholesale/retail distribution channel; and

three large vertically integrated oil refineries, and one small non-integrated refinery
creating substantial provincial oversupply of gasoline and other petroleum based
products.
Alberta’s transportation fuels market, similar to the other prairie provinces, has a greater emphasis on the
farm segment. The ratio of gasoline used in passenger cars versus farm vehicles in Alberta is approximately
4.8, which is slightly higher than Manitoba’s and the ratio in Saskatchewan. By comparison the ratio in
Ontario is 32.9, 43.7 in British Columbia and similarly high in other provinces with large urban
transportation segments.
Table 34: Provincial Ratios of Gasoline Use for Passenger Cars
Versus Farm Vehicles
(energy content ratio basis)
Region
Saskatchewan
Manitoba
Alberta
Ontario
BC
Atlantic provinces
Quebec
Source: Natural Resources Canada
Based on 1997
1.8
4.6
4.8
31.9
43.7
52.7
80.6
The ratios of gasoline trucks and light duty diesel trucks in Alberta are also higher than non-prairie
provinces. These segments of the Alberta market are also growing faster than gasoline passenger vehicles,
according to Natural Resources Canada. One factor contributing to the slower growth in fuels required for
the passenger car segment is the improved efficiencies expected from new vehicles over time. Although
gasoline and diesel trucks are also expected to improve efficiencies, these are anticipated to be lower.
Table 35: Projected Trend in Vehicle Population in Alberta
(thousands of vehicles)
1995
983
668
Passenger cars (all fuels)
Gasoline trucks
47
2000P
1024
739
2010P
1172
972
CHEMINFO
Light diesel trucks
Heavy diesel trucks
51
31
72
38
92
44
Total vehicles
1,733
Source: Natural Resources Canada
1,873
2,280
The Alberta fuel ethanol market is currently a small fraction of the total gasoline made or used in the
province. There is approximately 5 billion litres of annual gasoline demand in Alberta (on-road and offroad vehicles). The amount of fuel ethanol consumed is less than 0.1% of the total market for gasoline in
the province.
Table 36: Trends in Transportation Fuel Demand in Alberta37
(million litres)
Gasoline
Diesel
Propane
Natural gas
Other fuels
1995
4417
4046
353
1
14
2000P
5101
5597
137
1
31
2010P
6140
7528
47
1
83
Total
8831
10868
13799
(petajoules)
Gasoline
153
175
210
Diesel
157
217
291
Propane
9
4
1
Natural gas
0
0
0
Other fuels
1
1
3
Total
319
397
505
(Percent of petajoules)
Gasoline
47.9% 44.2% 41.5%
Diesel
49.1% 54.6% 57.6%
Propane
2.8%
0.9%
0.2%
Natural gas
0.1%
0.1%
0.0%
Other fuels
0.2%
0.3%
0.6%
The development of a substantial market for ethanol (i.e., 200 million litre/year) in Alberta requires the
integrated oil refiners/wholesalers to purchase the product. Imperial Oil, Shell and Petro-Canada account
for between 65 to 80% of the retail gasoline sold in Alberta. These firms account for a large portion of
retail outlets in the province and even a higher portion of gasoline sales due to their strong presence in the
larger urban markets.
Table 37: Approximate Number of Retail Stations in
Prairie Provinces, 1997
Company
Imperial Oil Ltd. (Esso)
Shell / Turbo
Petro-Canada
Husky/Mohawk
37
Alberta
Alberta
Sask.
Manitoba
Total
20%
20%
10%
17%
297
292
154
255
179
115
83
55
164
456
101
70
640
863
338
380
Source: Natural Resources Canada.
48
% of
Total
19%
26%
10%
11%
CHEMINFO
Fas Gas
United Farmers of Alberta
DOMO
Co-op / Tempo
7/11
Canadian Tire
Hughes
13%
6%
2%
6%
4%
1%
2%
Total
100%
Sources: Octane. Industry sources.
200
96
27
92
53
15
30
58
0
6
309
26
3
6
0
25
173
17
6
264
96
58
574
96
24
30
8%
3%
2%
17%
3%
1%
1%
1,511
834
1,018
3,363
100%
3.4.4 Canadian Trade in Ethanol
The pattern of Canadian trade in ethanol has changed over the years. Canada was a net exporter of ethanol
in the 1970s, but export sales dropped to low levels since Commercial Alcohols closed its synthetic ethanol
plant in Varennes, QC in the 1980s. In 1999 Canada imported more ethanol than it exported.
Table 38: Trend in Canadian Ethanol Trade
(million litres)
1976 1981 1990 1999
Exports
39
49
8
27
Imports
(0)
(3)
(0)
(75)
Net exports
39
46
8
(48)
Source: Statistics Canada. Includes denatured and undenatured. 1999 are estimates based on year-to-date
November data. May include product less than 100% ethanol, which may result in differences versus trade
in Table 32 above.
Trade in ethanol covers movement of product that is used for alcoholic beverages, industrial solvents as
well as transportation fuels. The unit values of these grades are quite different, with transportation fuels
being the lowest priced (There may be different grades included within each of the commodity categories
such that the average unit values of the imports may be a mix of grades.) Over 95% of ethanol imports
come from the United States.
Table 39: Ethanol Trade November 1999 Year-to-Date
Imports
Description
Spirits nes denatured
of any strength
Ethyl alcohol, nes,
denatured, of any strength
Ethyl alcohol,
denatured, in accordance
with specs of
excise act and regulations
Ethyl alcohol,
nes, undenatured ?80% vol.
Code
Quantity
Total Value
Average
Unit Value
(million litres)
(C$ million)
(¢/litre)
2207209000
34.3
20.8
61
2207201900
0.1
0.2
126
2207201100
11.2
9.4
84
2207109000
16.6
7.7
47
49
CHEMINFO
2207101000
Ethyl alcohol
undenatured ?80 vol,
for use as or for mfr
of spirituous/alc bev
Total November 1990 YTD
6.7
5.4
81
68.9
43.5
63
75
47
63
Quantity
Total Value
Average
Unit Value
Estimated total 1999
Code
Exports
Description
Ethyl alcohol and
other spirits, denatured,
of any strength
Undenatured ethyl alcohol
strength by vol of 80% vol
or higher
Total November 1990 YTD
(million litres)
(C$ million)
(¢/litre)
22072000
7.3
6.6
90
22071000
17.3
19.4
112
24.6
26.0
106
27
28
106
Estimated total 1999
Canada’s ethanol exports are not concentrated on the United States market. In 1998 the United States only
accounted for 30% of exports. The Commonwealth of Independent States (CIS) have recently become
major exporting destinations for denatured and undenatured grades of ethanol.
Table 40: Canadian Ethanol Exports by Destination, 1998
(million litres)
Code
Ethyl alcohol and
other spirits, denatured,
of any strength
Undenatured ethyl alcohol
strength by vol of 80% vol
or higher
Total
USA
Georgia
All Other
Countries
0.7
Total
1.9
Ukraine,
Russia
0.6
22072000
1.8
22071000
5.3
10.4
3.5
0.2
19.4
7.1
12.3
4.1
0.9
24.4
5.0
3.4.5 Pacific Northwest Ethanol Market
To date, ethanol demand in the Pacific Northwest of the U.S. has been driven primarily by federal and state
Clean Air Act requirements mandating the use of oxygenates in winter gasoline to lower emissions. There
is currently a capacity shortfall in the region such that ethanol is sourced from the mid-west U.S. and from
imports. Demand for ethanol in the Pacific Northwest of the U.S. dropped for transportation fuel when the
Seattle area in Washington achieved ambient standards of environmental attainment for carbon monoxide.
50
CHEMINFO
Table 41: Trend in Demand for Ethanol in PNW38
(million litres)
1992
431
58
Transportation fuel
All other applications
1995
431
61
1997
290
63
Total
489
492
353
Includes Western Canadian provinces
Capacity in the region (including western provinces) has doubled over the last decade, with new plants in
Alberta and Wyoming. However, these capacity additions have been relatively small in context of meeting
local demands. The region imports a large percent of its ethanol requirements.
Table 42: Ethanol Capacity in PNW
(million litres/year)
States
Washington
Montana
Oregon
Idaho
Wyoming
Provinces
Alberta*
British Columbia
Saskatchewan
Total
1990
16
23
-
1998
16
23
19
200539
329
114
114
23
19
4
40
22
16
93
22
16
637
* Excludes as base case announcements for new Alberta and BC capacity
To date, ethanol producers in the PNW have to date installed facilities that are small in comparison to many
plants in the mid-west regions. For example, the Commercial Alcohol plant in Chatham, ON with
approximately at 150 million litre/year capacity is about 7 times larger than the biggest of the PNW plants.
Table 43: Some Ethanol Producers in PNW
Company
Location
Type of Plant
Capacity
Market Focus
(million litre/yr)
API Grain Processing
Georgia Pacific
Red Deer, AB
Bellingham,WA
Wheat, gluten
Pulp waste
22
13
Miller Brewing
Olympia, WA
Distilled spilled beer
3
J.R. Simplot
Caldwell, ID
Burley, ID
Potato skin wastes
23
38
100% fuel
70% fuel
30% industrial
60% fuel,
40% food
100% fuel
Estimate of demand in Montana and Idaho from state authorities, Washington, Montana, Oregon and
Nevada data from U.S. Energy Information Administration.
39
This forecast assumes proposed/announced ethanol projects in Washington, Montana and Oregon are
constructed.
51
CHEMINFO
Wyoming Ethanol
Torrington, WY
Dry process,
corn, sorgham
19
100% fuel
Total regional
80
Note: Excludes Saskatchewan
There are a host of new plants being proposed for the PNW. Not all may come to fruition. Some of the
proposed plants have been announced and “on the books” for years. Most proposed are large scale (over
100 million litre/year) although predicated on using a variety of fermentable raw materials including wheat,
corn, potato wastes and wood wastes. (Alberta potato production is growing.) If all of the
announced/proposed capacity is constructed, the region will have an overcapacity situation versus regional
demands. In total, the regional overcapacity could reach 200 to 300 million litres/year, or the equivalent of
2 to 3 large plants. Potential new installations have expectations regarding the growth in the California
market.
Table 44: Proposed Ethanol Capacity in the PNW40
Company
Location
Type of Plant
American Agri-Tech
Great Falls, MT
Agra Processing
Pacific Rim Ethanol
Pacific Rim Ethanol
Sustainable Energy
Moses Lake, WA
Moses Lake, WA
Longview, WA
Central Region, OR
Dry process,
wheat/barley
Potato waste
Dry process, grain
Dry process, grain
Wood waste
Total
Capacity
(Million litres/yr)
114
11
152
152
114
543
API Grain Processing operates Alberta’s only commercial ethanol plant. The 22 million litre/year ethanol
facility at Red Deer, AB was started in June of 1998. The Red Deer complex is mainly a grain processing
facility. The company says this grain fractionation facility is the first of its kind in North America and uses
wheat as its feedstock in the initial stages of production. The plant produces bread flour, high quality vital
wheat gluten, motor fuel grade ethanol and livestock feed. API has a market partnership agreement with
International Marketing Associates (IMA). IMA plays a key role in marketing the motor fuel grade ethanol.
IMA distributes fuel grade ethanol, fuel additives and oil field chemicals throughout the U.S. and Canada.
IMA has been marketing fuel grade ethanol since 1980 to gasoline marketers and refiners. There are a
number of proposals for plants in the province.
There are no known commercial ethanol plants currently in production in British Columbia. There are two
groups reported to be working on ethanol projects. One group is proposing a grain fraction plant in the
Peace River area, the other claims to have technology to convert wood waste to ethanol and is proposing a
plant in Prince George.
Montana does not currently produce ethanol, but does have some proposed ethanol plants. One proposed
plant has reached the stage of regulatory approval. The plant to be located in Great Falls, MT would have a
capacity of 114 million litre/yr. According to state spokespeople, output from the plant could be shipped by
railcar to the California market.
40
Source: Bryan & Bryan, October 1999.
52
CHEMINFO
The state of Washington has two ethanol plants in operation and one, Agra Processing at Moses Lake, is
said to be in the start-up mode. The state has studied the feasibility of ethanol from biomass using
agricultural wastes. The ethanol would be targeted for the fuel market to meet requirements for a 7%
reduction in emissions from the state’s transportation sector. Spokespeople for the Washington’s energy
program think any future ethanol production facilities would be targeting the California market.
Two ethanol plants in Idaho operated by J.R. Simplot are in production. There are no known proposed
ethanol plants, according to state officials.
Montana has about 35 gasoline stations selling an ethanol fuel blend. The stations are located mostly in the
north-eastern part of the state. There is one non-attainment area in the state for CO at Missoula. From
November 1 to the end of February there is a mandate to oxygenate fuels to have a 2.7% oxygen content.
This is achieved by using 8% ethanol in the area. There are six or seven other areas in the state which are
close to being non-attainment for CO. West Yellowstone, MT is very high for CO levels in winter months
mostly because of the use of snowmobiles. Since there is currently no reported producer of ethanol in
Montana the supply is serviced from the adjacent states of North Dakota, South Dakota (Heartland Grain
Fuels) and Wyoming (Wyoming Ethanol). Some of the ethanol requirements have been sourced in the past
from Iowa and Indiana. The state in addition to collecting a 27 cents/gallon tax on any type of fuel has a
0.75 cents/gal clean-up fee.
The state of Washington has seen the use of ethanol fuels drop recently. Ethanol fuels were being used in
greater amounts in the Seattle area as an oxygenate. However, the Seattle area is no longer a non-attainment
area for carbon monoxide (CO), such that oxygenated fuels are not required. The replacement of older cars
with newer less polluting vehicles is a contributing factor in the reduction of CO emissions. Spokane still
requires the use of oxygenate in the winter months. The improvement in air quality has not happened to the
same degree in Spokane, potentially because of the colder climate and colder engine starts. Washington’s
incentive to use ethanol fuels was removed when the State’s revenue loss became significant. There are
currently no requirements for reformulated gas in the State. Arco is reported to be the major user of ethanol
for fuels and is more than likely purchasing product from the mid-western United States, and to lesser
degree from offshore suppliers.
There is conflicting information and data on the consumption of ethanol in Idaho. While no consumption of
gasohol is reported in Idaho by the U.S. Department of Energy, officials with the states energy program
report the estimated use is actually about 8 M gallons per year. There are 42 gasoline stations in the state
offering E10 fuels. Another major supplier to the state is Wyoming Ethanol. There is one non-attainment
area in Idaho, year round, for carbon monoxide (CO) and PM 10 (particulate) in North Ada County. The
state has three other non-attainment areas for PM10.
Nevada has non-attainment areas for CO in the counties of Clark and Washoe from October 1 to February
29. Both locations have a winter oxygenates program. Clark County has a number of stations that use and
sell ethanol fuels year-round. Clark County, which is located in southern Nevada, began its winter ethanol
program in 1989. The county adds 3.5% ethanol by weight to gasoline. Nevada is reported to be the only
state in the US that mandates only the use of ethanol in winter fuels. Consumption of ethanol used in
gasohol in Nevada in 1998 was 52.3 million litres according to the U.S. Energy Information
Administration.
Ethanol demand in the western states of California, Arizona, Nevada, Oregon and Washington increased
from 154 million to 214 million gallons per year from 1992 to 1995. In 1996, ethanol demand dropped to
124 million gallons per year with the loss of the California market and a significant decrease in the
Washington market.
The are no public figures for fuel use in B.C. and Alberta. As a public company Mohawk released sales
volumes for ethanol blended gasolines. Not all of the gas was blended at 10%. The most ethanol used
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according to an analyst was about 23 million litres in 1995. In 1996, Mohawk increased the price of ethanol
blends in Alberta and Saskatchewan and that caused consumers to shift away from ethanol blends, which
had been sold at the same price as gasoline blends. Alberta and B.C. are currently estimated to use about 5
million litres/yr and Saskatchewan 2.5 million litres/yr of ethanol for ethanol/gasolines blends.
3.4.6 Market Pricing
Prices of ethanol are influenced by the cost of raw material grains (corn) as well as ethanol plant coproducts, such as DDG and gluten. Other influences are the price of gasoline which is turn is strongly
influenced by the price of crude oil. Recent (February, March 2000) escalations of crude oil and gasoline
prices saw increases in the price of ethanol, although to lesser degrees.
In the United States list prices has tended to fluctuate, while in Canada the listed price has remained
relatively stable. Canadian suppliers increase or decrease discounts from high list prices, depending on
prevailing market conditions. Generally, the price for ethanol is similar across North America.
Most of the ethanol sold in Canada is under contract, with pricing mechanisms and actual transaction prices
that are unique to the producer-buyer relationship. Therefore, market list or spot prices for ethanol do not
necessarily reflect the actual transaction prices in Canada. Recent fluctuations in crude oil and gasoline
prices across North America have also influenced ethanol prices. Crude oil reached close to 32 US$/barrel
in the first quarter of 2000 and has recently dropped to 26 US$/barrel. Ethanol prices have corresponding
increased and decreased.
Table 45: Canadian Pricing Data for Ethanol
High price in last 5 years
Low price in last 5 years
Current market price in U.S.
Sources: Industry sources.
Cdn¢/litre
68
34
38-55
3.5 Wheat Gluten Market Overview
Wheat gluten represents a potential value-added product of an integrated ethanol plant. The North
American wheat protein market can be considered to include vital wheat gluten as well as intrinsic wheat
protein. Total North American wheat protein demand is roughly estimated at 35-40 million tonnes per year.
In the 1996/1997 crop year, approximately 35 million tonnes of wheat were consumed in the United States
for food, feed and seed, alone. The U.S. produces approximately 64 million tonnes per year of wheat, a
large portion of which is exported. By comparison in the same period, 120,000 tonnes of wheat gluten were
consumed in the United States, or only 0.3% of the total weight of domestic wheat processed. However,
since wheat gluten consists of approximately 75-80 percent protein, its contribution to total wheat protein
market, is higher and to a minor degree can influence the overall market. 41
3.5.1 Market Size
The total North American (including Canada) market for wheat gluten is estimated at 130,000 to 140,000
tonnes per year. A new 100 million litre-ethanol per year gluten/ethanol facility could produce
41
Stiegert, K., Balzer, B., Evaluating the U.S. Wheat Gluten Quota Policy, The Wheat Utilization
Committee of the U.S. Wheat Associates, August 1999.
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approximately 25,000 to 30,000 tonnes of gluten annually. This is a relatively large portion - approximately
20% - of the North American market, which presents substantial potential marketing problems and trade
issues for a new supplier. Lately, U.S. producers of gluten have been more protective of their domestic
market (see below).
In 1997, North American imports, mostly into the United States, made up approximately 30% of domestic
consumption. In 1998, these imports increased substantially and for European Union countries and
Australia exporters, exceeded import quotas established during 1998 by the U.S. Administration.
Table 46: United States Imports of Wheat Gluten42
(HS Code: 110900: Value in Millions of Canadian Dollars)
Country of Origin
1994
1995
1996
1997
Europe, Western
Canada
Australia
Others
(M$)
48
17
47
10
(M$)
43
13
36
4
(M$)
55
15
49
5
(M$)
45
12
31
4
Total
122
96
124
92
1997
(estimated)
(kilotonnes)
1998
(M$)
18
6
12
2
76
16
47
7
38
146
In most applications, gluten competes with wheat protein, which varies in supply based principally on the
types of wheat varieties planted and weather factors late in the growing season. The value of protein
depends on its supply and availability. There are crop years in which protein is in oversupply, which tends
to drive its value to very low levels. In other years, when availability of wheat protein is low, the price can
be influenced by the cost of incremental production of protein contained in value-added products (e.g.,
gluten).43 The full dynamics affecting the price of wheat gluten are complex, and beyond the scope of this
study to detail. However, potential ethanol producers, need to understand these complex markets in context
of investment decisions.
3.5.2 Suppliers of Wheat Gluten
There are less than half a dozen identified wheat gluten producers in North America. The major Canadian
producer of wheat gluten is ADM (Archer Daniels Midland) in Lachine, Quebec. The facility has an
estimated capacity of approximately 20 kilotonnes per year of gluten, which represents nearly 2 times the
size of total Canadian demand. ADM exports gluten to the United States 44. It does not make ethanol at the
Quebec plant. Starch is a co-product. API Grain Processing in Red Deer, AB also makes wheat gluten. Its
capacity is assumed to be smaller than ADM’s, with a substantial portion of its production potentially used
for its enriched flour products. API does make ethanol.
42
Trade Data Online v3.0, strategis.ic.gc.ca
Stiegert, K., Balzer, B., Evaluating the U.S. Wheat Gluten Quota Policy, The Wheat Utilization
Committee of the U.S. Wheat Associates, August 1999.
44
May sell gluten internally to ADM food operations.
43
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Table 47: Identified US Gluten/Ethanol Producers
Company
Manildra
Midwest Grain Products, Inc.
Location
Hamburg, Iowa
Atchison, Kansas
3.5.3 Dumping and Recent U.S. Import Quota
On January 22, 1997, the Wheat Gluten Industry Council of the United States filed a Section 301 petition to
stop the current European Union trade practices concerning wheat gluten and starch. European producers
were increasing their share of the U.S. market. Between 1995 and 1998, European wheat gluten EU
producers nearly doubled their share of the U.S. market from 14 percent to 28 percent. The Wheat Gluten
Industry Council estimated that the U.S. wheat gluten industry was operating at only one-third of its
production capacity as the result of what it claims was European gluten dumping. Pressure on U.S. wheat
gluten markets caused U.S. prices to fall, at times, below production costs. U.S. gluten production has been
forced to scale back, causing job loss and reduced demand for U.S. wheat, according to U.S. producers.
As a result in 1998, The U.S. International Trade Commission (ITC) imposed a 3-year quota (June 1, 1998
until June 1, 2001) on wheat gluten imports from the European Union, Australia, Argentina, Taiwan,
China, and some East European nations. It limited total imports to 57.5 kilotonnes in year 1 and increases
by 6% annually. Canada, Israel, Mexico and countries included in the Caribbean Basin were exempt45.
In 1999 it became evident to United States officials that some exporting countries were exceeding their
quotas. Further action was taken. The Clinton Administration took steps to reduce the quantity of European
vital wheat gluten that could be imported into the United States over the next 12 months. In a presidential
proclamation issued May 28, EU import allocation was reduced by 5,402,000 kilograms, or 21% of
25,700,000 kilograms. The action was taken after the U.S. Customs Service determined that gluten imports
from the European Union during the previous 12 months had exceeded the EU quota by 5,200,000
kilograms. For the 12 months ended May 31, 2000, the EU quota will be 20,581,000 kilograms.
European Union officials claimed the move was "highly discriminatory" and "without warning." Further,
the EU said that the quota cut for the next 12 months of 5.4 million kg exceeds the 5.2 million kg the EU is
said to have shipped into the United States in excess of the quota. That gluten exports from the EU
exceeded the quota at all is the fault of U.S. Customs, according to the Europeans. Specifically, the EU has
accused Customs of failing "to record declared imports against the EU quota. Only U.S. Customs had the
complete picture of how much wheat gluten had been imported, yet they were posting misleading data on
their traders’ Internet site about the room for further imports under quota," the Europeans claim. "When
they realized their error, the extra amounts were added to the quota, showing the overshoot for the EU Now
the EU trade is being penalized for what is in effect an omission of the U.S. authorities."
45
Washington File, Statement On Wheat Gluten Import Quotas, U.S. Information Service, June 1998. The
President found pursuant to the NAFTA Implementation Act that imports of wheat gluten from Canada do
not contribute importantly to the injury caused by imports and that imports from Mexico do not account for
a substantial share of imports of wheat gluten. As such, imports of wheat gluten from Canada and Mexico
were excluded from the quota.
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4. Comparison of Fuel Alternatives
4.1 Summary
This section describes vehicle emission standards, technologies to reduce emissions and compares
alternative fuels as gasoline blending components or fuels used in pure form (e.g., propane, natural gas,
biodiesel). The table below summarizes key properties of gasoline blending components, namely ethanol,
MTBE, ETBE, and alkylates, aromatics and olefins. The characteristics are presented in context of ethanol
as a low level blending component, not as a high ethanol-concentration fuel or as a diesel fuel component.
Propane, natural gas and biodiesel are also considered in this section although summary data are not
provided in table below.
Impact on
CO
Emissions
Impact on
HC
Emissions
Impact on
NOx
Emissions
18.0
9.0
4.0
7.9
~3
~7
Oxygen
Content,
wt%
115
110
112
92.6
~110
~90
Carbon
Content,
Wt %
Ethanol
MTBE
ETBE
Alkylate
Aromatics
Olefins
Blending
Vapour
Pressure, psi
Blending
Octane
R+M/2
Table 48: Summary of Key Properties of Gasoline Blending
Components
52.2
70.5
68.1
84
90.0
85.7
34.4
18.2
15.7
0
0
0
0
0
0
0
+
-
+
0 to +
0 to +
0
+
+
- DENOTES A DECREASE, + IS AN INCREASE
* Assumes vapour pressure adjustments to gasoline. HC emissions may increase if VP is not adjusted.
4.2 Vehicle Technologies and Emission Standards
Vehicle and engine technologies are continually changing in response to these government regulations,
consumer demand, technological capabilities and other factors. These changes have resulted in exhaust
emissions from new vehicles being over 90% less than emissions from vehicles of the 1960’s. One of the
results of this continual improvement has been that vehicles with different technologies and different
control strategies respond differently to changes in fuel composition. It is therefore necessary to look at fuel
impacts separately for the varying classes of technology.
Most cars today are equipped with catalytic converters. Catalytic converters are pollution control devices
installed directly in the exhaust system of vehicles to reduce harmful emissions. First used in 1975,
oxidation (or two-way) catalytic converters take hydrocarbons (HC) and carbon monoxide (CO) and
convert them into carbon dioxide (CO2) and water vapour, which are then released into the air. Three-way
catalytic converters appeared in the mid-1980s, and convert carbon monoxide and hydrocarbon (HC)
emissions as well as nitrogen oxide (NOx) into nitrogen, carbon dioxide and water vapour.
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The following table provides an illustration of the evolution of Canadian exhaust emission standards for
gasoline-fuelled vehicles. On August 20, 1997, Transport Canada published comprehensive new emission
regulations in the Canada Gazette Part II. The new regulations require the more stringent control of
exhaust emissions (HC, CO, NOx and PM), evaporative emissions (mostly HC) and refuelling emissions
(mostly HC) from 1998 and later model year vehicles. In addition, the new regulations require that new
light-duty vehicles and light-duty trucks be equipped with on-board diagnostic systems to monitor vehicle
emission control systems for proper functioning and to alert the driver of any malfunction by illuminating a
dashboard light.
Table 49. Light-Duty Gasoline Vehicle Standards in Canada
Exhaust Emissions (g/km)
HC
Effective
CO
NOx
PM
Date
THC
NMHC
Prior to Standards
5.5
54
2.2
(Estimates)
January 1971
1.4
14
July 1971
2.1
24
January 1973
1.2
24
1.86
January 1975
1.2
16
1.93
September 1987
0.25
2.1
0.62
Tier 0 Vehicles
September 1997
0.25
0.16
2.1
0.25
0.05
Tier 1 Vehicles
LEV Proposal
0.047
2.1
0.125
HC: Hydrocarbons, THC: Total Hydrocarbons, NMHC: Non-Methane Hydrocarbons, CO:
Carbon Monoxide, NOx: Nitrogen Oxides, PM: Particulate Matter.
Note:
In the case of the standards in place from 1971 through 1974, different test procedures
were used to verify compliance. Therefore, their stringency cannot be directly
compared with the other standards. For the 1998 model year, similar standards exist
for diesel, methanol, natural gas, and LPG vehicles.
Source: Environment Canada, Transport Canada
Canada's new vehicle emission standards are now fully harmonized with those applicable in the United
States under the Environmental Protection Agency's federal emission control program and are consistent
with a recommendation of the CCME's Task Force on Cleaner Vehicles and Fuels. This has not always
been the case. There was a delay in standards setting in the 1980’s with the 1987 Canadian standards being
introduced in 1980 and 1981 in the US. Vehicles meeting these standards are now known as Tier 0
vehicles.
Transport Canada has also initiated a public process to develop low-emission vehicle standards for the 2001
model year. These low emission vehicles are available in the US and have NOx emissions about 50% lower
than the Tier 1 standards and NMHC 70% lower than Tier 1. The US has implemented new standards to
take effect in 2004. These Tier 2 standards have an average NOx level of 0.04 g/km and a range of
standards for NMOG, CO, formaldehyde and particulate matter that is a function of the NOx certification
level for that vehicle. In general, NMOG and particulate levels are lower than LEV’s and the aldehyde
standard is new.
California has its own terminology for classifying vehicles that have emissions lower than that required by
law. Some of the alternatively fuelled vehicles have been calibrated to meet these lower standards. The
standards are shown in the following table.
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Table 50. California Low Emission Vehicle Standards
Category
NMOG
Oxides of
nitrogen
g/mile
0.4
0.4
Formaldehyde
g/mile
0.25
0.125
Carbon
Monoxide
g/mile
3.4
3.4
mg/mile
n/a
15
Diesel
Particulate
g/mile
0.08
n/a
Units
Tier 1
TLEV, Transitional Low
Emission vehicle
LEV, Low Emission
Vehicle
ULEV, Ultra Low
Emission Vehicle
SULEV, Super Ultra Low
Emission Vehicle.
Proposed 2001 standard at
120,000 miles.
0.075
3.4
0.05
15
n/a
0.040
1.7
0.05
8
n/a
0.010
1.0
0.02
4
0.01
Vehicle emissions are a very complex issue and are highly dependent on engine operating conditions such
as load, speed, engine temperature and the rate of change of conditions. The results of emission testing are
therefore dependent on the test protocol. As noted in a previous table there have been changes in test
procedures over time. The most common test today is the US FTP (Federal Test Procedure). This is the test
used to confirm that vehicles meet the required emission standards. It is acknowledged that operating
conditions during this test procedure are less severe than typical in-use operation, the speeds are slower
with less rapid accelerations. In the real world the higher speed and faster acceleration periods are known
as “off cycle” periods.
The US EPA has developed a new test procedure (the Supplemental FTP or SFTP) in response to the
requirements of the 1990 Clean Air Act Amendments, which includes higher speeds and higher rates of
acceleration. New vehicles will have to be certified in the US using SFTP starting with the 2001 model
year. Manufacturers are expected to mitigate the impact of the emissions from these off cycle periods and
will be required to meet the same emission standard as they would with the FTP.
Emissions from these off cycle periods can be very high. Ross (1995) reports that emissions during high
power accelerations can be 500 times higher than FTP emissions for CO, 100 times higher for HC and 20
times higher for NOx. Ross estimated that these periods could contribute 7.3 g/mile of CO, 0.12 g/mile HC
and negligible emissions of NOx per average mile driven. The EPA (German 1995) reached the same
conclusions regarding the importance of controlling off cycle emissions during their review of the FTP and
development of the SFTP. The increase in emissions is due to enrichment of the air fuel mixture and a drop
in catalyst efficiency during these periods. Fuel oxygen leans the air fuel mixture and could be expected to
have a larger impact on off cycle emissions than on emissions from the FTP cycle where the air fuel
mixture is generally controlled close to stoichiometric.
Emissions from vehicles generally increase with age or mileage. The rate of increase is dependent on the
vehicle technology. Older vehicles deteriorate at a faster rate than newer technology vehicles. This
deterioration along with off cycle emissions accounts for the much higher in-use emission factors than the
certification emission rates.
4.3 Gasoline and Hydrocarbon Blending Components
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Gasoline and diesel fuels are complex mixtures of hydrocarbons that are produced from refining crude oil.
These two fuels provide the majority of the energy requirements of the transportation sector. Traditionally
the fuels have been blended to meet the performance requirements of the vehicles they are used in and to
balance the production at the refinery. Refiners increasingly have to blend fuels to meet environmental
requirements, allowing vehicles to operate with lower exhaust emissions. Canadian fuel specifications now
limit benzene content of gasoline, the sulphur content of diesel fuel and in the future will also limit gasoline
sulphur content.
Not only are fuels complex mixtures but the refineries that produce them are also complex manufacturing
processes that combine many individual process operations to obtain the required yield of fuels demanded
by the market in the most efficient and cost effective manner. The schematic layout of a typical refinery is
shown in Figure 2 (Chevron, 1996).
Crude oil is fed to the distillation column where straight run light and heavy gasoline, jet and diesel are
separated at atmospheric pressure. Whereas straight-run jet and diesel are usually acceptable as is, the
straight-run gasolines typically require more processing to convert them into gasoline blending
components. The straight run light gasoline may be isomerized to increase octane, hydrotreated to convert
benzene to cyclohexane so that the final gasoline blend will meet a benzene specification limit, or both. The
straight run heavy gasoline is hydrotreated to remove sulphur and then reformed to improve octane and
generate hydrogen for the hydrotreaters.
The bottoms from the atmospheric column is vacuum distilled to obtain gas oils for FCC or hydrocracker
feed. The gasoils are hydrotreated to reduce sulphur and nitrogen to levels which will not interfere with the
FCC process. Even though the feed was desulphurized, the FCC product must be sweetened to convert
reactive sulphur compounds (mercaptans) to more innocuous ones, otherwise the gasoline blend will be
malodorous and unstable. In the future with tighter restrictions on the sulphur content of finished gasoline,
the FCC product must be further desulphurized.
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Figure 2. Gasoline Processing in a Modern Refinery
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The typical characteristics of the major refinery streams are shown in the table below (Miller, 1999).
Table 51: Typical Characteristics of Refinery Streams
Name
Light Straight Run
Isomerate
FCCU
Reformate
Alkylate
Lt. Hydrocrack
n-Butane
Blending
Octane,
R+M/2
73.1
87.0
86.4
87.0
92.6
80.9
92.0
Blending
Vapour
Pressure, psi
13.3
16.9
7.1
3.0
3.0
12.5
51.8
Olefins, %
Aromatics, %
Benzene, %
2.2
0.7
29.1
0.2
0.5
0.2
0
2.8
1.4
29.2
58.9
0.4
3.0
0
0.3
0.1
2.9
1.8
0.04
0.2
0
Many of the gasoline components not yet regulated in Canada are known to impact vehicle emissions. The
Auto/Oil Air Quality Improvement Research Program (AQIRP) was initiated in the late 1980’s to develop a
better understanding of the relationships between fuel composition and fuel parameters and vehicle
emissions. The AQIRP program and efforts of the US EPA and California throughout the 1990’s has lead
to a much better understanding of the impact of fuel parameters and exhaust emissions.
A recent presentation from the California Air Resources Board (1999) summarized the emissions response
to fuel parameters.
Table 52: Emission Response to Fuel Parameter Changes
Decreasing Fuel Parameter
RVP
Sulphur
Benzene
Aromatics
Olefins
T50 and T90
Oxygen
Leads to
Reduced evaporative
Reduced , NOx, Toxics, SOx
Reduced Toxics
Reduced , NOx, Toxics
Reduced NOx, Toxics, Increased
Reduced , Toxics, Increased NOx
Increased , Toxics, CO, Reduced NOx
Gasoline is formulated to meet many quality parameters including octane content, volatility, driveability,
and energy content. In addition, refiners must simultaneously meet the quality specifications of the other
products being produced. The result is that it is extremely difficult to change only one parameter at a time.
For example, aromatics are a good source of octane, such that lowering aromatics to reduce emissions of
VOCs, NOx and toxics must be offset by increasing another component that will increase octane.
Adding an oxygenate to gasoline such as ethanol or MTBE, not only reduces VOCs, CO, and toxics and
increases NOx, it also adds octane so the aromatics can be reduced. A refiner that takes full advantage of
the properties of the oxygenate can therefore reduce VOCs and Toxics further and offset at least some of
the NOx increase usually associated with oxygenates. The oxygenate will also dilute some of the other
gasoline parameters such as benzene and sulphur leading to further small improvements in air quality.
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A brief description of various gasoline blending components with their key energy and environmental
considerations follows.
4.3.1 Aromatics
With aromatic compounds some of the carbon atoms are joined in a ring. These rings always contain six
carbons. Some of the better known aromatics include benzene, toluene and xylene. The benzene content of
gasoline in Canada is now limited to 1.0% by volume. In other jurisdictions such as California and those
areas of the United States that require reformulated gasoline there are also limits on the quantity of
aromatics that gasoline may contain.
Aromatics have high-octane levels and a high specific gravity (~0.87 g/l) which leads to good volumetric
fuel economy. Aromatics have a carbon content of about 0.90 by weight. This leads to slightly higher
greenhouse gas emissions per mile driven. The blending octane is a function of the severity of the
reforming process but it is generally in the range of 88 to 92 (R+M/2). The aromatic content of gasoline
generally rose when lead was removed from gasoline. Refinery processes such as reforming produce
streams with high aromatic contents.
Increasing the aromatic content of gasoline leads to higher emissions of hydrocarbons, NOx, and air toxics.
Higher aromatics also lead to a higher driveability index resulting in poorer performance. Aromatics are
also linked to higher levels of combustion chamber deposits. Both higher driveability index and higher
combustion chamber deposits are linked to higher exhaust emissions (Piel, 1999).
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4.3.2 Reformate
Reformate is the product stream produced by catalytically reforming low octane straight chain paraffins
into aromatics. Hydrogen is also produced in the process. The hydrogen can be almost as important as the
octane boost. Hydrogen is used in the refinery to remove sulphur and in processes such as hydrocracking.
Reformate is high in aromatics, carbon and specific gravity. It is low in sulphur.
4.3.3 Benzene
Benzene is a specific aromatic compound. It is a known carcinogen and for this reason the quantity
permitted in gasoline is now limited to 1% in Canada. Canada introduced this limit on benzene in gasoline
effective July 1999. Benzene can also be produced during the combustion process in an engine from
incomplete combustion of larger aromatic compounds. This is a factor in leading some areas to limit total
aromatic content of gasoline. Working under the Canadian Council of Ministers of the Environment
(CCME), Canada-Wide-Standards for benzene are in the development process and cover all benzene
sources of emissions. The results of the CWS may have additional regulatory impact on benzene in
gasoline.
4.3.4 Olefins
Olefins are unsaturated hydrocarbons with one or more double bonds. They rarely exist in crude oil but are
formed during the refining process. They have a lower stability than paraffinic compounds. Increasing
olefin content of gasoline increases emissions of NOx and air toxics. Refinery streams with a high olefin
content include cat cracker gasoline. Cat cracker gasoline typically has an octane rating of 86 (R+M/2). The
cat cracker converts the heavier hydrocarbons in crude oil to lighter, higher-octane gasoline components.
Olefins have a specific gravity of about 0.77 g/l and a carbon content of 0.86. Both of these properties are
close to the average for gasoline. The gaseous, light C3 and C4 olefins can be used as feedstock for the
alkylation process.
Olefin content of gasoline is regulated in US and California Reformulated Gasoline.
4.3.5 Alkylate
The alkylation process combines small gaseous olefins with boiling points too low to be used in gasoline
with iso-butane to produce liquid paraffinic hydrocarbons. Alkylate has a high octane, usually in the low
90’s (R+M/2). Alkylation is a key process in producing reformulated gasoline due to limits placed on the
other classes of high-octane hydrocarbons, olefins and aromatics. Alkylate has very low contents of olefins,
aromatics and sulphur.
Alkylate has a low specific gravity (~0.68) leading to a lower volumetric fuel efficiency. The carbon
content is typically 0.84 by weight. Gasoline with high alkylate content can produce lower greenhouse gas
emissions from the combustion of the fuel per mile driven.
Alkylate production in the refinery is limited by the capacity of the cat cracker and the olefin production. It
has been proposed that MTBE plants could be converted to alkylation units if the market for MTBE shrinks
but this would produce very expensive alkylate (Miller, 1999).
4.3.6 Butane
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Butane is a light paraffin used to adjust the front end volatility of gasoline. It is a high-octane component.
Tighter vapour pressure limits on gasoline limits the amount of this high-octane component that can be
added to gasoline in the summer. This puts additional pressure on gasoline octane. Butane has a carbon
content of 0.86, a specific gravity of 0.58 and an octane of 92.
4.3.7 Sulphur
The Federal government has introduced limits on gasoline sulphur content that will take effect in 2002 and
2005. The average sulphur content of Canadian gasoline is about 360 ppm. This will be reduced to an
average of 150 ppm for the period of July 1, 2002 to January 1, 2005. After January 1, 2005, sulphur levels
are to be less than 30 ppm. Therefore, by 2005 sulphur related emissions (SOx) from gasoline vehicles are
projected to be less than 10% of the 360 ppm level.
Sulphur in gasoline impairs the operation of catalytic converters. Low sulphur gasoline can reduce
emissions substantially. The reduction is dependant on the vehicle technology used but emissions of carbon
monoxide, hydrocarbons and nitrogen oxides are all reduced when the sulphur content of gasoline is
reduced. The reductions reported by the US EPA (EPA 1999). The reductions for lowering sulphur from
400 to 50 ppm would be additive.
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Table 53: US EPA Sulphur Reductions
Emission
Mode
Vehicle
Technology
Percent Reduction in
HC when Sulphur is
changed from:
400>200
FTP
Running
Tier 0
Tier 1
Complex
Model
Tier 0
Tier 1
Percent Reduction in
NOx when Sulphur is
changed from:
200>50
400>200
200>50
Percent Reduction in
CO when Sulphur is
changed from:
400>200
200>50
6.0
3.4
9.9
12.8
7.1
7.5
2.08
2.4
5.7
4.2
4.8
7.4
6.92
5.23
9.6
14.8
11.1
7.26
11.7
13.4
26.3
32.5
3.38
2.3
7.0
4.71
10.5
9.72
23.3
21.4
4.4 Oxygenates
Oxygenates are combustible liquids that contain oxygen in addition to carbon and hydrogen. All of the
oxygenates currently used in gasoline belong to either the alcohol or ether families. With alcohols the
oxygen is bonded to a hydrogen atom and a hydrocarbon group. With ethers two hydrocarbon groups are
bonded to the oxygen atom. While the physical properties of the two families are different their impacts on
exhaust emissions are quite similar for a given oxygen content.
The most common oxygenates used in North America are ethanol, methyl tertiary-butyl ether (MTBE),
Ethyl tertiary-butyl ether (ETBE), and tertiary-amyl methyl ether (TAME). The basic properties of these
four oxygenates are shown in the table below.
Table 54: Information on Gasoline Oxygenates
Name
Ethanol
MTBE
ETBE
TAME
Formula
C2H6O
C5H12O
C6H14O
C6H14O
Oxygen
Content, mass
%
Blending
Octane
Number,
R+M/2
34.7
18.2
15.7
15.7
129
118
119
112
Blending
Vapour
Pressure,
psi
18.0
9.0
4.0
2.5
Maximum Concentration
Approved by EPA
Mass %
Oxygen
3.7
2.74
2.7
2.7
Volume %
Oxygenate
10.0
15.0
17.1
16.6
4.4.1 Ethers
4.4.1.1 Methyl tertiary-butyl ether (MTBE)
MTBE is manufactured from methanol and isobutylene. The methanol is almost always manufactured from
natural gas and the isobutylene is either a by-product of the refining process or manufactured from field
butanes. MTBE facilities within a refinery tend to be small units limited by the availability of isobutylene.
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Stand-alone facilities that obtain the isobutylene from butane are usually larger units producing 10,000
bbls/day (584 million litres/year) or more of MTBE.
US MTBE demand was reported to be 250,000 bbls/day in 1997 (~14 billion litre/year) by the US Energy
Information Administration. One fifth of that was met through imports with the remainder being
domestically produced. Although eastern Canadian refiners/fuel suppliers (especially North Atlantic
Refining in Newfoundland and Irving in New Brunswick) import a substantial amount of MTBE,
practically all of it is blended for gasoline export sales to the United States. The eastern Canadian refiners
selling into U.S. smog non-attainment areas require the oxygenate to meet specifications.
MTBE began to be used as a gasoline blending component in the early 1980’s. Initially it was used because
of its high octane value and it was used to replace lead as an octane booster. In the 1990’s with the
introduction of winter Oxyfuel programs and Reformulated Gasoline in the US it was also used as a source
of oxygen for gasoline.
Fuel economy of gasoline is reduced when any oxygen containing compound is added to the fuel. An 11%
MTBE blend contains 2.0% oxygen and can be expected to reduce the fuel economy by 1.5 to 2%
compared to gasoline without oxygen.
The addition of oxygen to gasoline will reduce exhaust emissions of carbon monoxide and hydrocarbons.
The actual amount of the reduction is dependent on the vehicle technology. Older vehicles tend to exhibit a
larger reduction in exhaust emissions than newer technology vehicles. With 11% MTBE new vehicles with
Tier 1 technology can be expected to have an 8% reduction in unburned hydrocarbons ((S&T) 2, 1999).
Most studies have concluded that these Tier 1 vehicles do not exhibit a CO reduction at the 2% oxygen
level. There should be no impact on NOx at this level. Incomplete combustion of MTBE will lead to
exhaust emissions of MTBE and formaldehyde. Emissions of MTBE and formaldehyde are very low with
these vehicles, less than 10 mg/mile. Percent increases can be very large because of the small baseline
quantities. The US EPA Complex Model46 predicts formaldehyde increases of 9.7% (1 mg/mile) from the
addition of 11% MTBE to gasoline. Total air toxics decrease from 86 to 80 mg/mile with this addition. The
Complex model results for baseline gasoline and gasoline with the addition of 11% MTBE are shown in the
table below.
Table 55: US Complex Model Results for Baseline Gasoline With
and Without 11% MTBE
Units
Exhaust benzene
Nonexhaust benzene
Acetaldehyde
Formaldehyde
Butadiene
Particulate organic matter (POM)
Total exhaust toxics
Total toxics
Baseline Gasoline
mg/mile
53.54
5.51
4.44
9.70
9.38
3.04
80.10
85.61
Gasoline with MTBE
mg/mile
48.34
5.01
4.14
10.64
8.78
3.02
74.92
79.93
Change, %
-9.72
-9.03
-6.73
9.68
-6.36
-0.72
-6.47
-6.63
The US EPA’s Complex Model is a spreadsheet model used to estimate potential emissions for
hazardous or toxic organic substances.
46
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MTBE use in gasoline has become a significant concern in the US over the past several years. Many
chemicals in gasoline, including MTBE, can be harmful in water. However, MTBE is highly soluble in
water and if gasoline containing MTBE is spilled or leaks into the soil it travels faster and further in water
than the other gasoline components. MTBE is therefore more likely to be found in ground water or drinking
water than other gasoline components. Combined with its distinctive odour, MTBE use in gasoline has
become an issue of significant public concern. The State of California moved to eliminate the use of MTBE
in gasoline and an EPA recently announced its intention to phase-out MTBE from use in gasoline.
Greenhouse gas emissions resulting from the production and use of MTBE depend on how the fuel is made.
Large stand alone plants using purchased methanol and field butanes will have greenhouse gas emissions
similar to that of gasoline production on a per unit of energy basis.
4.4.1.2 Ethyl tertiary-butyl ether (ETBE)
ETBE is a very similar compound to MTBE. It can be manufactured in the same plants by substituting
ethanol for methanol in the feed to the plant. It has a slightly lower oxygen content than MTBE which
requires more of it to be used to meet the same oxygen level in the final gasoline. It has a lower vapour
pressure than MTBE, which could be attractive for some refiners, especially in the summer months.
Ethanol costs more than methanol so ETBE is more expensive to make than MTBE. In the US if the
ethanol that is used for ETBE production qualifies for the ethanol tax exemption then that reduces the cost
disadvantage for ETBE production. In recent years the cost spread between methanol and ethanol has been
high enough that not even the tax incentive was sufficient to overcome ethanol’s price disadvantage and
very little ETBE has been produced.
ETBE will behave in a very similar fashion to MTBE if it enters ground water. It is not considered as a
replacement for MTBE. Incomplete combustion of ETBE will produce acetaldehyde in the exhaust rather
than formaldehyde. Acetaldehyde is less reactive in the atmosphere than formaldehyde. The Complex
Model predicts a 4 mg/mile increase in acetaldehyde emissions when 2% oxygen is added with ETBE. This
is an 88% increase in acetaldehyde emissions. Even with this increase acetaldehyde emissions are less than
formaldehyde emissions from non-oxygenated gasoline. Total toxics emissions decline by 2 mg/mile or
2.4%. The Complex Model results for gasoline with 12.5% ETBE (2% Oxygen) are shown in the table
below.
Table 56: US Complex Model Results for Baseline Gasoline With
and Without 12.5% ETBE
Units
Exhaust benzene
Nonexhaust benzene
Acetaldehyde
Formaldehyde
Butadiene
POM
Total exhaust toxics
Total toxics
Baseline
Gasoline
Gasoline with 12.5% ETBE
Change, %
mg/mile
53.54
5.51
4.44
9.70
9.38
3.04
80.10
85.61
mg/mile
48.34
5.50
8.36
9.70
8.78
3.02
78.20
83.71
-9.72
-0.00
88.33
0.00
-6.36
-0.72
-2.37
-2.22
4.4.2 Alcohols
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The two alcohols that are of interest from a fuels perspective are methanol and ethanol. In the past
isopropanol, tertiary butyl alcohol, and isobutyl alcohol have been used as gasoline blending agents. These
other alcohols are usually made from petroleum and are more expensive to make than gasoline so their use
in gasoline has essentially disappeared. The octane properties of alcohols heavier than butyl alcohols are
lower than gasoline so their has never been significant interest in those compounds as a gasoline fuel
component.
4.4.2.1 Methanol
Methanol is made from natural gas. In the past it has been used as a low level blending agent with gasoline
(M5) and as a high level blend (M85). There is little interest in these two markets today from the methanol
or automotive industries. The last M85 vehicles were produced about a year ago by Ford. The methanol
industry is very interested in the potential application of methanol as the fuel for fuel cell vehicles. The
industry is also investigating the use of diesel methanol emulsions for use in unmodified diesel engines.
Methanol is the simplest alcohol. It has the highest oxygen content (50%) of any of the ethers and alcohols.
Of all of the alcohols it is the one most unlike a hydrocarbon. It has the lowest solubility in hydrocarbons
and thus has needed to be used with a co-solvent to improve water tolerance. It is the most aggressive
towards elastomers and some of the metals typically found in automotive fuel systems.
Methanol and ethanol exhibit unusual volatility properties. As pure liquids there have very low vapour
pressure but in low level blends they form azeotropes with some low weight hydrocarbons and as a result
exhibit very high blending vapour pressures. As high level blends the 15% gasoline serves a number of
purposes including increasing volatility to aid with cold starts. Blends of 5% methanol can increase the
vapour pressure of gasoline by as much as 3 psi.
Methanol does have a high octane rating particularly in low level blends (R+M/2 of 120). Its high heat of
vapourization has made methanol and attractive fuel in high performance applications such as Indy car
racing. In blends with diesel fuel methanol has demonstrated an ability to lower particulate and NOx
emissions. These diesel emissions are the target of current efforts by Governments and manufacturers to
improve the environmental performance of diesel engines.
Methanol’s other attractive attribute is that it is one of the few liquid fuels that does not have a carboncarbon bond. This means that the temperature at which methanol breaks down to form hydrogen is much
lower than any of the non-hydrogen fuels that are being considered for fuel cell applications. Lower
temperature reforming should improve the transient response for on-board reforming. Methanol’s high
hydrogen content is also attractive as a fuel cell fuel.
4.4.2.2 Ethanol
Ethanol is used widely throughout North America as a blending component of gasoline. In the United
States approximately 4.8 billion litres were used in 1998. There is a small but growing market for high
level blends (E85) for flexible fuels vehicles developing in the United States.
Most of the ethanol produced in North America is made from fermentation of biological materials. In some
parts of the world some ethanol is made from the petrochemical feedstock, ethylene.
Ethanol has a high blending octane value, a high blending vapour pressure and a high oxygen content. It is
soluble in gasoline when water is not also present. Water contents above 0.4% will cause a 10% ethanol
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blend so separate into a gasoline rich phase and an ethanol rich phase. This phase separation must be
avoided for the fuel to work properly in vehicles.
When ethanol is added to gasoline at the 10% level it will increase the octane of the fuel by up to 3 octane
numbers. It will increase the vapour pressure by approximately 1 psi and will reduce the emissions of
carbon monoxide and unburned hydrocarbons. The magnitude of the emission reductions is dependent of
the vehicle technology. The vehicle fleet average reduction in Alberta will be about 15% for carbon
monoxide, 14% for hydrocarbons. Emissions of NOx may increase by 5% and evaporative emissions will
increase if the ambient temperature is above 10C and the vapour pressure of the gasoline is not adjusted by
removing other highly volatile components such as butane. Ethanol will increase the emissions of
acetaldehyde in the exhaust. The Complex Model results for a 5.7% ethanol blend (same oxygen content as
presented for MTBE and ETBE) are shown in the table below.
Table 57: US Complex Model Results for Baseline Gasoline With
and Without 5.7% Ethanol
Baseline Gasoline
Units
Exhaust benzene
Nonexhaust benzene
Acetaldehyde
Formaldehyde
Butadiene
POM
Total exhaust toxics
Total toxics
mg/mile
53.54
5.51
4.44
9.70
9.38
3.04
80.10
85.61
Gasoline with 5.7%
Ethanol
mg/mile
48.34
5.50
7.31
9.70
8.78
3.02
77.20
82.65
Change, %
-9.72
-0.00
64.64
0.00
-6.36
-0.72
-2.37
-3.45
More details on the environmental effects of ethanol are provided in Section 6 of this report.
Ethanol can be used in high level blends containing 85% ethanol and 15% gasoline. Flexible fuelled
vehicles are being manufactured and sold by Ford, DaimlerChrysler, and Mazda. The Ford vehicles are
certified to the Transitional Low Emission Vehicle level. High level blends require the 15% gasoline to
provide volatility for vehicle staring.
There are demonstrations taking place in the US with ethanol diesel emulsions in heavy-duty applications.
Emissions of particulates and NOx are reduced with this fuel.
4.5 Propane
Propane has been widely used as a transportation fuel in Canada for thirty years. In its natural state it is a
gaseous fuel, however under moderate pressures it becomes a liquid making storage simpler. In Alberta
about 300 million litres of the fuel is sold annually for transportation applications. In Canada approximately
1 billion litres per year is sold for road transportation. Sales have been dropping throughout Canada due to
the imposition of Provincial taxes on the fuel, the lack of a major effort on the part of the industry to
promote conversions, a very small offering of OEM vehicles, and the need for more sophisticated
conversions to keep pace with improving gasoline technology.
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One of the original attractions of propane as a vehicle fuel was the fact that the fuel was gaseous. This can
lead to good mixing of the air and the fuel and result in lower exhaust emissions. This relative advantage of
propane has been reduced over the past twenty years with the continuing development of gasoline
technology. Improvements in propane fuel technology, particularly in the after-market have not kept pace
with those of gasoline.
Only Ford offers a factory built light duty propane fuelled vehicle. The F-Series pick-up truck is certified as
a Low Emission Vehicle.
Propane is produced as a by-product of natural gas processing plants and in refineries. In Canada 86% of
the propane comes from gas plants with the remainder being produced in refineries. In Alberta an even
higher percentage comes from gas plants.
Propane has a lower carbon content (0.817) than gasoline so the combustion of the fuel produces less
carbon dioxide than gasoline per mile driven.
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4.6 Natural Gas
Natural gas has been used as a vehicle fuel in Canada for almost twenty years. In its natural state it is a
colourless, odourless gas which is widely used as a heating fuel in residential, commercial and industrial
applications. It is also used as a feedstock for chemical processes and can be used as a feedstock for other
fuel options such as methanol, dimethyl ether or various gas to liquid fuel processes.
Natural gas can be used as vehicle fuel without any further refining or chemical
processing beyond that required for heating applications. It is composed primarily of
methane with very small amounts of higher hydrocarbons that have not been completely
removed at the gas processing plants. It is essentially sulphur free with only a few parts
per million of mercaptans added to provide an odour for safety purposes. As a vehicle
fuel it is most often compressed to between 3000 and 5000 psi (CNG) to provide a higher
energy density; but sometimes liquefied (LNG is a cryogenic liquid at –159 C) to provide
even higher energy densities. CNG has been used as a vehicle fuel in the United States,
New Zealand, Italy, Argentina and the Netherlands for as long as or longer than it has in
Canada. The market is starting to develop in a number of countries in Asia, Europe and
South America.
There are a number of OEM natural gas vehicles available. Ford offer six vehicles,
DaimlerChrysler two, and General Motors one. Honda, Volvo, Toyota, and Mazda also
have natural gas vehicles in development or production in the US or internationally. Most
of the vehicles have been certified to a more stringent emissions level than their gasoline
counterparts, many of them to Ultra Low Emission Vehicles.
Natural gas has an octane rating of 130, making it suitable for use in very high
compression engines. High compression engines have a higher efficiency and the
potential for lower greenhouse gas emissions. Few of the existing OEM vehicles take full
advantage of the octane rating due to economic limitations imposed by the small number
of vehicles being sold. The carbon content of natural gas (0.75) is lower than gasoline,
resulting in the fuel having inherently lower greenhouse gas emissions.
The LNG market is not as well developed as the CNG market anywhere in the world. The
major advantage of LNG is the higher energy density of the fuel, which allows a larger
vehicle range. LNG can be transported as a liquid and can be used at locations that are
not connected to a gas pipeline. The applications of the fuel have tended to be heavy-duty
trucks rather than light duty vehicles. There are several LNG refuelling sites in the United
States including public sites that allow for self-serving the fuel. Interest in LNG as a
vehicle fuel for heavy-duty applications is starting to increase in Canada.
Natural gas has a low cetane number. When the fuel is used in diesel type engines it
requires an ignition source or the pilot injection of diesel fuel to ignite the natural gas. A
Canadian company, Westport Innovations Inc, is developing the pilot injection systems.
They are working on developments with Ford and Cummins.
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4.7 Biodiesel
Biodiesel is the methyl or ethyl ester of vegetable or animal fats. It can be used in its pure form or as a
blend with petroleum based diesel fuels, the most common blend being 20% biodiesel. It can be made from
a variety of products, including animal fats and virgin and recycled vegetable oils derived from crops such
as soybeans, canola, corn and sunflowers. Oil of low quality oil seeds, used restaurant oil, and tall oils
produced from pulp waste are also potential feedstocks.
The technology for using biodiesel has been available for over a century, but it is only recently been used
for commercial production. Biodiesel is receiving attention as an alternative fuel and fuel additive because
of growing interest in environmental issues and through the development of more cost-effective processing
techniques. It is produced and distributed in Europe to large extent and has also been produced and used in
the United States.
The production of biodiesel is well known. Methanol and ethanol can both be used as the alcohol. There are
three basic routes to ester production from oils and facts:
 based catalyst transesterification of the oil with alcohol,
 direct acid catalyzed esterification of the oil with alcohol,
 conversion of the oil to fatty acids, and then to esters with acid catalysis.
The majority of the esters produced today are done with the base catalyzed reaction using methanol
because it is the most economic for several reasons:
 it is low temperature (65C) and pressure (1.35 atm),
 it yields high conversion (98%) with minimal side reactions and reaction time,
 it is a direct conversion to methyl ester with no intermediate steps,
 methanol is the lowest cost alcohol,
 exotic materials of construction are not necessary.
The general process is depicted in Figure 3-2. A fat or oil and is reacted with an alcohol, like methanol, in
the presence of a catalyst to produce glycerine and methyl ester or biodiesel. The methanol is charged in
excess to assist in quick conversion and recovered for reuse. The catalyst is usually sodium or potassium
hydroxide, which is already been mixed with the methanol.
Figure 3: Biodiesel Production Process.
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The Canadian production of oilseed crops (canola, soybeans, and flaxseed) ranges from 8 to 10 million
tonnes per year. Given the current yields, the suitable land base and crop rotational requirements there is
very little potential for increased production of oilseeds in Canada. The oilseeds are grown primarily for the
oil content which has a value of two to four times that of the protein on a weight basis. Most of this oil was
used for high value human consumption markets in Canada or the United States. Approximately four
million tonnes of this crop are exported as seed and as much as 900,000 tonnes are exported as oil.
Approximately three quarters of the exports are canola or canola oil. The primary market for the seed is
Japan and the United States for the oil.
The canola seed has an oil content of approximately 40%, double that of soy oil, so there is the equivalent
of 1.6 million tonnes of oil exported as seed. The maximum potential resource, if one considers all of the
exported material for diversion to the fuel market is 2.5 million tonnes of oil.
One kilogram of oil produces one kilogram of methyl ester or 1.13 litres of biodiesel. If the oil currently
being exported was produced in Canada and converted to biodiesel there would be the potential to produce
2.8 billion litres of biodiesel each year. Total Canadian annual consumption of diesel fuel is 14.5 billion
litres. The potential for substitution of biodiesel is about 20%, which coincidentally is the blend of
biodiesel and conventional diesel being used in the United States. In most urban areas of Canada waste
cooking oils and animal fats are collected and processed into animal feed and feedstocks for chemical
processes. There is very little information available on quantities that might be available for biodiesel
production but it is unlikely that the availability of this material would make a significant difference to the
market penetration potential.
The production costs are strongly influenced by the cost of the vegetable or animal oil used as feedstock.
The production costs are typically broken down as follows:




Oil feedstock
Cost of capital
Direct costs
Indirect costs
70%
7%
14%
9%
Canola oil prices have been about $750 per tonne the last several years. This generates a cost estimate of
$1.00 per litre.
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The following table highlights the impact of biodiesel on exhaust emissions from diesel engines when the
fuel is used either as a blend with diesel fuel or as a neat fuel. The wide variation in the data is evidence of
the influence of engine design on the emissions.
Table 58: Impact of Biodiesel on Exhaust Emissions
Parameter
20% Biodiesel
100% Biodiesel
Particulate Matter
-5 to –15%
+27 to –68%
Total hydrocarbons
-15 to –20%
-37 to –63%
Nitrogen oxides
+1 to +5%
-8 to + 8%
Carbon monoxide
-2 to –16%
-33 to –46%
-20%
-100%
0 to –2%
0 to –5%
Sulphur oxides
Power
Biodiesel is not presently commercially available in Canada. It is commercial in Europe and has some
niche markets in the United States. It has been widely tested and much is known of its properties. Biodiesel
has many similar properties to conventional diesel. The table below compares the properties of the diesel,
soy methyl ester and canola methyl ester as reported by Peterson et al (1994).
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Table 59: Typical Properties of Diesel Fuel and Biodiesels
Property
Diesel
GROSS HEATING
VALUE KJ/KG
SME Soy
Methyl Ester
40,000
45,000
CME Canola
Methyl Ester
40,000
Cetane number
40-45
60
58
Specific Gravity
0.85
0.88
0.88
Pour Point C
-40 to -10
2
-7
Flash Point C
60
180
160
Viscosity CS @ 40C
2-3
4-5
4-5
Sulphur % mass
<0.05
<0.01
<0.01
Oxygen % mass
0
9-11
9-11
Aromatics % volume
25
0
0
Olefins % volume
15
0
0
The positive attributes of biodiesel are higher cetane, the oxygen content, the higher viscosity, and the
lower sulphur. The lower pour point is a problem for Canadian winters that can be partially overcome with
the use of pour point depressants and by using biodiesel as a blend with petroleum diesel fuels. The 10%
lower energy content will impact refuelling frequency or fuel tank size in a commercial application.
Biodiesel is rated non-toxic to humans and aquatic life. It biodegrades about four times faster than
petroleum diesel. Blends of biodiesel and diesel biodegrade about twice a fast as diesel fuel. It has a much
higher flash point than diesel. These characteristics have lead to niche applications such as marine fuels,
and fuels for underground mines. Emissions are lower than petroleum diesel, tests have shown that ozone
forming potential is about one half that of diesel. Emissions of polycyclic aromatic hydrocarbons (PAH)
and nitrated PAH compounds are much lower, most PAH’s are reduced by 75-80% and nPAH’s by 90%.
Biodiesel’s renewability, higher cetane, generally lower emissions, lower toxicity, and biodegradability and
better lubricity are attractive marketing propositions. These have been demonstrated in countries such as
Germany and Austria, which have seen rapid growth in production and marketing in recent years. Market
penetration has been aided by favourable tax considerations that have made the fuel economically
comparable to petroleum diesel in those countries.
5. Ethanol Production Technology
5.1 Ethanol Production Models
Ethanol or ethyl alcohol is can be produced as either 95% ethanol (190 proof) or 100% anhydrous (200
proof). A low-boiling, clear, colorless liquid, it is miscible in all proportions with water and most
hydrocarbon based solvents. Ethanol manufacturing industry is now dominated by the fermentation (and
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distillation) method of production, which depends on grains, such as corn or wheat and converts the
contained sugars into alcohol. There have been promising developments and adoption on a minor scale of
technology based on using biomass raw materials, such as wood cellulose or organic wastes. Biomass
routes are being touted as more cost effective than grain-based fermentation. Generally, synthetic alcohol
production from ethylene has not been competitive with fermentation based processes. Fermentation
alcohol constitutes nearly 90% of North American production. There are only a couple of synthetic ethanol
plants left in the United States. None exist in Canada since Commercial Alcohols closed its facility at
Varennes, QC in the 1980s. This report is focused on fermentation ethanol based on grains. There are
various operational (and business) models that ethanol producers have adopted, as shown by some
examples below.
Table 60: Examples of Production/Business Models
in Ethanol Industry
Fermentation ethanol
Archer Daniel Midland
(ADM)
5 plant locations in the
United States
Commercial Alcohols
Kincardine, ON
Chatham, ON
API Grain Processing
Red Deer, AB
Poundmaker Agventures,
Lanigan, SK
Model Components
Most ADM plants have capacity for 500 to 800 million litres per year
and are based on corn.
ADM has strong position in raw material grains business.
Integrated to livestock feed markets, value-added co-products and other
businesses related to fermentation ethanol.
Diversified food industry business portfolio.
Important stakeholder in mid-west economy.
Based on corn for raw material.
Serves industrial and fuel markets.
New 150 million litre/year fermentation plant in Chatham services fuel
market in Ontario region.
Based on wheat for raw material.
Producer of flour, flour products, wheat gluten, and ethanol for export
markets. Most revenues from flour and flour products.
Relatively low ethanol capacity at 22 million litres/year.
Sells most ethanol in United States.
Based on wheat for raw material.
Ethanol for domestic gasoline blending. Relatively low ethanol capacity
(13 million litres/year). Integrated to cattle feedlot operations.
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5.2 Raw Materials
Ethanol production in North America primarily uses corn as the feedstock. The exception to this is Western
Canada where wheat has been the dominant feedstock. The reason for this is the lack of corn production in
this region and the use of wheat provides lower production costs than importing corn into the region. The
area generally does not have enough heat degree-days and moisture for corn production. The exceptions are
Southern Manitoba and a very small irrigated area of Southern Alberta. Wheat is also an excellent source of
starch that can be converted to fermentable sugars for ethanol production. Compared to corn, wheat has a
lower starch content and a higher protein and fibre content. These characteristics have a small impact on
ethanol production and generally require more energy to make a litre of ethanol than if corn was the
feedstock. The wheat co-products have a higher protein content than corn products and are thus more
valuable as an animal feed.
It has been assumed that any Alberta ethanol plants will be designed to process wheat. Plants that are
designed to make animal feed (dry milling) will process Canadian Prairie Spring (CPS) wheat. For plants
that produce gluten as well as ethanol and animal feed the use of Hard Red Spring (CWRS) wheat is also
investigated to determine the impact of feedstock on greenhouse emissions and energy balances.
Data on feedstock production has been compiled with the assistance of Alberta Agriculture. The data is
based on the consensus estimates of five agronomists and represents grain production in all parts of the
province and not an individual soil type or region. Data has been compiled for both CPS and CWRS wheat
as well as for barley. The barley data is required because in some animal feeds the wheat distillers dried
grains (DDG) will replace barley in the ration. The co-product credit for energy balance and greenhouse
gas emissions purposes will be calculated based on the displaced emissions from barley production for
some of the production scenarios investigated.
5.2.1 Wheat
Wheat is the largest crop in Alberta both in terms of acreage planted and crop produced. In 1997 and 1998
approximately 6.8 million acres (2.75 million hectares) of wheat was seeded producing 6.8 million tonnes
of grain each year. 80% of the crop is spring wheat and 20% is Durum wheat. All classes of wheat are
capable of being used for ethanol production but the most likely feedstock for a dry milling ethanol plant is
CPS wheat. This type has a higher starch content and a lower protein level than hard red spring wheats.
Both characteristics are desirable from the perspective of efficient ethanol plant operations. CPS wheat also
produces a higher yield for the farmer. The Canadian Wheat Board (1999) reports a 44% yield advantage
over CWRS wheat and only a 14% reduction in price resulting in an increase in revenue for the producer,
consequently it’s production is increasing in the Province.
Hard Red Spring wheat is a potential feedstock for a plant producing gluten. Gluten is primarily the protein
portion of the wheat and thus feedstocks that are high in protein have a higher gluten yield. Gluten can be
produced from CPS wheats and in fact the gluten facility in Red Deer uses CPS wheats. Both wheats have
been considered as feedstocks to a gluten ethanol plant combination to determine the impact of feedstock
choice on greenhouse gas emissions and on energy consumption. An ethanol plant in combination with a
gluten facility will process the starch rich, low protein stream that leaves the gluten plant.
5.2.2 Barley
Barley is grown for malting purposes and for animal feed in Alberta. It is the second largest grain crop after
wheat. Typically 5.5 million acres are planted producing 6 to 7 million tonnes of grain. While barley
theoretically can also be used for ethanol production it has a lower starch content and higher fibre content
than wheat making it less desirable. Some of the carbohydrates in barley are beta glucans, which are
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difficult to hydrolyze and ferment. The barley hulls can cause erosion of ethanol plant equipment. The
lower cost of barley is insufficient to overcome these disadvantages of processing barley and the result is
that total ethanol production costs are higher for barley than for wheat.
Barley is of interest for this study because wheat DDG will replace barley in some animal feed rations. The
greenhouse gas emissions and energy credits for DDG are calculated based on the displaced emissions from
barley production.
5.2.3 Agronomic Data
The agronomic data that is required for determining the energy balances and greenhouse gas emissions for
ethanol production in Alberta is summarized in the table below. The data has been compared to corn grown
in Ontario. The Ontario data is from a recent study that used the same greenhouse gas and energy balance
model. (Levelton, 1999). All data is presented on the same weight basis as corn for comparison. The wheat
and barley data represents the agronomist’s best estimates for the crops across the variety of soil zones and
tillage practices in the Province. The estimate for tillage practices were 20% zero till, 35% minimum till
and 45% conventional tillage. It is assumed that all of the fertilizer requirements are met with chemical
fertilizers. The impact of the use of manure to supply a portion of the nitrogen requirements is calculated
later in this section.
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Table 61: Agronomic Data for Alberta Crops Compared to Corn
Yield
Fertilizer
Nitrogen
Phosphorus
Potassium
Sulphur
Lime
Pesticides
Seed
% N from
manure
Energy for
production
Units
Bu/acre
Lbs/bu
Lbs/acre
CPS Wheat
50
60
3,000
CWRS Wheat
38
60
2,280
Barley
59
48
2,832
Corn
116
56
6,496
Lbs/acre
Lbs/56 lbs
Lbs/acre
Lbs/56 lbs
Lbs/acre
Lbs/56 lbs
Lbs/acre
Lbs/acre
Lbs/acre
Lbs/56 lbs
Lbs/acre
Lbs/56 lbs
55
1.03
30
0.56
10
0.19
0
0
0.3
0.006
110
2.05
50
1.27
30
0.74
10
0.25
0
0
0.3
0.007
95
2.33
60
1.186
30
0.59
10
0.20
0
0
0.3
0.006
110
2.17
125
1.08
40
0.34
54
0.47
0
0
2.4
0.021
2.8
.024
35
Litres diesel
equivalent
/acre
Litres diesel
equivalent /56
lbs
13.0
13.0
13.0
18.647
0.24
0.32
0.26
0.16
There are several points of interest in above table. The productivity of wheat and barley is significantly
lower than it is for corn. The fertilizer requirements are similar overall for all four crops, pesticide usage is
lower for wheat and barley compared to corn but seed requirements are higher. The energy required for
planting and harvesting is higher for the Alberta crops than it is for corn in Ontario. These factors will all
have some impact on the energy balance and greenhouse gas emissions of ethanol produced from wheat
rather than corn.
Change in soil carbon content and above and below biomass due to crop cultivation will impact greenhouse
gas emissions. The quantity of biomass is calculated from the grain yield. Bolinder (1997) measured the
root mass as percent of above ground biomass for some potential ethanol plant feedstocks. For barley the
roots were 50% of the above ground biomass and for wheat the roots were 16% of the above ground
biomass. The straw yield is equal to 1.2 times the grain yield for barley and 1.3 times for the wheat crops.
Changes in the level of soil carbon due to cultivation is a function of crop rotations, tillage practices,
fertilizer rates and other management practices. Historically cultivation has caused a loss of soil carbon.
Smith (1995) has calculated that about 23% of the soil organic carbon has been lost in Canada due to
cultivation. Changes in cultivation practices are slowly beginning to reverse this trend. Smith estimates that
by the year 2000 the carbon losses for Canada will have stopped and carbon in the soil will slowly begin to
increase. There are large differences between provinces due to the different soil types and cultivation
47
This is the energy required for field operations. There is an average of 55.2 litres equivalent required for
crop drying in addition for a total requirement 0.63 litres equivalent/56 lbs.
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practices. Smith estimates that Saskatchewan soils began to build soil carbon in 1995 but Alberta soils are
still forecast to be depleting carbon through to the year 2010. The rate of carbon loss has been modeled to
be 0.0036 kg C/m2/yr in 2000 and 0.0027 kg C/m2/yr in 2010.
The difference in the rate of loss of soil carbon between Alberta and Saskatchewan is primarily a function
of the rate of nitrogen fertilizer application. Nitrogen loss through the removal of crops in Alberta exceeds
the rate of nitrogen added through fertilizers, whereas Saskatchewan has recently reversed this long
standing practice. There is a delicate balance of carbon and nitrogen in soils such that a drop in soil
nitrogen leads to a drop in carbon to maintain this balance.
The rate of soil carbon loss modeled is consistent with the other agronomic data modeled. The nitrogen
added with the fertilizer is essentially equal to the nitrogen removed in the grain. This will not be enough
nitrogen to cause soil carbon to increase.
5.2.4 Energy Requirements for Crop Production
A full cycle emissions model was developed by Dr. Mark Delucchi of the University of California at Davis
in the early 1990’s. The model has been used by the US DOE and Natural Resources Canada to model
greenhouse gas emissions from fuels and vehicles. More detail on the model is presented in section 6.1 The
Delucchi model calculates the energy required for the production of the crops of interest from the
agronomic data. The energy requirements are calculated not only from the actual fuel used in the farming
process but also from the energy used to produce the farming inputs of fertilizer and pesticides. The model
results for the three feedstocks of interest are shown below along with the data for corn production in
Ontario.
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Table 62: Energy Requirements for Crop Production
units
Fertilizer Manufacture
Pesticide Manufacture
Field Operations
Total
CPS Wheat
BTU/56 lbs.
35,681
643
8,754
45,078
CWRS Wheat
BTU/56 lbs.
43,723
750
11,671
56,144
Barley
BTU/56 lbs.
40,360
643
9,482
50,485
Corn
BTU/56 lbs.
21,360
998
22,894
45,252
The energy requirements for CPS wheat are close to those for corn. Fertilizer requirements are higher due
to the higher protein levels in the wheat but less energy is required for crop drying so field energy
requirements are much lower. The variations in energy efficiency will have an impact on the energy
balance and greenhouse gas emissions of ethanol production from wheat.
The results in the above table for wheat are comparable to those reported by Stumborg et. al. (1996). In that
study energy requirements for a variety of wheats, tillage systems and soils in Saskatchewan were
calculated. Results ranged from a low of 31,600 BTU/56 lbs. to a high of 107,000 BTU/56 lbs. The average
value for CPS wheat was 61,500 BTU/56 lbs. and the average for CWRS was 74,700 BTU/56 lbs.
Stumborg does not provide detailed information on fertilizer and fuel use so it is difficult to determine the
exact reasons why his average energy values are higher. Possible explanations are that wheat yields are
generally lower in Saskatchewan than in Alberta and fertilizer application rates are higher.
The greenhouse gas emissions from the production of wheat, barley and corn for manufacturing ethanol are
shown in the table below. The emissions are for the feedstock required to produce 44.9 litres of ethanol or
one million BTU of energy.
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Table 63: Greenhouse Gas Emissions for Wheat, Barley
and Corn Production
Units
Farming
Land Use and
Cultivation
Fertilizer
Manufacture
Total
Total grams
CO2/lb grain
CPS Wheat
Grams CO2/million
BTU
6,504
-1,807
CWRS Wheat
Grams CO2/million
BTU
8,672
-304
Barley
Grams CO2/million
BTU
7,890
-3,123
Corn
Grams CO2/million
BTU
8,912
908
12,824
15,709
16,112
6,654
17,521
65.5
24,077
87.5
20,879
69.9
16,474
66.5
Alberta has a large and important livestock industry, which produces substantial quantities of manure. The
manure is spread on the land for disposal. This process also fertilizes the soil and provides nitrogen to the
soil. This results in less chemical nitrogen added and lower emissions from the production of nitrogen
fertilizer. The emissions of N2O do not change significantly and the nitrogen in the manure can still be
converted to N2O. There is additional diesel fuel required to spread the manure and work it into the soil.
Alberta Agriculture was unable to provide an estimate of the amount of the crop nitrogen requirement that
is currently being supplied by manure. This practice is known to exist so it is important to determine the
magnitude of the impact of manure addition on the energy requirements and greenhouse gas emissions that
have been calculated for CPS wheat. This will aid in determining if the GHG results calculated for 100%
chemical fertilizer are conservative or pessimistic. It will be assumed that over a four year period the
manure replaces an average of 17.5% of the annual nitrogen, with the manure being added in year 1 and the
benefit being measured over the four years. An additional 3.75 litres of diesel fuel is used in year 1 to
spread and incorporate the manure into the soil. This calculation does not assume any additional cattle
production or manure generation over the current situation.
Table 64: Energy Requirements for CPS Wheat With and
Without Manure
units
Fertilizer Manufacture
Pesticide Manufacture
Field Operations
Total
CPS Wheat w/o manure
BTU/56 lbs.
35,681
643
8,754
45,078
CPS Wheat with manure
BTU/56 lbs.
16,928
643
11,373
28,944
Table 65: Greenhouse Gas Emissions for Wheat and Corn
Production
Units
Farming
Land Use and Cultivation
CPS Wheat w/o
manure
Grams CO2/million BTU
6,504
-1,807
83
CWRS Wheat with
manure
Grams CO2/million BTU
8,450
-1,807
CHEMINFO
Fertilizer Manufacture
12,824
7,389
Total
Total grams CO2/lb grain
17,521
65.5
14,032
52.4
The use of manure as a source of nitrogen is beneficial from the perspective of energy used in the
production process and greenhouse gas emissions. It has not been possible to accurately estimate the
quantity of nitrogen fertilizer replaced by manure in Alberta. The use of 100% chemical fertilizers has been
modeled in determining the overall greenhouse gas emissions and energy balances and it is recognized that
the results projected are conservative because of the use of manure. A sensitivity case will be modeled that
includes the use of manure in one of the ethanol production scenarios.
5.3 Ethanol Production Models for Alberta
Four ethanol plant models have been developed to analyze the potential feedstock and energy requirements
related to increased ethanol production in Alberta. The first considers an ethanol plant integrated with a
cattle feeding operation similar to the Pound Maker Agventures facility at Lanigan Saskatchewan. The
second concept is a conventional dry milling operation processing wheat and producing distillers dried
grains. The third concept combines a wheat gluten plant with an ethanol plant. For this concept the use of
both CPS and HRS wheats are investigated and modeled. The summarized results for energy and feedstock
requirements, as well as products from the four ethanol plant configurations are provided in the following
table. The gluten plant options are presented on the basis of a tonne of feed to the gluten plant. For larger
size ethanol plants, dry milling plants are generally more feasible than wet milling. Very large nearby
feedlot operations would be required to support large wet milling operations. More detailed descriptions are
provided below.
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Table 66: Summary of Ethanol Plant Inputs and Outputs
Integrated Feedlot
Ethanol Yield, L/t
Natural Gas
Consumption scf/L
Electricity
Consumption
kWh/L
Animal feed kg/t
feed
Gluten kg/t feed
370
7.77
Conventional Dry
Mill
370
9.98
Gluten Plant with
CPS Wheat
340
3.70
Gluten Plant with
HRS Wheat
325
4.44
0.25
0.40
352
352
0.11
(incremental for
ethanol only)
269
0.11
(incremental for
ethanol only)
283
0
0
88
100
5.3.1 Wheat Feedstock in an Ethanol Plant Cattle Feedlot Complex
An ethanol plant integrated with a cattle feedlot has a number of advantages over more traditional stand
alone facilities. The capital costs are lower because no drying of the distillers grains (DG) is required. This
also reduces the energy consumption in the ethanol plant. The plant captures the true value of the coproduct since it is all utilized by the operation where the benefits of higher feed efficiency and higher rates
of growth are captured.
The size of these facilities is limited by the number of cattle in the feedlot and the total size of the industry
is limited by the number of cattle fed in large feedlots. A facility with an ethanol production rate of 15
million litres per year and a one time feedlot capacity of 30,000 is modeled. This is similar in size to the
Pound Maker operation.
The energy requirements of the ethanol plant are 29.4 scf of natural gas used per USG of ethanol
production and 0.95kWh/USG of electricity. It has been assumed that 0.01 USG of diesel fuel is also used
at the plant.
5.3.2 Conventional Wheat Dry Milling Plant
A conventional dry milling plant is not limited in size by the co-product market in the immediate vicinity of
the plant since the product can be stored and shipped. The energy consumption in the plant is higher than
the integrated cattle feedlot plant since the co-product must be dried. This is offset partially by higher coproduct displacement ratios which are discussed in more detail later in this section.
The energy consumption in the plant is modeled as 37.7 scf of natural gas per USG of ethanol and 1.51
kWh/USG of electricity. The same 0.010 USG of diesel fuel per USG of ethanol produced is modeled. This
is a state of the art facility with respect to energy consumption.
5.3.3 Wheat Gluten and Ethanol Plant
Wheat gluten is a portion of the protein found in the wheat grain kernel. It has a number of applications in
foods for humans and typically commands a higher price than the protein used in animal feed rations. The
gluten plant does not utilize the starch, which can be used to manufacture ethanol. The concept modeled
here is a combined gluten and ethanol operation. The energy consumption has been broken out between the
gluten plant and the ethanol plant so that the ethanol plant can be modeled by itself.
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The feedstock for the ethanol plant is the co-product from the gluten operation. The farming emissions have
been allocated between the gluten facility and the ethanol plant on the basis of weight. The facility has been
modeled both with CPS wheat as the feedstock and HRS wheat as the feed. From a gluten perspective the
HRS with its higher protein levels will provide a higher gluten yield and is usually the type of wheat used.
CPS wheat is being used as the feedstock at the Red Deer gluten ethanol plant complex.
The incremental electrical energy for ethanol at a gluten plant for both feedstocks is 0.11 kWh/litre of
ethanol and the incremental natural gas requirements are 3.70 scf/litre of ethanol for CPS feedstock and
4.44 scf/litre ethanol for the HRS feedstock. There are some synergies between the gluten plant and the
ethanol plant as can be seen from the lower energy consumption for the ethanol part of the gluten ethanol
complex. The synergies have been all allocated to ethanol since that way the emissions displaced by the
gluten production become the same as a stand alone gluten plant. This is the appropriate treatment as long
as the supply of this new gluten in Alberta does not create new demand for the gluten.
The ethanol yields expressed per tonne of gluten plant co-product (ethanol plant feed) are 370 litres/t for
CPS wheat and 360 litres/t for the HRS feedstock.
5.3.4 Co-Products
Ethanol production utilizes the starch portion of the feedstock. The protein, fibre and minerals do not
contribute to ethanol and constitute the co-products (or by-products). Typically an equal weight of ethanol
and co-products are produced. Depending on the ethanol production process used, different ratios and a
variety of co-products can be produced. These are described further under the two general categories of
ethanol production, dry milling and wet milling.
5.3.4.1 Dry Milling
The co-products of a dry milling ethanol plant are carbon dioxide and distillers grains. In large plants (more
than 50 million litres per year) it can be economical to collect the carbon dioxide and sell it. Most
applications for CO2 result in the CO2 eventually being released into the atmosphere so it has little impact
on greenhouse gas emissions. CO2 is not considered in the greenhouse gas emission analyses that follow.
Distillers grains (DG) can be used wet or dried and are almost exclusively used as an ingredient in animal
rations. It is high in protein, fibre and micro-nutrients. It is also very digestible and widely accepted as a
premium feed ingredient. Distillers grains made from wheat have protein contents of 35%. Wet distillers
grains (WDG) typically have a moisture content of 65% and have a shelf life of 2-3 days. The high
moisture content and short shelf life require the product to be consumed close to the point of production. A
scenario where the ethanol plant is integrated with a cattle feedlot is developed. Dried distillers grains
(DDG) have a moisture content of less than 10% and an indefinite shelf life. A second scenario is
developed for dried distillers grains than are shipped to the end consumer.
The model uses the displacement method for determining the energy and greenhouse gas credits that should
be applied for the distillers grains. It is thus necessary to determine what would have been in the animal
ration if the distillers grains were not included and what would be the overall impact on the quantity of feed
consumed by the animal. One of the key components of DG is its high protein content and more
importantly its high level of bypass protein. Bypass protein is protein that is not degraded in the rumen but
is absorbed in the intestine where the animal requires a portion of its protein. This is particularly important
for cattle, the primary market for DG.
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Different types of animals require different amounts of bypass protein and the amount also varies over the
life cycle of the animal. Cattle require more bypass protein when they are small and growing rapidly than
when they are approaching full size. Dairy cows require very high levels of bypass protein during lactation.
The two scenarios under consideration therefore have different displaced emissions due to the different
uses of the DG.
The integrated plant gets less value from the DG since there tends to be more protein available than the
animals require. The displacement ratio is therefore lower. Delucchi uses a displacement ratio of one pound
of DDG replacing 1.57 pounds of corn in cattle rations. In Canada the feedlot will be feeding barley rather
than corn and the DG will have a higher protein level than corn DG. The barley has a higher protein content
than corn so the animals need for protein from supplements is lower. The experience at Pound Maker
Agventures where wheat does displace barley is that the displacement ratio is strongly dependent on being
able to optimize the ratio by including lower quality components in the ratio to offset the high quality DG.
It is not always possible to source this material and thus the displacement ratio is often less than it
theoretically could be. It has been assumed that one pound DG replaces 1.4 pounds of barley for modelling
purposes. As shown earlier barley greenhouse gas emissions are 1.068 times higher than wheat on a per
unit weight basis. The modelling of greenhouse gases is performed on the basis of one pound of DG
replacing 1.49 pounds of wheat with no energy required for drying and no energy for the distribution of the
DG to the consumer.
The second scenario examined is where the DG are dried so that they can be stored and shipped to
consumers that are some distance from the ethanol plant. There are increased emissions from the drying
and transportation of the DDG but it is assumed that the consumers can take full advantage of the bypass
protein and that higher displacement ratios can be achieved.
It has been assumed that the average transportation distance of the DDG is four times that of the wheat
entering the plant or 200 miles. All of the DDG is shipped by truck. Wang (1999) reported displacement
ratios for corn DDG of one pound DDG replacing 1.077 lbs. of corn and 0.822 lbs. of soymeal. These ratios
were based on DDG being used not only for cattle rations but also a portion for dairy cows. It is expected
that in Alberta the wheat DDG will replace barley and canola meal in rations. Delucchi reports a
displacement factor for soymeal based on barley. After adjusting for the different protein levels in soymeal
and canola meal the overall displacement ratio becomes one pound of wheat DDG replaces 3 lb. of barley.
This is the ratio used for this scenario.
There is another aspect of DDG use that has not been investigated in previous full cycle analyses of ethanol
production and use. That is the impact of DDG on the animal consuming the DDG and its emissions of
methane. There have not been any definitive studies done on the magnitude of changes in methane
emissions from the addition of DDG to a ration (Mathison, 1999). An analysis of methane production from
cattle fed brewers grains, distillers grains with solubles and corn gluten feed confirmed that DDGS
produced less methane and more energy than corn gluten feed (Jarosz). The diets used by Jarosz were
designed to determine the impact of the feedstock and were not representative of feedlot rations so it is
difficult to extrapolate the magnitude of the impact from the work.
Small changes in feed efficiency in the animal, if the daily rate of gain does not change significantly, are
expected to influence methane emissions. The experience at Pound Maker Agventures and from feed trials
performed in the United States (Fanning, 1999, and Ham, 1994) suggests that 8 to 10% less feed is required
for the same gain if the feed contains DDG. For small changes in feed, methane emissions are directly
proportional to feed efficiency (Mathison). Feedlot cattle in North America emit 47 kg methane/head/year
(IPCC, 1996). Feedlot cattle consume about 10 kg/day of feed. Methane emissions are therefore 12.9 grams
of methane per kg of feed. One kilogram of DDG saves 0.5 kg of feed or 6.4 grams of methane. Each litre
of ethanol has 0.7 kg of DDG produced, which is equivalent to 4.5 grams methane or 94 grams of CO 2 eq.
A million BTU of ethanol has equivalent savings of 4,200 grams of CO 2 eq. This is approximately 8% of
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the full cycle emissions as will be shown in the next section. The impact is even greater on dairy cows since
they emit more than twice as much methane per head per year.
This methane emission credit has not been included in the full cycle analyses because it has not been
conclusively proven. It should be an area of research because of the magnitude is significant.
5.3.4.2 Wet Milling
The wet milling plants considered here produce gluten and a low protein animal feed as co-products. The
modelling has been done in such a fashion that the energy required to produce the gluten has been kept
separate. This way it is not necessary to deal with the issue of gluten co-product values. The ethanol plant is
simply another facility that has as its feedstock the wet starch stream from a gluten plant.
The primary outlet for gluten is in bakery products. Vital gluten is added to both conventional and
continuous white pan bread, bread and rolls, including rye, specialty protein and diet breads, rolls and buns,
and sweet yeast—raised products. It is generally used at 2-4% of the flour in breads and rolls.
The addition of vital gluten to baked goods improves dough-handling properties and the quality of the
finished product. Supplementing flours that have poor baking qualities and low protein content with vital
gluten permits reducing the number of flour types required, and tends to increase production flexibility.
Addition of gluten to buns and rolls, like sandwich buns, improves hinge strength and produces the type of
crust most desirable in commercial markets where buns are steamed. Yeast—raised sweet goods, like
doughnuts, when fortified with gluten, generally show greater volume, proof tolerance, and strength.
Vital gluten also finds some usage as a supplemental source of protein in breakfast cereals. Gluten can also
be used as a texturizing protein and meat substitute in all vegetable meat-like products. Other food
applications of gluten are as a protein source for the preparation of hydrolyzed vegetable proteins, in soy
sauce production, and as a meat or fish extender in sausage or pasta-type products.
Current U.S. consumption of Vital Gluten breaks down to approximately 85 million pounds per year for
cereal and other human consumption products and 20 million pounds for pet food year for a total of 105
million pounds per year. Of this figure more than one third is supplied by imports primarily from Canada
and Australia (Don, these numbers are old and still need verifying)
The growth in vital gluten market for human consumption is expected to rise only proportionately to
population. Significant growth is also anticipated in pet foods where it is used as a supplement and/or
replacement of meat, due to its very high protein content (e.g., 80%+). Relative to meat prices, based on
protein content, vital gluten is an attractive alternative to pet food processors.
The bran, fibre and yeast produced as by-products in gluten-ethanol plants will have a different
composition from normal distillers grains due to the removal of the high protein gluten concentrate.
However, the combined products would have a good energy/protein balance. The material does have a
protein content of 15 to 16%.
The animal feed that is produced is assumed to replace barley on a one to one basis in animal rations. This
is a reasonably assumption given the composition of the product. This product is dried and shipped to
consumers. Since there is less of this product produced than a dry mill facility and because it has a lower
value it has been assumed that it can be used closer to the ethanol plant. The shipping distance for this
material is assumed to be equal to the distance that the feedstock coming in to the plant travels. This is one
quarter of the distance assumed for the dry mills.
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5.4 Ethanol Plant Economics
Ethanol plant revenues and profits are dependent on many factors, including: plant size; configuration; type
and amount of co-products (or by-products) made; the price of raw material – in this case wheat; and coproduct revenues. For smaller plants the ability to sell ethanol (at above gasoline producers’ value – i.e.,
around 40 cents per litre) as well as animal feed to regional customers can be important factors for
profitable operations. Without tax incentives directly influencing ethanol prices, some plants cannot be
profitable.
Prices for raw materials and for finished products change constantly. Currently grain prices are low and
energy prices are high which leads to a period of high profitability for ethanol producers. The following
economics are based on the market conditions of late 1999. Given wheat raw material price at $100 per
tonne, and co-product DDG animal feed price at $160 per tonne, the breakeven ethanol price for a 100
million litre per year facility is approximately 28 cents per litre (includes additional simplifying
assumptions for financing, etc. – see below)48. For larger ethanol plants co-producing wheat gluten, the
ability to actually sell the gluten (at required prices) is a necessary component of the profitability shown in
model plant economics. Under actual business conditions, market barriers in the wheat gluten market may
affect the ability to achieve the revenues and profits assumed for these model plants.
Table 67: Summary of Revenues and Operating Expenses for
Model Plants
Dry mill
CPS wheat,
with feedlot,
no drying
Dry mill CPS, Gluten/Ethanol Gluten/Ethanol
with DDG
CPS
HRS
Model A
25
Model B
100
Model 3
100
Model 4
100
$10.0
$40.0
$40.0
$40.0
$3.0
$11.8
$(36.1)
$(46.4)
Energy (electricity, natural gas)
Labour
Maintenance & overheads
$0.8
$1.0
$1.2
$4.3
$1.0
$4.2
$9.2
$2.8
$6.8
$9.4
$2.8
$6.8
Total expenses
Interest on debt
$5.9
$1.4
$22.3
$4.7
$(17.3)
$7.7
$(27.4)
$7.7
Ethanol capacity (million
litre/yr)
($ million)
Revenue (ethanol only)
(at 40 cents/litre)
Net raw material cost
(credits applied for by-products – feed and/or gluten)
(assumed 25:75 debt to equity, 9% interest changes)
48
Generally, prices for DDG, gluten and raw materials are based on information from industry sources.
DDG prices are based on soybean meal values adjusted downward for protein content in DDG. DDG prices
in this study were based on soybean meal values at the time of preparing this report in December 1999. By
May 2000, soybean meal values were different than in December 1999.
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Income before income tax
Income tax rate*
Income tax payable
$2.7
38%
$1.0
$12.9
38%
$4.9
$49.6
38%
$18.8
$59.7
38%
$22.7
Net income
Return on Investment
$1.7
9%
$8.0
11%
$30.7
27%
$37.0
32%
(Annual net income divided by total capital
employed *)
* Excludes capital cost allowances (CCA), which would result in reduced income taxes, and
greater returns on investment.
5.4.1 Ethanol Plant Construction and Operating Costs
This section provides an overview analysis of production options and associated costs for model ethanol
facilities based on using wheat as the raw material. The models are useful for providing approximate
estimates of capital cost, employment, revenues, operating expenses, income taxes and profits associated
with different sized plants and for alternative business profiles. Microeconomic parameters are estimated
based on the assumption of construction of “greenfield” facilities and the following profiles.
Table 68: Size and Description of Model Facilities
Model
Ethanol
Capacity
Plant Profile
(million litres/year)
A
25
B
100
C
100
D
100
Dry mill CPS wheat with adjacent cattle feedlot.
No drying of wet grains
Dry milling with DDG for sale.
CPS wheat.
Gluten Production with ethanol by-product.
CPS wheat.
Gluten Production with ethanol by-product.
HRS wheat.
Model A corresponds to a relatively small plant that produces ethanol and Wet Distillers Grains (WDG).
No drying of the distillers grain is undertaken. The wet DG requires a nearby feed lot of approximately
1,000 to 1,200 head of cattle per million litres of annual ethanol production. This assumes a ration of 30%
WDG, with the remainder feed barley, roughage and concentrates. The Pound-Maker Agventures EthanolFeedlot in Lanigan, Saskatchewan employs an even lower ration than 30% WDG, which results in
approximately 2,400 head per million litres of annual ethanol for that facility. Pound-Maker have found the
constraints to be the amount of liquid consumed by the animals during cold weather and the animals
optimum protein requirements.
Model B involves 100 million litres per year ethanol production combined with drying and resultant
production of Distillers Dried Grains (DDG). This product can be shipped to more distant (than WDG)
animal feed markets and does not rely on a feedlot operation.
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Models C and D correspond to 100 million litre/year ethanol operations where the wheat gluten containing
protein is separated and sold on international markets. Models for CPS and HRS wheat were developed to
compare the alternative raw materials. The bran, fibre and yeast produced as by-products of these glutenalcohol plants will have a different composition than normal distillers grains due to the removal of the high
protein gluten concentrate.
For Models C and D (gluten plants), the bran, fibre, and wheat germ components ("mill feed"), have been
added to the stillage solubles to arrive at the total animal feed production, in order to simplify the
comparison. In a fully integrated plant, these may be separated and which may add to by-product values.
The result would be similar for HRS and CPS (76.5% flour vs. 75% flour).
5.4.2 Capital Cost Estimates
Capital (including installation) costs have been conservatively estimated. There have been some facilities
of comparable size to the models that have been installed for less than indicated in the model plants.
However, some of these have been at, or near, existing complexes. Capital cost estimates are meant to be
order-of-magnitude only. They serve the purpose of this project and should not be used for investment
decisions. These estimates are based on a combination of the following:







Process Equipment Costs are based on costs published by Chemical Engineering January
1982, updated to December 1998, using Chemical Economic Indicators, allowing the
Lang Multiplier of 1.5 to 2.5 to give installed costs and 10% contingency adjusted for
Canadian factors, plus engineering, project management;
Standard equipment supply packages and systems prices were obtained from appropriate
manufacturers. Some prices were obtained from various vendors. Engineering estimates
based on 1998 units costs such as (per sq.ft.)(per ft. of length)(per ton), etc.;
Installation performed at 1998 union rates;
Grain handling and cleaning, flour mill, mashing sized @ 115% of plant capacity rating;
Wet Gluten Processing, fermentation process sized @ 110% of plant capacity rating,
balance sized @ 105% of rated capacity; and
Co-generation of Steam and electric power are not included.
Costs of Feedlot operation are not included.
The capital (and operating) costs for an ethanol plant making ethanol and Distillers Dried Grains (DDG)
increases. Drying, handling and other equipment are required. Making wheat gluten results in additional
capital cost to the basic ethanol/WDG-feedlot plant. However, if the gluten can be sold at reasonable price,
there is a substantial positive return for this incremental investment.
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Table 69: Estimated Capital and Construction Employment
Plant Model
Ethanol
Capacity
Capital Cost*
Construction
Employment
(million litres/year)
($ million)
(total labour-years
over 3 years)
20
800
70
2,400
114
9,600
114
9,600
* Excludes capital costs for feedlot operations. Construction employment include direct and indirect
A
B
C
D
Ethanol + feedlot
Ethanol+DDG
Ethanol+Gluten (CPS)
Ethanol+Gluten (HRS)
25
100
100
100
5.4.3 Revenues, Operating Expenses and Returns
Revenues from ethanol plants are generated from sales of ethanol as well as WDG, DDG animal feed,
gluten or other value-added products. Prices for these products vary over time, depending on the global or
regional demands, contract volumes, and other factors. For this analysis the following sale price
assumptions have been made:





ethanol at 40 cents/litre;
animal feed (without gluten removed) at $160 per tonne;
animal feed (with gluten removed) at $125 per tonne;
gluten at $1.0 per pound ($2205 per tonne); and
carbon dioxide value is assumed zero (some plants do sell the CO 2).
The ethanol price inherently reflects the effect of provincial retail tax relief of 9 cents per litre and the
Federal Excise tax exemption of 10 cents per litre. Animal feed with gluten protein contained is higher
priced than animal feed, gluten removed. The gluten price is based on U.S. import values and quantities.
These are simplifying price assumption for the purpose of this study. These prices may not be available or
relevant for specific times and under difficult business conditions. In addition, entry by new suppliers into
existing markets can present problems. Suppliers of gluten or DDG may protect key accounts by reducing
prices.
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Table 70: Revenues for Model Plants
(dollars)
Dry mill
CPS wheat,
with feedlot,
no drying
Dry mill CPS,
with DDG
Gluten/Ethanol
CPS
Gluten/Ethanol
HRS
($)
Model A
Model B
Model 3
Model 4
Ethanol
Animal feed
Gluten
10,000,000
3,805,405
-
40,000,000
15,221,622
-
40,000,000
9,889,706
57,070,588
40,000,000
10,884,615
67,846,154
Total Revenue
13,805,405
55,221,622
106,960,294
118,730,769
Because of its high value as a food commodity, the use of wheat for industrial purposes has been fairly
limited. Wheat is the feedstock of choice for fuel ethanol production in the prairies. It is currently used as a
feedstock in the Pound-Maker plant in Saskatchewan and the Mohawk Oil Co. Ltd. plant in Manitoba. In
Europe and in Australia, wheat is considered the primary raw material for fuel ethanol production. It is a
generally more expensive feedstock than corn although higher protein DDG and higher DDG yields offset
much of the higher cost49.
Commercial ethanol yields typically range wheat vary 340 to over 500 litres per tonne of wheat. Yields
vary depending on the type of wheat, as well as the ethanol process employed. Some processes that recycle
fermenter broth report yields in excess of 500 litres/tonne. 50 For this analysis the following yields and
wheat requirements have been assumed for the different model plants.
Net raw material costs are dependent of the price of wheat and competing sources of protein (soybean
meal). Prices fluctuate substantially over time. The simplifying assumption for this analysis is that the price
of wheat for ethanol production is $100 per tonne (2.70 $/bushel). The portion of the wheat (e.g., ~10%)
that is used for gluten would need to be purchased through the Canadian Wheat Board (with an associated
current price of $150 per tonne). Therefore, the total weighted average price of the raw material wheat for
Models C and D is $105 per tonne (90% * 100 $/t + 10% * 150 $/t). A slightly greater amount of HRS
wheat than CPS wheat is required per unit of ethanol produced in gluten plants.
Table 71: Wheat Requirements for Model Plants
Dry mill
Dry mill Gluten/Ethanol Gluten/Ethanol
CPS wheat,
CPS,
CPS
HRS
with
with DDG
feedlot,
no drying
Model A
Model B
Model 3
Model 4
49
Tibelius, C., Coproducts and Near Coproducts of Fuel Ethanol Fermentation from Grain, Agriculture
and Agri-Food Canada - Canadian Green Plan Ethanol Program: Starchy Waste Streams Evaluation
Project, May 1996
50
ibid.
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Tonnes wheat/tonne ethanol required
Total wheat required (tonnes)
3.42
67,568
3.42
270,270
3.72
294,118
3.89
307,692
Wheat bushels (1000)
2,483
9,932
10,808
11,307
Price of wheat ($/tonnes)
Wheat costs ($ million)
$100
$6.8
$100
$27.0
$105
$30.9
$105
$32.3
Revenues for by-products are often credited against raw material costs. Viewed in this manner, the net raw
material cost for gluten plants can be substantially negative. That is, there is more potential revenue
associated with by-products (gluten and DDG) than the cost of purchasing the wheat. Cost calculations
below assume that all of the gluten and DDG can be sold at $1/lb. This may not always be the case. It is
emphasized that transportation costs to accessible markets, other distribution and marketing costs
have not been considered. Industry sources point out that wheat gluten typically sells for 75-1.00$/lb. One
supplier claims that C$1.00 per pound is very close to the current price.
5.4.4 Employment
The more complicated the facility, the more employees are required for operations, handling, maintenance,
sales and management. Total estimated employment for a 100 million per year ethanol plant is estimated at
50 people. Another 20, for a total of approximately 70 people would be required for a gluten/ethanol
facility.
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Table 72: Permanent Employment
(Includes sales and management: excludes feedlot)
Dry mill
CPS wheat,
with feedlot,
no drying
Model A
Model B
Model 3
Model 4
25
50
70
70
$1,000,000
$2,000,000
$2,800,000
$2,800,000
Employees
Payroll
Dry mill CPS, Gluten/Ethanol Gluten/Ethanol
with DDG
CPS
HRS
5.4.5 Other Expenses
The following assumptions have been made for the price of utilities and other costs:




electricity available at 4 cents/kilowatt-hr; and
natural gas available at 2.75 $/million BTU (or 1000 scf); and
insurance, maintenance, expenses, etc. at 6% of capital costs; and
income tax rate in Alberta at 38%.
Producing DDG adds to the electricity and heating requirements versus an ethanol plant selling wet DG.
Energy costs more than double for gluten/ethanol plants.
Table 73: Utility Requirements for Model Plants
Dry mill
CPS wheat,
with feedlot,
no drying
Total electricity required
(kW-hr/litre ethanol)
Total cost electricity
Natural gas required
(scf/litre ethanol)
Total gas cost
Dry mill CPS, Gluten/Ethanol Gluten/Ethanol
with DDG
CPS
HRS
Model A
Model B
Model 3
Model 4
0.25
0.40
1.04
1.04
$250,000
$1,600,000
$4,160,000
$4,160,000
7.8
1.0
18.3
19.0
$534,188
$2,744,500
$5,027,000
$5,230,500
5.4.6 Fully Integrated Facility
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An integrated wheat biorefinery that can produce fuel ethanol, milled wheat products and higher value
coproducts has long been touted as the most viable choice for the future of the wheat industry. 51 These
plants separate the wheat into the fibrous bran hull, the germ, starch and gluten, all before fermentation the
production of ethanol. Determining the suitable size and operational flexibility for these plants in
consideration of potential market costs or barriers are important investment considerations for such plants.
5.4.6.1 Economics of Integrated Facility
The incremental capital cost to a 100 million litre-ethanol/year gluten /ethanol for construction of an
integrated biorefinery has been very roughly estimated at $60 million. These facilities are more labour
intensive and can add 20, or so, more employees to the payroll. They are also more energy intensive than
gluten/ethanol plants. The profitability of these plants is heavily dependent on revenues from value-added
co-products, which will exceed ethanol sales. Detailed plant costs and market analysis for all co-products
(beyond the scope of this study) are required to develop proper economic models for these types of
facilities.
5.5 Technology Developments
Technology developments for the production of ethanol include (not limited to) advances related to:
alternative raw materials (e.g., cellulose biomass instead of grains); increasing the efficiency of the
fermentation process; improving the separation of co-products; use of ethanol as a renewable transportation
fuel. Some of the Canadian research activities are described below. This analysis is not intended to be
comprehensive of all the research underway. Nor, does the study have the scope of evaluating the potential
impacts of the research on the ethanol industry. There may be many other or more important R&D
activities.52
5.5.1 Examples of Ethanol Research Areas in Canada
A range of carbohydrate containing biomass raw materials may be used for ethanol production. These
include: rice straw; corn fiber; sawdust; pulp and paper sludge; yard clippings; and dedicated energy crops
like switch grass‚ prairie grasses and fast-growing trees. Advances such as the production of new enzymes
and development of new production processes may facilitate the commercialization of cellulose (as
opposed to sugars only) to ethanol production.
Petro-Canada and Iogen (a privately held biotechnology company of 60 people) have signed an agreement
to develop new ethanol production technology from biomass. Iogen and Petro Canada plan
commercialization of ethanol from cellulose using Iogen’s technology known as enzymatic hydrolysis. The
process produces fermentable sugars from such feedstocks as straw, hay, grasses and oat hulls. PetroCanada uses ethanol for some of its gasolines, particularly SuperClean 94, a high octane fuel sold in
Quebec. Iogen has recently received a $10 million loan from Technology Partnerships Canada towards
construction of a $25.3 million ethanol demonstration plant. The demonstration plant will be located
adjacent to Iogen’s current enzyme manufacturing facility in Ottawa. The companies initiated construction
in April of 1999 and hope to have production begin in the summer of 2000. By the fall of 2000, should the
51
Tibelius, C., Coproducts and Near Coproducts of Fuel Ethanol Fermentation from Grain, Agriculture
and Agri-Food Canada - Canadian Green Plan Ethanol Program: Starchy Waste Streams Evaluation
Project, May 1996
52
This analysis borrows from past Cheminfo Services studies and other existing literature on ethanol
research.
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demonstration plant be successful, work on a commercial plant will be started. Iogen plans to have several
plants constructed across Canada by 2004.53,54
There are various universities and other institutions that are conducting R&D into ethanol into Canada. At
the University of British Columbia, a proposal is in progress to establish a Process Development Program
to adapt the most promising world technologies to produce ethanol and by-products from BC softwood
residue. The proposal seeks to progress the technology from bench scale to larger scale in a 5-year
timeframe. The University of Saskatchewan and the University of Toronto are other universities that have
or are conducting ethanol related R&D. Research into very high gravity fermentation (VHG) of wheat to
produce ethanol continues to be done at the University of Saskatchewan. 55 The VHG process involves
removal of the bran before fermentation, which relates to value-added co-product production.
Seaway Valley Farmers Energy is working with ethanol production technology developed at Queen's
University. The technology uses oleyl alcohol as a solvent for continuous extraction of ethanol and to avoid
end product inhibition. The new technology is said to double the efficiency of ethanol production.
Agriculture and Agri-Food Canada was more involved in ethanol R&D in the past. AAFC’s Green Plan
Ethanol Research Program lasted approximately 3-4 years, but was shut down a few years ago. This
program conducted R&D on a wide variety of areas with respect to ethanol at AAFC’s research stations
across Canada. Natural Resources Canada’s Alternative Fuels Market Development Program had annual
expenditures of $900,000 in 1996/97. This initiative was developed to encourage the production and use of
alternative fuels and alternative fuel vehicles. The alternative fuels that were focused on include methanol,
ethanol, propane and natural gas. A second program at NRCan, the Alternative Transportation Fuels Research and Development program, had annual expenditures of over $5 million in 1996/97. The purpose
of the program was to increase the market penetration of alternative transportation fuels through technology
development.56
53
Cheminfo Services Inc., Profiles of Selected Technologies to Reduce GHG Emissions, For National
Climate Change Secretariat, Technology Table, May 1999.
54
Camford Information Services, Camford Chemical Report, February 1, 1999 Issue.
55
Tibelius, C., Coproducts and Near Coproducts of Fuel Ethanol Fermentation from Grain, Agriculture
and Agri-Food Canada - Canadian Green Plan Ethanol Program: Starchy Waste Streams Evaluation
Project, May 1996
56
Natural Resources Canada, 1997 Efficiency and Alternative Energy Programs in Canada Directory.
Program may have been discontinued.
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6. Ethanol Lifecycle Analysis for Energy and
Greenhouse Gas Emissions
6.1 Introduction
To assess the total direct and indirect net effects of more ethanol production and use, a lifecycle analysis is
required. The full cycle concept of analyses considers all inputs into the production and use of a fuel. It
combines the fuel production, vehicle manufacture and fuel use in a single analysis. It is also referred to as
the fuel cycle by some authors. The ultimate result is a value that can be used for comparison of different
commodities on the same basis, such as per unit of fuel energy or per kilometre driven. Greenhouse gas
emissions over the full cycle include all significant sources of these emissions from production of the
energy source (i.e. crude oil, biomass, natural gas, etc.), through fuel processing, distribution, and onward
to combustion in a motor vehicle for motive power. A life cycle analysis should also include greenhouse
gas emissions from vehicle material and assembly as these emissions are affected by the choice of
alternative fuel/vehicle technology. Wide ranges of emission sources are involved in the production and
distribution of fuels, and these vary depending on the type of fuel.
Figure 4: Full Cycle Including Fuel and Vehicle Cycles
The two fuel pathways of primary interest here are petroleum to gasoline and grain to ethanol. The ethanol
is subsequently blended with gasoline in various proportions. The final comparison is gasoline to ethanol
blended gasoline.
Figure 5: Grain to Ethanol and Petroleum to Gasoline Fuel
Cycles
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6.1.1 Full Cycle and Energy Balance Analysis Methods
Two spreadsheet models are available from the United States to facilitate full cycle emission analysis; one
developed by Delucchi (1991,1993, 1998), the other by Wang (1996). The work of Delucchi in the 19871993 period resulted in the development of a spreadsheet model based on Lotus software for AppleTM
computers, which contained capabilities for predicting emissions of greenhouse gases and criteria nongreenhouse gases from most of the alternative fuels of potential interest in this study. The model is
comprehensive in scope and level of detail, and, hence, requires input of extensive information on the
energy usage for fuel production, distribution and related fuel cycle sources, as well as factors for
emissions of non-greenhouse gases from these sources and motor vehicles. Using the results from the
Delucchi model and a simplified approach based on the application of energy conversion efficiencies and
relative emission factors for pollutants from the full cycle sources, Wang (1996, 1999) developed a userfriendlier spreadsheet model for the US DOE in ExcelTM. This model is available on the Internet at
www.transportation.anl.gov/ttrdc/greet.
Delucchi has updated his model since 1993, as described in Delucchi and Lipman (1996) and a report by
Energy and Environmental Analysis Inc. (1999). This work has focused primarily on updating the earlier
model to include recent data for motor fuel production, processing, distribution and use in the United
States, and incorporation of improved algorithms for predicting non-greenhouse gas emissions from motor
vehicles based on the U.S. EPA Mobile 5 model. A partial Canadianization of the Delucchi model was
completed by Delucchi (1998) for Natural Resources Canada (NRCan) in late 1998 through to March,
1999, drawing from information on the production and distribution of conventional and alternative fuels
that was provided by NRCan and Statistics Canada and some other Canadian government agencies.
The partially Canadianized version of the full cycle model prepared by Delucchi in 1998 was further
developed by Levelton and (S&T)2 for NRCan. This Canadianized version is used as the starting point for
this study. It is considered to yield the most rigorous life cycle analysis of both greenhouse and nongreenhouse gases from alternative motor fuels, and had the advantage of incorporating functional
capabilities and data for analysis of Canada specifically. The parameters used in the model for predicting
emissions from gasoline and ethanol production and use were further refined to accurately simulate full
cycle emissions in the study area.
6.1.2 Greenhouse Gases Encompassed in Analysis
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The greenhouse gases included in the calculations for this report are carbon dioxide (CO 2), methane (CH4)
and nitrous oxide (N2O). The emissions have been weighted according to Intergovernmental Panel on
Climate Change (IPCC) guidelines where CO 2 has a weighting factor of 1.0, CH4 is assigned a value of 21.0
and N2O has a weighting factor of 310. These are the 100-year global warming potential (GWP) multipliers
recommended by the IPCC. Throughout the report we will report primarily CO 2 equivalent values. This
will be the weighted sum of the three greenhouse gases. In some areas this will be further broken down to
provide detail on the separate gases.
Other gases and contaminants associated with the production and use of fossil and renewable fuels, such as
carbon monoxide, non-methane organic gases, oxides of nitrogen and particulates, also have the potential to
influence climate change, either directly or indirectly. The global warming potential of these other gases
has not been considered in this study, to be consistent with the approach being used by most other studies
in this area.
6.1.3 Model Used to Calculate Full Cycle Emissions
The Delucchi model, as used in this study, is capable of estimating fuel cycle emissions of the primary
greenhouse gases, carbon dioxide, methane, nitrous oxide, and the criteria pollutants, nitrogen oxides,
carbon monoxide, sulphur oxides, non-methane organic compounds (also known as VOC’s) and exhaust
particulate matter. The model also is capable of analyzing the emissions from gasoline and alternative
fuelled internal combustion engines for both light-duty and heavy-duty vehicles, and for light duty battery
powered electric vehicles.
The full cycle model predicts emissions for past, present and future years using historical data or
correlations for changes in energy and process parameters with time that are stored in the model. The
model is thus capable of analyzing what is likely to happen in future years as technologies develop. The
model allows for segmentation of the predicted emissions into characteristic steps in the production,
refining, distribution and use of fuels and the production of motor vehicles. The fuel cycle segments
considered in the model are as follows:







Vehicle Operation
Emissions associated with the use of the fuel in the vehicle. Includes all three greenhouse gases.
Fuel Dispensing at the Retail Level
Emissions associated with the transfer of the fuel at a service station from storage into the
vehicles. Includes electricity for pumping, fugitive emissions and spills.
Fuel Storage and Distribution at all Stages
Emissions associated with storage and handling of fuel products at terminals, bulk plants and
service stations. Includes storage emissions, electricity for pumping, space heating and lighting.
Fuel Production (as in production from raw materials)
Direct and indirect emissions associated with conversion of the feed stock into a saleable fuel
product. Includes process emissions, combustion emissions for process heat/steam, electricity
generation, fugitive emissions and emissions from the life cycle of chemicals used for ethanol fuel
cycles.
Feedstock Transport
Direct and indirect emissions from transport of feedstock, including pumping, compression, leaks,
fugitive emissions, and transportation from point of origin to the fuel refining plant. Import/export,
transport distances and the modes of transport are considered.
Feedstock Production and Recovery
Direct and indirect emissions from recovery and processing of the raw feedstock, including
fugitive emissions from storage, handling, upstream processing prior to transmission, and mining.
Fertilizer Manufacture
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
Direct and indirect life cycle emissions from fertilizers, and pesticides used for feedstock
production, including raw material recovery, transport and manufacturing of chemicals.
Land use changes and cultivation associated with biomass derived fuels
Emissions associated with the change in the land use in cultivation of crops, including N 2O from
application of fertilizer, changes in soil carbon and biomass, methane emissions from soil and
energy used for land cultivation.
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




Carbon in Fuel from Air
Carbon dioxide emissions credit arising from use of a renewable carbon source that obtains carbon
from the air.
Leaks and flaring of greenhouse gases associated with production of oil and gas
Fugitive hydrocarbon emissions and flaring emissions associated with oil and gas production.
Emissions displaced by co-products of alternative fuels
Emissions displaced by distillers grains, a co-product of ethanol production, equal to emissions
from animal feed products displaced from other sources. Other co-products are calculated on the
same displacement method.
Vehicle assembly and transport
Emissions associated with the manufacture and transport of the vehicle to the point of sale,
amortized over the life of the vehicle.
Materials used in the vehicles
Emissions from the manufacture of the materials used to manufacture the vehicle, amortized over
the life of the vehicle.
Levelton and (S&T)2 (1999b) conducted a thorough review of the assumptions and characteristic
parameters used in the original model to predict fuel cycle emissions from the fuels chosen in this study for
detailed analysis. These assumptions and parameters were compared to information available to Levelton
and (S&T)2 from in-house information, direct contact with energy and vehicle companies, published
literature and other sources.
For this study further refinement of the model was undertaken to properly model the Alberta emissions.
The primary requirement was to be able to assign Alberta electricity indirect emissions to those activities
happening in Alberta and the indirect emissions from electricity from Canada for those activities happening
outside the Province. The ethanol production process was changed from corn to wheat and an in-depth
review of land-use changes, soil sinks and emission, and co-product credits was made to better model the
Alberta situation.
Emissions and energy requirements for natural gas were adjusted to Alberta by reducing energy
requirements for transmission by 80% compared to the national values in the Canadianized model. The
basic emission data on natural gas for the Canadianized model was derived from a report by Radian (1997)
for the Canadian Gas Association to improve the model’s estimates of greenhouse gas emissions from
leakage and energy use from processing, transmission and distribution in Canada. Emissions associated
with production and processing and with distribution for Alberta were not changed.
Fuel economy in units of miles per US gallon is the principal input variable available to the user of the
model for case studies and is used within the model as the energy demand that must be satisfied by the fuel
production, refining and other segments of the fuel cycle. Fuel economy values are input separately for city
and highway travel and for light-duty and heavy-duty vehicles. The model inputs are all in US units. Most
of the full cycle energy and greenhouse analyses found in the literature use US units. We have presented
results in US units and in most cases present input data in metric and US units.
6.2 Greenhouse Gas Emissions
The baseline information on vehicle fuel use that has been used in the modelling are shown in the table
below. The key model inputs are vehicle fuel economy and total vehicle kilometres travelled over the life
of the vehicle. The annual kilometre accumulation rates are the same as used by Levelton (1999b) and were
originally provided by NRCan. The N2O emission factors used are the same as are currently being used by
NRCan and Environment Canada. These values have been reduced from those used to determine the 1995
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Canadian inventory of emissions (Jaques, 1997). The reductions were based on the most recent data from
the US EPA.
Table 74: Baseline Vehicle Fuel Economy for Modelling Use
New Vehicle Test Values
2000
2010
2020
Passenger Cars*
Gasoline Vehicles
City
L/100km
US mpg
Highway
L/100km
US mpg
Combined
L/100km
US mpg
2000
On-Road Values
2010
2020
9.60
24.39
6.40
9.00
26.02
6.00
8.30
28.21
5.60
10.70
21.95
8.20
10.00
23.42
7.70
9.3
25.39
7.1
36.59
8.20
39.04
7.70
42.32
7.10
28.54
9.60
30.45
9.00
33.01
8.3
28.70
30.61
33.19
24.50
26.14
28.34
6.2.1 Gasoline
There are four refineries in Alberta producing road transportation fuels. The refineries are owned by
Imperial Oil, Petro-Canada, Shell and Parkland Industries. The companies were contacted to determine the
types of crude oil processed at each facility such that a weighted average could be determined for
modelling purposes.
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Table 75: Crude Oil Slate Modeled
Crude Oil Type
Conventional
Heavy
Bitumen
Synthetic
Percent of Input
55.5%
0%
4.8%
39.7%
It is assumed that all of the crude oil is transported by pipeline an average of 150 miles and that 10% of the
oil is transported by truck an average of 20 miles.
The greenhouse gas emissions associated with the production of the crude oil are derived from the
Foundation Paper for the Upstream Petroleum Sector presented to the Industry Table of the National
Climate Change Process (CAPP, 1998). The CAPP data was disaggregated by crude type and then
combined in the same proportions as the crude used for the four Alberta refineries. The model was then
calibrated to this data. The Alberta crude oil slate has a higher portion of synthetic crude oil than is used
nationally. This crude oil requires more energy for production and produces more greenhouse gases than
conventional crude oil. This produces higher greenhouse gas emissions than have been reported for Ontario
(Levelton, 1999) and nationally (Levelton, 1999b).
Table 76: Comparison of Greenhouse Gas Emissions
from Three Studies
Units
Feedstock transmission
Feedstock recovery
Gas Leaks and Flares
Total
Alberta
Ontario
National
Gram CO2 eq/million BTU
Gram CO2 eq/million BTU
Gram CO2 eq/million BTU
139
12,726
277
371
8,219
1,924
204
5,848
3,081
13,142
10,510
9,133
The differences in feedstock transmission are driven by distance. The differences in feedstock recovery and
gas leaks and flare is a function of the type of crude oil. Heavy oil has a high level of methane emissions
according to the CAPP data and those emissions combined with methane’s GWP of 21 contribute to the gas
leaks and flares values. With no heavy oil use reported by the Alberta refiners that value is low for Alberta.
Several of the producers of synthetic crude oil have announced goals of reducing greenhouse gas emissions
per unit of production in the future. They will accomplish this through improvements in energy efficiency,
reductions in fugitive emissions, and in some cases through changes in product specifications. The later is
not necessarily a true reduction since it may be transferring the use of energy from the upgrader to the
refiner. The production of synthetic crude oil is also expected to increase over time with several expansions
underway or announced. With the projected reduction in conventional light crude oil it is likely that the use
of synthetic crude oil will increase in Alberta over the next ten years. The issue then becomes will
emissions from synthetic crude oil be as low as the emissions from the conventional oil it replaces? In the
table below the current and projected emissions from the synthetic oil plants are shown (Syncrude, Suncor,
Shell, 1999) and compared to the data modeled. The year 2000 data modeled was derived from CAPP
average synthetic crude oil data. The year 2008 value will be used for the 2005 scenarios modeled. It is an
estimate of the average future emission rate.
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Table 77: Greenhouse Gas Emissions from Synthetic Crude
Production
Syncrude
Suncor
Shell
Data modeled
Units
gms CO2eq/million BTU
gms CO2eq/million BTU
gms CO2eq/million BTU
gms CO2eq/million BTU
1998
2000
2002
2008
21,412
16,800
22,136
20,710
16,600
11,500 to 15,700
19,800
14,000
13,890
For the year 2005 projections the emissions from a crude oil slate with 55% synthetic, 5% bitumen, and
40% conventional oil essentially reversing the proportions of conventional and synthetic oil in the slate
were determined. It was assumed that the synthetic emissions decreased by 30%. In this potential future
case the greenhouse gas emissions from the production of the oil were 19% lower than for the case
calculated for the year 2000.
Three of the four refineries are large complex producing a variety of products. It is assumed that the energy
used in the refineries is typical of that reported by the industry in the Petroleum Downstream Sector
Industry Foundation Paper (Purvin & Gertz, 1998). That paper provides the total energy used as well as the
type of fuel providing the energy. That data is used as inputs to the model. The energy has been allocated
between products on the same proportional basis as the original Delucchi model.
The refining energy used is less than Delucchi reports for the United States refineries. The reasons for this
include the lower proportion of gasoline produced by Canadian refineries requiring less complexity in the
refinery and the use of MMT as an octane enhancer. The refining energy use data is for the year 1996.
Future years have been calculated based on annual improvements of 1% per year until the year 2001 and
0.5% per year after that until the year 2010.
Low sulphur gasoline will be available in 2005 and the additional energy required to remove the sulphur
and replace the octane lost in the desulphurization process has been taken from the Downstream
Foundation paper. Depending on the technology chosen by the individual refiners that may lead to an over
estimation of greenhouse gases emitted and energy consumed after the year 2005 as the foundation paper
represents a worst case.
In the table below the greenhouse gas emissions for gasoline for Alberta are presented for 2000 and for
2005. For 2005 the additional energy required to make low sulphur gasoline is considered along with a
crude slate with more synthetic crude. The lower energy requirements for the synthetic crude are factored
in. The annual improvements in refinery energy consumption are accounted for. This table presents the data
for the fuel cycle up to the dispenser nozzle on the basis of grams CO2 eq per million BTU.
Table 78: CO2 Equivalent Emissions for Gasoline and Low
Sulphur Gasoline for 2000
Source Category
Year
Feedstock
Specification
Units
Fuel Dispensing
Conventional Gasoline
2000
Oil
300 ppm S
Low Sulphur Gasoline
2005
Oil
30 ppm S
Grams CO2 Equivalent/Million
BTU Delivered
Grams CO2 Equivalent/Million
BTU Delivered
597
585
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Fuel Distribution and Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Sub Total
Percent Change
918
14,887
139
12,697
0
0
277
0
29,514
856
17,136
126
10,223
0
0
271
0
29,198
-1.1
The advancements in synthetic crude oil production are mostly offset by the increase in energy required to
make low sulphur gasoline.
In the table below, the data is presented for the complete life cycle on the basis on grams CO 2 eq. per mile
travelled. This takes into account the exhaust emissions from the vehicles that contribute to GHG, CO 2,
methane and N2O. For the low sulphur gasoline case the impact of sulphur on exhaust emissions is also
considered. The most significant reduction is a 60% drop in N 2O emissions when sulphur is lowered to 30
ppm. Other assumptions are that carbon monoxide is reduced 20%, NOx by 15% and VOCs by 30%. The
mechanism for the reductions is less catalyst fouling from the sulphur. Vehicle fuel economy has been kept
constant between 2000 and 2005 so that just the impact of upstream changes can be compared.
Table 79: CO2 Equivalent Emissions for Gasoline and Low
Sulphur Gasoline
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Gas leaks and flares
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Gasoline
Low Sulphur Gasoline
Grams CO2 equivalent/mile
Grams CO2 equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
1.4
507.3
364.7
3.0
4.4
87.5
0.6
52.2
1.4
513.8
0.9
5.4
29.5
548.7
0.9
5.5
31.3
544.1
The table above introduces an interesting issue with the model that has been caused by the calibration of
the vehicle exhaust emissions to the Alberta emission factors. Vehicle fleet exhaust emissions in Alberta
are higher than the default values in the model. This means that fuel is being wasted due to incomplete
combustion. More detail on this is presented in a later section. The improved catalyst efficiency with low
sulphur gasoline results in significant quantities of carbon monoxide and to a lesser extent oxidized to
carbon dioxide in the catalytic converter. This accounts for the increase in CO 2 emissions per mile driven
for vehicle operation. This should not impact the overall result if this oxidation takes place in the converter
but if some of the oxidation takes place in the engine then vehicle efficiency will improve which has not
been accounted for in the model.
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Since greenhouse gas emissions for gasoline are projected to remain fairly constant over the next five years
the analyses of ethanol and the other alternative fuels will focus on the year 2000. The lack of significant
change in the emissions from baseline gasoline during the next decade makes the year 2000 applicable over
the decade.
6.2.2 Ethanol
The greenhouse gas emissions for the four scenarios studied are described in the following sections. The
methodology for the treatment of land use changes and emissions displaced by co-products is constant for
each of the scenarios.
Land use changes includes emissions of N2O from the application of nitrogen fertilizers, loss of soil carbon
from cultivation, changes in above and below ground biomass due to the production of the crop and
emissions of methane from the soil. It is recognized that changes in soil carbon and plant biomass are
reversible if changes in soil use occur. Changes that happen in the future are less certain and the model
applies a discount factor to future changes. The discount factor used is 2%. Soil carbon changes are
assumed to occur over a 25 year period and changes in plant biomass happen over a 15 year period. Further
discussion of this topic can be found in Delucchi (1998). The summary of key factors impacting land use
emissions for wheat and barley production are shown in the following table.
Table 80: Emission Factors Impacting Land Use Emissions
Emission Factors
0.0125 g N2O/g N
0.10 g CH4/kg N fertilizer
25.0 g CH4/ ha/year
25
0.0036 kg C/m2
15
2%
0.37 kg C/m2 for CPS wheat. Varies with yield.
None. Land previously used for wheat.
N2O from nitrogen application
Methane emissions from soil
Methane emissions from soil
Years over which soil loss occurs
Rate of soil loss
Years over which biomass changes occurs
Discount rate for carbon loss
Plant biomass carbon (above and below ground)
Acreage displaced
The energy and greenhouse gas emissions credits for the co-products from the ethanol production process
are calculated based on the energy and greenhouse gas emissions from the products that they replace. In the
case of the animal feeds the displaced product is barley. Barley emissions were calculated and shown in an
earlier section. Co-product displacement ratios are determined for the various co-products in the different
scenarios. For gluten the energy use for the ethanol production is calculated based on the incremental
energy requirements and thus the gluten can be removed from the calculations. This methodology in effect
treats gluten in exactly the same manner as the other co-products and is correct as long as the gluten
production does not increase gluten demand. Further discussion of the displacement method of co-products
can be found in Delucchi (1998). The displacement method generally produces a smaller credit than
allocating the emissions and energy use based on mass of products produced or on a market value
allocation. It is a more complex procedure.
In previous analyses (Levelton, 1999,1999b) it has been assumed that a 10% ethanol blends achieves a 1%
better fuel economy on an energy basis or 2.5% less on a volumetric basis. Dynamometer testing has
confirmed this increase in efficiency (Ragazzi, Hochauser). There are a number of reasons to expect higher
energy efficiency with low level ethanol blends. The lower emissions of carbon monoxide and
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hydrocarbons mean more energy from the fuel is released in the engine. In addition there are more moles of
combustion products formed per mole of air for ethanol than for gasoline leading to higher pressures in the
cylinder and finally the ethanol has a higher heat of vapourization than gasoline leading to lower intake
tract losses and a cooler mixture.
This 1% efficiency improvement has been used for this analysis. This may be too low. The cited references
were on vehicles that had lower exhaust emissions than the Alberta fleet average and thus produced less
carbon monoxide and unburned hydrocarbons. Since a portion of the increased efficiency is derived from
more complete combustion, vehicles with higher emissions should get a larger efficiency increase since
more grams of partially burned fuel are completely burned in the presence of extra oxygen. Hochhauser did
report that the older fleet had an even higher efficiency gain with fuel oxygen. Vehicle fleet tests performed
in the 1980’s when emissions were higher usually found no significant change in volumetric fuel economy.
The modelling results do support the case for higher than 1% efficiency as will be shown later.
No allowance for the octane of ethanol has been given since an in-depth study of the Alberta refineries is
beyond the scope of this study. Other studies (Levelton, 1999) have found that including this benefit
changes the greenhouse gas reductions for a 10% blend by 0.1 percentage point.
The changes in exhaust emissions from a 10% blend that were modeled were a 15% reduction for CO and
VOC and a 5% increase in NOx. The CO and VOC values do have a small impact on greenhouse gas
emissions.
None of the scenarios considers the application of manure to provide a portion of the nitrogen fertilizer nor
considers the impact of DG on animal emissions of methane. The projections can thus be considered to be
very conservative. Separate sensitivity cases will study these two issues and the fuel economy issue.
It is important to consider that a blend with 10% ethanol by volume is a blend with 6.5% of the energy in
the fuel being supplied by the ethanol. If the ethanol contributed no greenhouse gases then the reduction in
greenhouse gases would be 6.5% compared to 100% gasoline.
6.2.2.1 Integrated Ethanol Plant Cattle Feedlot
The greenhouse gas emissions from the production of CPS wheat and the conversion to ethanol in an
integrated ethanol plant cattle feedlot are shown and compared to gasoline in the table below. The coproduct credits and ethanol plant inputs are as described in earlier sections.
Table 81: CO2 Equivalent Upstream Emissions for Gasoline and
Ethanol from an Integrated Cattle Feeding Operation
Source Category
Year
Feedstock
Units
Fuel Dispensing
Fuel Distribution and Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Conventional Gasoline
2000
Oil
Grams CO2 Equivalent/Million
BTU Delivered
597
918
14,887
139
12,697
0
108
Ethanol
2000
CPS Wheat
Grams CO2 Equivalent/Million
BTU Delivered
856
1,337
38,424
2,187
6,504
-1,807
CHEMINFO
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
CO2 Emissions from
Combustion in Use
Total
Percent Change
0
277
0
29,514
63,159
92,673
12,824
0
-9,376
50,950
0
(renewable)
50,950
-45.0
The emissions from combustion only include CO2 since the methane and nitrous oxide emissions are
dependent on engine technology. This data is shown for comparison purpose since in the case of ethanol
the CO2 emissions are not counted since they came from biomass. This is in accordance with the IPCC
guidelines (IPCC, 1999).
The use of this ethanol in a 10% blend with gasoline in the average fleet vehicles can be compared to
gasoline on a per mile driven basis.
Table 82: CO2 Equivalent Vehicle Emissions for Gasoline and
Ethanol from an Integrated Cattle Feeding Operation
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Land Use and Cultivation
Gas leaks and flares
C in end use fuel from CO2 in air
Emissions displaced by coproducts
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Gasoline
Grams CO2 equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
0
1.4
0
0
507.3
5.5
31.3
544.1
Ethanol
Grams CO2 equivalent/mile
357.6
3.1
4.8
83.5
1.4
66.5
-0.6
1.3
-23.9
-3.3
490.4
-3.3
5.5
31.2
527.0
-3.1
On a full cycle basis ethanol from an integrated ethanol plant cattle feedlot will reduce greenhouse gas
emissions by at least 3.1% for a 10% ethanol blend with gasoline.
This table provides evidence that the assumed fuel economy improvement is too low. The CO 2 emissions
are higher for the ethanol blend even though ethanol produces less CO 2 per million BTU of energy than
gasoline and a 1% efficiency gain was used. The high emissions of carbon monoxide modeled along with
the reduction in carbon monoxide emissions from the ethanol increased the amount of CO 2 produced. The
complete oxidation of the carbon monoxide would release more energy than has been accounted for with
the 1% efficiency gain. This issue will be explored further in the sensitivity section.
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6.2.2.2 Conventional Dry Milling Ethanol Plant
In a conventional dry milling ethanol plant there is more energy consumed in the process due to the need to
dry the co-product and there is energy required distributing the product to the end user. Offsetting this, the
co-product can be better utilized by feeding less of it to each animal or by incorporating it into dairy cow
rations. The upstream emission results and the full cycle emissions are shown in tables below.
Table 83: CO2 Equivalent Upstream Emissions for Gasoline and
Ethanol from a Conventional Dry Mill Ethanol Plant
Source Category
Year
Feedstock
Units
Fuel Dispensing
Fuel Distribution and Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
CO2 Emissions from
Combustion
Total
Percent Change
Conventional Gasoline
2000
Oil
Grams CO2
Equivalent/Million BTU
Delivered
597
918
14,887
139
12,697
0
0
277
Ethanol
2000
CPS Wheat
Grams CO2
Equivalent/Million BTU
Delivered
856
1,337
48,086
2,187
6,504
-1,807
12,824
0
0
29,514
63,159
-17,789
52,498
0
92,673
52,498
-43.3
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Table 84: CO2 Equivalent Vehicle Emissions for Gasoline and
Ethanol from a Conventional Dry Mill Ethanol Plant
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Land Use and Cultivation
Gas leaks and flares
C in end use fuel from CO2 in air
Emissions displaced by coproducts
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Gasoline
Grams CO2 equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
0
1.4
0
0
507.3
5.5
31.3
544.1
Ethanol
Grams CO2 equivalent/mile
357.6
3.1
4.8
86.9
1.4
66.5
-0.6
1.3
-23.9
-6.2
490.9
-3.2
5.5
31.2
527.6
-3.0
This scenario produces slightly higher greenhouse gas emissions than the integrated feedlot concept.
6.2.2.3 Gluten and Ethanol Plant
The reductions in greenhouse gas emissions from ethanol from a combined ethanol plant gluten operation
are greater than the dry milling operations. This is due to the synergies between the two operations. The
ethanol plant does not have to mill the grain or dry the co-products since these activities already happen
with a gluten plant. The greenhouse emissions for the gluten ethanol plant complex are shown in the table
below. The results for both feedstocks are compared to gasoline.
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CHEMINFO
Table 85: CO2 Equivalent Upstream Emissions for Gasoline and
Ethanol from a Combined Ethanol and Gluten Operation
Source Category
Year
Feedstock
Units
Fuel Dispensing
Fuel Distribution and
Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
CO2 Emissions from
Combustion
Total
Percent Change
Conventional Gasoline
2000
Oil
Ethanol
2000
HRS Wheat
Ethanol
2000
CPS Wheat
Grams CO2
Equivalent/Million BTU
Delivered
Grams CO2
Equivalent/Million BTU
Delivered
Grams CO2
Equivalent/Million BTU
Delivered
597
856
856
918
1,337
1,337
14,887
139
12,697
0
0
277
0
29,514
20,157
2,258
8,953
-351
16,219
0
-5,690
43,740
18,109
2,205
6,556
-1,822
12,927
0
-5,457
34,711
63,159
0
0
92,673
43,740
-52.8
34,711
-62.5
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CHEMINFO
The results can also be presented for the full cycle on a grams per mile driven basis, as shown in the table
below.
Table 86: CO2 Equivalent Full Cycle Emissions for Gasoline and
Ethanol from a Combined Ethanol and Gluten Operation
Gasoline
Units
Feedstock
Vehicle operation
Fuel Dispensing
Fuel storage and
distribution
Fuel Production
Feedstock transport
Feedstock production
Land Use and Cultivation
Gas leaks and flares
C in end use fuel from
CO2 in air
Emissions displaced by
co-products
Sub total (fuel cycle)
% Changes
(fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Grams CO2 equivalent/mile
Ethanol
Grams CO2 equivalent/mile
Ethanol
Grams CO2 equivalent/mile
Oil
HRS Wheat
CPS Wheat
356.6
3.0
4.7
357.6
3.1
4.8
357.6
3.1
4.8
76.0
0.7
64.8
0
1.4
0
77.0
1.5
68.6
-0.1
1.3
-23.9
76.3
1.4
66.5
-0.6
1.3
-23.9
0
-2.0
-1.9
507.3
487.8
-3.8
484.6
-4.5
5.5
31.3
544.1
5.5
31.3
524.5
-3.6
5.5
31.2
521.3
-4.2
6.2.2.4 Impact of Manure, Reduced Animal Methane Emissions and Vehicle
Emissions
It has been shown that the use of manure to supply some of the nitrogen requirements for crop growth can
reduce the energy requirements and greenhouse gas emissions from the production of wheat. It is also
likely that the use of DG will reduce the emissions of methane from the animal eating it. A case is
considered where these two situations are quantified to determine the potential full cycle impact. It is
assumed that manure supplies 35% of the nitrogen requirements on 50% of the farms. The overall impact is
to increase diesel fuel consumption by 1.87 litres per acre per year and to reduce the energy required to
make the nitrogen fertilizer by 17.5%. The co-products credit has been increased by 4,200 gms/million
BTU. The scenario is applied to the integrated feedlot ethanol plant.
Table 87: Impact of Manure Use and Methane Credit from DG
Source Category
Year
Feedstock
Conventional Gasoline
2000
Oil
Ethanol
2000
CPS Wheat
113
Ethanol
2000
CPS Wheat, Manure,
CHEMINFO
and Methane Credit
Units
Grams CO2 Equivalent/Million
BTU Delivered
Grams CO2 Equivalent/Million
BTU Delivered
Grams CO2 Equivalent/Million
BTU Delivered
597
856
1,337
856
1,337
14,887
139
12,697
0
0
277
0
29,514
63,159
38,424
2,187
6,504
-1,807
12,824
0
-9,376
50,950
0
38,424
2187
7456
-1,807
11,465
0
-13,573
46,346
0
92,673
50,950
-45.0
46,346
-50.0
Fuel Dispensing
Fuel Distribution and
Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
CO2 Emissions from
Combustion
Total
Percent Change
918
The manure impact is relatively small in this case. The impact would be larger if more manure was spread
over a smaller percentage of the land. The inclusion of the methane benefit increases the co-product credits
by 45%.
To determine the impact of vehicle emissions and the efficiency increase improvement from the use of
ethanol. The feedlot full cycle case was run with the default vehicle emission rates. This has an appropriate
balance between emissions and fuel economy. Carbon monoxide emissions were reduced from 20.0 g/mile
to 10.9 g/mile in 2000. The VOC emissions were reduced from 2.34 g/mile to 1.09 g/mile. There are no
changes in the emissions for the upstream part of the cycle.
Table 88: Impact of Lower Exhaust Emissions of Carbon
Monoxide and Hydrocarbons on Full Cycle Emissions
Vehicle Exhaust Emission
Assumption
Ethanol Plant Concept
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Land Use and Cultivation
Gas leaks and flares
C in end use fuel from CO2 in air
Emissions displaced by coproducts
Sub total (fuel cycle)
Gasoline
Calibrated to
Alberta Fleet
Ethanol
Calibrated to
Alberta Fleet
Integrated
Feedlot
Gasoline
Model
Defaults
Ethanol
Model
Defaults
Integrated
Feedlot
Grams CO2
equivalent/mile
Grams CO2
equivalent/mile
Grams CO2
equivalent/mile
Grams CO2
equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
0
1.4
0
0
357.6
3.1
4.8
83.5
1.4
66.5
-0.6
1.3
-23.9
-3.3
370.9
3.0
4.7
76.0
0.7
64.8
0
1.4
0
0
369.4
3.1
4.8
83.5
1.4
66.5
-0.6
1.3
-23.9
-3.3
507.3
490.4
521.6
502.2
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CHEMINFO
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
-3.3
5.5
31.2
527.0
-3.1
5.5
31.3
544.1
-3.7
5.5
31.2
538.9
-3.5
5.5
31.3
558.4
The low emission case has a higher percentage reduction in greenhouse gas emissions. The CO 2 from the
vehicle operation is lower than the gasoline case, which is now consistent with the efficiency improvement
modeled. GHG emissions are higher because the vehicle fuel economy has not been adjusted and more of
the carbon in the fuel has been oxidized to CO2. The model assumptions for the low emission case are more
internally consistent and the 3.5% reduction is more representative of what would happen in the real world.
There are no external references for fuel efficiency improvements for high emitters which is why the 1%
improvement has been chosen for the base cases even though it is recognized that it creates internal
inconsistencies in the model. The actual Alberta emission rates are important for the consideration of other
environmental impacts.
6.2.2.5 Summary of Environmental Emissions Effects
The results of the four model plants and the sensitivity cases are shown the table below. Also shown are the
results for gasoline and the results for gasoline and corn ethanol for Ontario. The GHG emissions for
gasoline in Alberta is significantly higher than similar emissions in Ontario due to the different crude oil
slates used in refining (a higher percentage of synthetic crude oil in Alberta) and the higher carbon intensity
of electricity production in Alberta compared to Ontario.
Table 89: Summary and Comparison
Feedlot
Dry Mill
CPS Gluten
HRS Gluten
Ontario
Corn
92,673
83,359
50,950
52,498
34,711
43,740
45,917
544.1
510.3
45.0%
527.0
3.1%
43.3%
527.6
3.0%
62.5%
521.3
4.2%
52.8%
524.5
3.6%
44.9%
490.6
3.9%
3.5%
3.4%
4.6%
4.0%
3.9%
Alberta
gms CO2 eq/million
BTU including CO2
from combustion
% reduction
gms CO2 eq/mile
% reduction, Alberta
exhaust emission rates
% reduction, model
default exhaust
emission rates
Ethanol
Wheat
Ontario
Gasoline
6.2.3 Alternative Fuels
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CHEMINFO
6.2.3.1 Natural gas
It is assumed that natural gas is sold and used in vehicles as a pure compressed gas at 3000 psi. The
compression is provided by an electric motor. It has been assumed that the natural gas vehicles have the
same engine efficiency as gasoline vehicles. The extra weight required for the natural gas tanks has been
factored into the final energy efficiency used in the model. Natural gas vehicles have the potential for
higher efficiencies if full advantage is taken of the 130 octane rating of the fuel. With the small production
runs for natural gas vehicles currently it is not economically feasible to take full advantage of the octane.
Table 90: CO2 Equivalent Emissions for Natural Gas and
Gasoline
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Gas leaks and flares
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Gasoline
Natural Gas
Grams CO2 equivalent/mile
Grams CO2 equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
1.4
507.3
309.7
34.6
3.4
7.5
0.0
9.0
21.5
385.6
-24.0
5.7
32.0
423.4
-22.2
5.5
31.3
544.1
Natural gas has a lower carbon content per unit of energy released and thus produces lower greenhouse gas
emissions per mile driven. The emissions between the oil or gas field and the vehicle are also lower for
natural gas. The extra vehicle weight for the fuel tanks can be seen in the higher emissions from materials
in vehicles.
Emissions from natural gas vehicles could be improved by taking advantage of the fuels high octane rating.
A 10% improvement in vehicle fuel efficiency would increase the total reduction in greenhouse gas
emissions to 27.9%.
6.2.3.2 Propane
Propane for vehicle fuels can come from gas plants and from refineries. For Canada the split is 86% gas
plants and 14% refineries. Alberta has a larger proportion of the Canada’s gas plants than it does refineries.
The model inputs set the Alberta proportions to 95% gas plants and 5% refineries based on 90% of the gas
plants being in Alberta and 30% of the refining capacity located in Alberta. Emissions from the refineries
are higher than from the gas plants.
The propane vehicles are assumed to have the same engine efficiency as gasoline. Like natural gas the
production runs are too small to be able to take advantage of propane’s higher octane rating.
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Table 91: CO2 Equivalent Emissions for Propane and Gasoline
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Gas leaks and flares
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
Gasoline
Propane
(Grams CO2 equivalent/mile)
(Grams CO2 equivalent/mile)
356.6
3.0
4.7
76.0
0.7
64.8
1.4
507.3
327.7
3.0
10.8
9.9
0.0
12.4
12.3
376.2
-25.8
5.6
31.4
413.2
-24.1
5.5
31.3
544.1
6.2.3.3 Methanol
Methanol’s use as an alternative fuel is likely to be either as a fuel for fuel cells or as a blend with diesel.
The greenhouse gas emissions for methanol production are based on the average gas conversion efficiency
of North American methanol plants (100 scf/USG methanol). It is assumed that the methanol is produced
and distributed by truck in Alberta. The greenhouse gas emissions are presented on the basis of grams per
million BTU of output followed by discussion of the implications for the two market applications.
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Table 92: CO2 Equivalent Emissions for Gasoline, Diesel and
Methanol for 2000
Source Category
Year
Feedstock
Units
Conventional Gasoline
2000
Oil
Diesel Fuel
2000
Oil
Methanol
2000
Natural Gas
Grams CO2 Equivalent/Million
BTU Delivered
Grams CO2 Equivalent/Million
BTU Delivered
Grams CO2 Equivalent/Million
BTU Delivered
597
558
765
1,155
8,838
143
13,051
0
0
284
0
23,639
22,917
527
5,142
0
0
3,938
0
35,863
+21.5%
(vs. gasoline)
Fuel Dispensing
Fuel Distribution and
Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
Percent Change
918
14,887
139
12,697
0
0
277
0
29,514
1,937
Greenhouse gas emissions for the production of methanol are higher than for gasoline and diesel fuel
production. The lower carbon content of methanol offsets some of this when it is consumed but reductions
in greenhouse gas emissions will only be possible with an increase in engine efficiency. The blends of
methanol and diesel will not result in an efficiency increase so while that fuel will reduce particulate
emissions and NOx it will not reduce greenhouse gas emissions. The situation with fuel cells is not as clear.
Fuel cell vehicles do offer an increase in efficiency because they are really electric vehicles and offer a
better load cycle than the internal combustion engine. The question is how much of an increase and how
quickly can they be developed to achieve this higher efficiency. Very little data has been released on the
performance of the few fuel cell vehicles currently in existence. In the future it is likely that fuel cell
vehicles may achieve twice the efficiency of internal combustion engines when operated on hydrogen and
about 1.6 times when operated on methanol. The case modeled is where current fuel cell efficiency on
methanol is 25% higher than the internal combustion engine.
Table 93: CO2 Equivalent Emissions for a Methanol Fuel Cell
Vehicle and Gasoline.
Units
Vehicle operation
Fuel Dispensing
Fuel storage and distribution
Fuel Production
Feedstock transport
Feedstock production
Gas leaks and flares
Sub total (fuel cycle)
Gasoline
Methanol FCV
Grams CO2 equivalent/mile
Grams CO2 equivalent/mile
356.6
3.0
4.7
76.0
0.7
64.8
1.4
507.3
262.5
4.7
7.9
94.0
2.2
21.1
17.2
409.6
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% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
5.5
31.3
544.1
-19.3
5.9
33.9
449.8
-17.3
The methanol fuelled fuel cell vehicle results in a reduction in greenhouse gas emissions based on the
assumptions made. There is room for further improvement in this reduction as fuel cell technology
improves. If fuel cell use becomes widespread and creates demand for new methanol plants, the greenhouse
gas emissions from the new efficient plants will also be lower.
6.2.3.4 Biodiesel
The greenhouse gas emissions for biodiesel has been modelled based on the use of canola grown in
Western Canada as the feedstock. The canola yield is 25 Bu/acre, nitrogen and phosphorus is applied as
fertilizer at 50 lb./acre N and 6.5 lb./acre P. The energy requirements for field work and the energy used in
the biodiesel plant is the same as modeled by Delucchi. With biodiesel production there is actually more
mass in the co-product meal than there is with the biodiesel. As a result the co-product credits are very
high. The methodology developed by Delucchi for calculating the co-product credits has been followed.
The meal replaces barley in animal feed rations. Corrections for mass of co-product and protein content in
the co-product have been made to adjust the model from soy oil to canola oil. The displacement factors are
not based on animal feed trials but on protein and energy displacement calculations. They may
underestimate actual displacement ratios.
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Table 94: CO2 Equivalent Emissions for Diesel, Biodiesel for
2000
Source Category
Year
Feedstock
Units
Diesel Fuel
2000
Oil
Biodiesel
2000
Canola
Grams CO2 Equivalent/Million BTU
Delivered
Grams CO2 Equivalent/Million BTU
Delivered
558
765
8,838
143
13,051
0
0
284
0
23,639
612
1,007
48,528
1,321
18,105
1,789
13,179
0
-45,746
38,795
Fuel Dispensing
Fuel Distribution and Storage
Fuel Production
Feedstock Transmission
Feedstock Recovery
Land Use Changes
Fertilizer Manufacture
Gas Leaks and Flares
Emissions displaced
Total
The greenhouse gas emissions of diesel, a 20% biodiesel blend and 100% biodiesel in a heavy-duty engine
are shown below.
Table 95: CO2 Equivalent Emissions for Diesel and Biodiesel in a
Heavy-Duty Truck
Diesel
Units
Vehicle operation
Fuel Dispensing
Fuel storage, distribution
Fuel Production
Feedstock transport
Feedstock production
Land use and cultivation
Gas leaks and flares
C in end use fuel from air
Emissions displaced by coproducts
Sub total (fuel cycle)
% Changes (fuel cycle)
Vehicle assembly
Materials in vehicles
Grand total
% Change
20% Biodiesel
100% Biodiesel
Grams CO2 equivalent/mile
Grams CO2 equivalent/mile
Grams CO2 equivalent/mile
1,715.4
13.1
18.0
207.9
3.4
307.0
0
6.7
0
0
1,715.9
13.4
19.1
388.0
8.7
389.7
8.4
5.4
-323.2
-207.5
1,718.0
14.4
23.7
1,141.7
31.1
736.0
42.1
0
-1,676.1
-1,076.2
2271.5
2,017.6
-11.2
14.8
80.6
2,113.0
-10.7
954.7
-58.0
14.8
83.3
1,052.8
-55.5
14.8
79.9
2366.1
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6.3 Energy Inputs and Outputs
The Delucchi model calculates greenhouse gas emissions from emission factors based on energy and
material inputs. The energy balances are calculated for most of the alternative fuels as part of the
greenhouse calculations. For alternative fuels that use the same feedstock for conversion to the fuel and the
energy to the conversion plant the model can overestimate the energy inputs. Of the fuels considered here
only methanol uses the same feedstock for energy and production. The energy balance as calculated by the
model for methanol is reasonable.
For most fuels greenhouse gas emissions are dominated by the use of energy used to produce them and the
release of the carbon in the fuel when it is burned. There should therefore be a correlation between
greenhouse gas reductions offered by alternative fuels and the energy balances of those fuels. The
exceptions to this are fuels made from renewable resources. By IPCC convention the carbon released from
these fuels is not counted in a country’s greenhouse gas emissions inventory since it is considered to have
come from the air in the production of the resource. Methane and nitrous oxide emissions from these
sources are counted. The other difference with renewable fuels is the use of nitrogen fertilizers and the
conversion of a portion of the nitrogen directly to nitrous oxide. For these renewable fuels there is therefore
not a correlation between greenhouse gas reductions and energy balances.
6.3.1 Gasoline
The energy balance for gasoline production is calculated based on the energy inputs in the model for all
stages except the production of crude oil. For that step, for countries other than the United States, the model
applies a factor against US emissions. The model as used here has been calibrated to produce the same
greenhouse gas emissions for crude oil production as reported by CAPP. The energy used is calculated
based on the distribution of energy types, e.g., electricity, natural gas, diesel, used in the United States and
the Canadian adjustment factor. The Canadian energy use factors are not available in the formats required
for the model. The potential errors introduced by this approach are considered to be small as most of the
carbon based fuels have similar greenhouse gas emissions per unit of energy. The biggest error would be
introduced from the use of purchased electricity because of the high carbon intensity of electricity
production in Alberta. If the electricity fraction is too high then we have underestimated the energy
consumed in crude oil production. Given the significance of synthetic oil in our crude oil slate and the
nature of that process it is unlikely that the electricity use is overestimated.
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Table 96: Energy Distribution of Energy Used in
Crude Oil Production
Fuel Used
Crude Oil Production
Diesel Fuel
Residual Fuel
Natural Gas
Purchased Electricity
Gasoline
Other
Percent of Total
1.3%
8.9%
1.3%
62.2%
18.7%
1.8%
5.6%
Total
100.0%
The energy consumed in the refining process is based on data from the Downstream Foundation Paper
(Purvin and Gertz). This source provides both the quantity and type of energy supplied. The distribution of
refining energy to the individual products is on the same basis as Delucchi has used.
Table 97: Energy Consumed in the Production of Gasoline and
Diesel Fuel
Units
Fuel Dispensing
Fuel Distribution
Fuel Production
Feedstock Transmission
Feedstock Recovery
Total
Percent
Gasoline
BTU Consumed/Million BTU
Delivered
1,800
5,000
115,700
400
107,600
230,500
23.0
Diesel
BTU Consumed/Million BTU
Delivered
1,800
5,000
67,900
400
110,600
185,700
18.6
6.3.2 Ethanol
The energy consumed in the production of the grain and the conversion of the grain to ethanol are
calculated for each of the ethanol production scenarios discussed. The energy is calculated for each stage of
the process. The energy consumption displaced by the co-products is determined and subtracted from the
ethanol plant energy requirements. Since the E10 blends considered here have a higher energy efficiency
when burned in an engine that gasoline does the energy balances are presented both as energy in versus
energy out and on the basis of apparent energy out. This incorporates the higher energy efficiency from
combustion and is more of a life cycle approach to energy balances. The energy that could be saved in a
refinery from utilizing ethanol’s high octane rating has not been incorporated in the analyses due to the
scope of the project, just as it was not considered for the greenhouse emissions.
6.3.2.1 Integrated Ethanol Plant Cattle Feedlot
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The integrated ethanol plant feedlot complex has the lowest energy inputs of the four scenarios considered
and therefore the best energy balance.
Table 98: Energy Balance for Integrated Ethanol Plant Feedlot
Compared to Gasoline.
Units
Gasoline
BTU per Million BTU Delivered
Ethanol
BTU per Million BTU Delivered
107,600
115,700
6,800
41,300
407,300
12,400
Energy Inputs
Feedstock Recovery
Fuel Production
Fuel Distribution, Storage, and
Dispensing
Feedstock Transmission
Fertilizer
Total Inputs
Co-Product Credits
400
0
230,500
14,500
170,000
645,500
-96,600
230,500
548,900
Net Inputs
1,000,000
1,000,000
Energy Output
Effective Energy Output
1,141,600*
769,500
451,100
Net Energy
Net Effective Energy
592,700
* Based on the energy content of the blended gasoline, allowing for the better energy specific fuel
consumption of ethanol. The additional effective energy for a 10% ethanol blend is: 0.01*(120,000
BTU/USG/(84,750 BTU/USG*0.10))=141,600 BTU/Million BTU Delivered.
6.3.2.2 Conventional Dry Milling Ethanol Plant
More energy is consumed in a conventional dry mill operation than in the integrated cattle feeding
operation but the DDG has a higher displacement ratio and thus the co-product energy credits are higher.
Table 99: Energy Balance for a Conventional
Dry Mill Ethanol Plant
Units
Gasoline
BTU per Million BTU Delivered
Ethanol
BTU per Million BTU Delivered
107,600
115,700
6,800
41,300
516,400
12,400
400
0
230,500
14,500
170,000
754,600
-188,470
566,130
1,000,000
1,141,600*
Energy Inputs
Feedstock Recovery
Fuel Production
Fuel Distribution, Storage, and
Dispensing
Feedstock Transmission
Fertilizer
Total Inputs
Co-Product Credits
Net Inputs
Energy Output
Effective Energy Output
230,500
1,000,000
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433,870
Net Effective Energy
575,470
* Based on the energy content of the blended gasoline, allowing for the better energy specific fuel
consumption of ethanol. The additional effective energy for a 10% ethanol blend is: 0.01*(120,000
BTU/USG/(84,750 BTU/USG*0.10))=141,600 BTU/Million BTU Delivered.
Net Energy
769,500
As expected the energy balance for this scenario follows the same trend as the greenhouse gas emissions
and is not quite as positive as the integrated ethanol plant feedlot concept. The energy balance is still
positive and more energy is produced than is consumed in manufacturing the ethanol.
6.3.2.3 Gluten and Ethanol Plant
The energy balances or the ethanol gluten plant complex is calculated on the same incremental basis as the
greenhouse gas emissions were. This insures that the gluten co-product is treated by the co-product
displacement method.
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Table 100: Energy Balance for Gluten and Ethanol Plants
Compared to Gasoline
Gasoline
Feedstock
Units
BTU per Million
BTU Delivered
Ethanol
CPS Wheat
BTU per Million
BTU Delivered
Ethanol
HRS Wheat
BTU per Million
BTU Delivered
107,600
115,700
6,800
41,700
199,000
12,400
56,900
232,000
12,400
Energy Inputs
Feedstock Recovery
Fuel Production
Fuel Distribution, Storage, and
Dispensing
Feedstock Transmission
Fertilizer
Total Inputs
Co-Product Credits
400
0
230,500
14,700
15,000
171,300
214,800
439,100
531,100
-61,600
-60,900
230,500
377,500
470,200
Net Inputs
Energy Output
1,000,000
1,000,000
1,000,000
Effective Energy Output
1,141,600*
1,141,600*
769,500
622,500
529,800
Net Energy
Net Effective Energy
764,100
671,400
* Based on the energy content of the blended gasoline, allowing for the better energy specific fuel
consumption of ethanol. The additional effective energy for a 10% ethanol blend is: 0.01*(120,000
BTU/USG/(84,750 BTU/USG*0.10))=141,600 BTU/Million BTU Delivered.
6.3.2.4 Impact of Manure Use
The impact of manure for a portion of the nitrogen fertilizer requirements has a small impact on the energy
balance of the integrated ethanol plant feedlot. There is a 15,800 BTU/million BTU savings on the energy
inputs but the co-product credit drops by 10,500 BTU/million BTU since it is also based on the energy
inputs. The net effect is a 5,300 BTU/million BTU increase in net energy out.
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6.3.2.5 Energy Balance Summary
All four of the ethanol plant scenarios investigated have a positive energy balance.
Table 101: Energy Balance Summary
Gasoline
Concept
Units
Energy inputs
Ratio Energy
Out/Energy In
Ratio
Effective
Energy
Out/Energy In
BTU/Million
BTU Output
230,500
4.25
Ethanol
Integrated
BTU/Million
BTU Output
548,900
1.82
Ethanol
Dry Mill
BTU/Million
BTU Output
566,130
1.77
Ethanol
HRS Gluten
BTU/Million
BTU Output
531,100
1.88
Ethanol
CPS Gluten
BTU/Million
BTU Output
439,100
2.28
4.25
2.08
2.02
2.15
2.60
The effective energy compares ethanol on an equal basis to the other fuels. There are two adjusted to net
energy. The first relates to the higher octane for ethanol and takes into account that a refinery could save
some processing energy if they could produce a lower octane gasoline for ethanol blending. The second
adjustment for a slightly higher efficiency of the engine when operated on a 10% blend of ethanol
compared to gasoline.
6.3.3 Alternative Fuels
6.3.3.1 Natural Gas
The energy consumed in the production and distribution of compressed natural gas in Alberta is shown in
the table below. It is compared to gasoline. The compressed natural gas system is more efficient than
gasoline refining in Alberta as evidenced by the lower energy consumption. This combined with the fuel’s
lower carbon content accounts for the reduction in greenhouse gas emissions for natural gas vehicles.
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Table 102: Energy Consumed in the Production of Gasoline and
Compressed Natural Gas.
Units
Fuel Dispensing
Fuel Distribution
Fuel Production
Feedstock Transmission
Feedstock Recovery
Total
Percent
Gasoline
BTU Consumed/Million BTU
Delivered
1,800
5,000
115,700
400
107,600
230,500
23.0
Compressed Natural Gas
BTU Consumed/Million BTU
Delivered
22,000
8,300
20,600
In fuel dispensing
23,000
73,900
7.4
6.3.3.2 Propane
The energy consumed in the production and delivery of propane is based on 95% of the propane coming
from gas plants and 5% from refineries. The gas plants use about 25% of the energy used in a refinery to
produce an equivalent volume. The energy savings and the lower fuel carbon account for the reduction in
greenhouse gas emissions for propane.
Table 103: Energy Consumed in the Production of
Gasoline and Propane
Units
Fuel Dispensing
Fuel Distribution
Fuel Production
Feedstock Transmission
Feedstock Recovery
Total
Percent
Gasoline
BTU Consumed/Million BTU
Delivered
1,800
5,000
115,700
400
107,600
230,500
23.0
127
Propane
BTU Consumed/Million BTU
Delivered
1,800
12,000
25,300
In feed recovery
28,400
67,500
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CHEMINFO
6.3.3.3 Methanol
The energy consumed in the production of methanol is based on the efficiency of existing North American
plants and the assumption that all natural gas feedstock is either converted to methanol or required to
operate the plant.
Table 104: Energy Consumed in the Production of
Gasoline and Methanol
Units
Fuel Dispensing
Fuel Distribution
Fuel Production
Feedstock Transmission
Feedstock Recovery
Total
Percent
Gasoline
BTU Consumed/Million BTU
Delivered
1,800
5,000
115,700
400
107,600
230,500
23.0
Methanol
BTU Consumed/Million BTU
Delivered
3,700
12,700
606,500
6,700
62,300
691,900
69.2
A modern methanol plant with state of the art conversion capability uses about 15% less natural gas per
unit of production. This has a significant impact on the energy balance and reduces the energy consumed
per unit of output to 44.1% of the energy in the methanol. This still results in a positive energy balance for
methanol.
If the methanol is being used in a fuel cell vehicle that has a higher efficiency than the internal combustion
engine then it is not appropriate to compare the energy balance on the fuel production cycle only. The
simplest way to account for this is to apply the ratio of efficiency to the energy output and recalculate the
energy consumption based on apparent energy output. Using the 25% higher efficiency for a methanol fuel
cell vehicle that was modelled for greenhouse gas emissions the energy consumed per apparent million
BTU of output drops to 553,000 BTU for existing plants and 352,800 BTU for new plants. There is the
potential for further improvements with improvements in fuel cell technology in the future.
Methanol’s higher energy consumption accounts for the increase in greenhouse gas emissions on a
production basis. The extra energy use is offset by the relatively low carbon intensity of the natural gas
used in the process. Greenhouse gas emissions from the full cycle methanol fuel cell vehicle result from the
efficiency of the fuel cell vehicle and the low carbon content of the methanol fuel.
6.3.3.4 Biodiesel
The energy balances for biodiesel must also account for the energy displaced by the co-products and the
energy consumed in the production of agricultural chemicals. The differences between biodiesel and diesel
are accounted for by the higher energy requirements of the production process and the energy required for
fertilizers.
Table 105: Energy Consumed in the Production of Biodiesel and
Diesel Fuel
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Units
Fuel Dispensing
Fuel Distribution
Fuel Production
Feedstock Transmission
Feedstock Recovery
Ag Chemicals
Co-products displaced
Total
Percent
Diesel
BTU Consumed/Million BTU
Delivered
1,800
5,000
67,900
400
110,600
185,700
18.6
Biodiesel
BTU Consumed/Million BTU
Delivered
2,000
13,400
426,100
8,300
89,200
138,000
-326,800
350,200
35.0
Biodiesel uses more energy than petroleum diesel for the same energy output. It does have a positive
energy balance with three times as much energy being produced as consumed in the process. Greenhouse
gas emissions benefit from the renewable nature of the fuel.
6.4 Other Environmental Considerations
The transportation sector is a significant source of a number of criteria contaminates in Alberta. These
include carbon monoxide, volatile organic compounds, nitrogen oxides, particulate matter and sulphur
oxides. In addition there are emissions of air toxics such as benzene, formaldehyde, acetaldehyde, 1,3
butadiene that are know to exist in vehicle exhausts but are not yet regulated or fully inventoried.
Emissions of these compounds from gasoline, ethanol blended gasolines and alternative fuels are discussed
below.
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6.4.1 Gasoline
The emissions from gasoline powered vehicles in Alberta in relation to all transportation sources and all
sources are shown below (Environment Canada, 1999). These emissions are derived from the vehicle
emissions model Mobile5C.57
Table 106: 1995 Emissions from Gasoline Vehicles in Alberta
(tonnes)
Vehicle Category
Heavy Duty Gasoline
Trucks
Light Duty Gasoline
Trucks
Light Duty Gasoline
Vehicles
Motorcycles
Off Road use
Total Gasoline
Total Transportation
Gasoline
as
%
Transportation
All Sources
Gasoline as % All
Sources
Carbon
Monoxide
34,165
VOCs
NOx
PM2.5
SOx
2,444
3,851
96
122
289,762
28,982
21,125
385
480
430,581
44,123
30,733
306
666
1,173
194,030
949,711
1,029,617
92.2
171
11,769
87,489
107,946
81.4
63
5,158
60,930
206,326
29.5
1
313
1,101
11,420
9.6
2
149
1,419
9,453
15.0
2,000,869
47.5
762,732
11.5
653,319
31.6
268,963
0.4
608,100
0.23
Gasoline sales in Alberta were 3.9 billion litres (Transport Canada, 1999) not including off road use. With a
combined on road fuel economy for gasoline cars and trucks of 10.94 L/100km in 1995 the total kilometres
driven to produce those emissions are calculated to be 35.9 billion kilometres. The majority of the on road
emissions are from light duty cars and trucks which have very similar emission rates. The emission rates in
the table are higher than that calculated from the same sources for Ontario.
57
Environment Canada, 1995 Criteria Air Contaminants Emissions For Canada, January 1999.
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Table 107: Calculated 1995 Vehicle Emission Rates
Carbon Monoxide
VOC
NOx
PM 2.5
SOx
Calculated Emission
Rate Alberta, g/km
Calculated Emission
Rate Alberta, g/mile
Calculated Emission
Rate Ontario, g/mile
21.0
2.1
1.5
0.022
0.035
33.7
3.4
2.5
0.035
0.057
25.4
2.5
1.8
0.064
0.112
These emission factors are very high. The in-use vehicle emission rates were higher in Alberta than many
other provinces in Canada due to factors such as the age of the fleet, the altitude, and the cold winters. The
Alberta fleet age has been reduced the past several years and remote sensing emissions measurements in
Alberta have reported similar results to those reported in Ontario (CASA, 1999). This would suggest that
emission rates in Alberta are approaching those of Ontario.
The average emission rates are declining each year in Canada. This trend is expected to accelerate in the
near future due to the introduction of Tier 1 vehicles that were phased in to the market place between 1995
and 1998. These vehicles not only have lower emission rates when they are new compared to the earlier
Tier 0 vehicles but they are required to meet the emission standards for 160,000 km rather than the 80,000
of earlier vehicles. This lower deterioration rate is expected to significantly impact total vehicle emissions
over the next ten years. None of the existing vehicle emission factor models are yet able to predict these
emissions. Mobile6, which will be able to accurately predict these emissions, is due in 2000.
The Delucchi model has been calibrated to the Ontario emission factors for the year 1995 for CO, VOC,
and NOx. The Alberta data is used for particulates and SOx. For the year 2000 it is expected that this will
predict full cycle emissions of regulated pollutants in Alberta quite closely and will allow an accurate
assessment of the impact of ethanol on emission rates. It has introduced some internal inconsistency within
the model with respect to fuel economy and engine efficiency that were addressed in the discussions on
greenhouse gas emissions. For the year 2005 the model will overweight vehicle emissions since it mimics
the results of the Mobile5 model. The comparison of the Environment Canada emission factors and the
Delucchi model results for the year 1995 and 2000 are shown in the table below.
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Table 108: Comparison of Environment Canada Emission Rates
and Rates Calculated by Calibrated Delucchi Model
Carbon Monoxide
VOC
NOx
PM 2.5
SOx
Environment Canada
Calculated Emission
Rate for Ontario,
g/mile
25.4
2.5
1.8
0.035
0.057
Delucchi Model 1995,
g/mile
Delucchi Model 2000,
g/mile
25.4
2.5
1.8
0.036
0.080
20.0
2.0
1.4
0.035
0.080
The Delucchi model calculates the SOx emissions from the gasoline sulphur content and includes the
sulphur from lubricating oil that is burned. The gasoline sulphur content is 240 ppm in the model, which is
reasonable for Alberta. It is not clear where the Environment Canada data was derived from but it probably
did not include the lube oil.
The Environment Canada data includes evaporative emissions and the model has also been calibrated to
include the evaporative emissions. The evaporative emissions are 18% of the total VOC emissions (0.37
g/mile). The EPA Complex Model calculates evaporative emissions for a summer fuel of 0.55 g/mile and
winter emissions of 0 g/mile. The model value is reasonable given the average of summer and winter
emissions.
.
Gasoline powered vehicles are also sources of other pollutants known as air toxics. These
are known or probable human carcinogens. Benzene, for instance, is a known human
carcinogen, while formaldehyde, acetaldehyde, 1,3-butadiene and diesel particulate
matter are probable human carcinogens. Studies are underway to determine whether other
toxic substances are present in mobile source emissions. For example, EPA is also
working with the vehicle and fuel industries to test motor vehicle emissions for the
presence of dioxin.
EPA estimates that mobile (car, truck, and bus) sources of air toxics account for as much
as half of all cancers attributed to outdoor sources of air toxics. This estimate is not based
on actual cancer cases, but on models that predict the maximum number of cancers that
could be expected from current levels of exposure to mobile source emissions. The
models consider available health studies, air quality data, and other information about the
types of vehicles and fuels currently in use.
Some toxic compounds are present in gasoline and are emitted to the air when gasoline
evaporates or passes through the engine as unburned fuel. Benzene, for example, is a
component of gasoline. Cars emit small quantities of benzene in unburned fuel, or as
vapour when gasoline evaporates.
A significant amount of automotive benzene comes from the incomplete combustion of
compounds in gasoline such as toluene and xylene that are chemically very similar to
benzene.
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Formaldehyde, acetaldehyde, particulate matter, and 1,3-butadiene are not present in fuel
but are by-products of incomplete combustion. Formaldehyde and acetaldehyde are also
formed through a secondary process when other mobile source pollutants undergo
chemical reactions in the atmosphere.
The emissions that come out of a vehicle depend greatly on the fuel that goes into it.
Consequently, programs to control air toxics pollution have centred around changing fuel
composition as well as on improving vehicle technology or performance.
The 1990 Clean Air Act required reformulated gasoline to be introduced in the US's most
polluted cities beginning in 1995. From 1995-1999, these gasolines must provide a
minimum 15% reduction in air toxics emissions over typical 1990 gasolines. This
increases to a 20% minimum reduction beginning in the year 2000. The air toxics
reductions will be achieved mainly by reducing gasoline volatility, reducing the benzene
content of the gasoline and adding oxygenates.
To date, there are no specific standards for air toxics emissions from motor vehicles in
Canada. However, the proposed Tier 2 emission regulation recently introduced in the US
includes limits of 11 to 18 mg/mile on aldehydes for the first time.
The EPA Complex Model includes models for the air toxics. The model is specific to
Tier 0 vehicles and was only developed from data from light duty cars and trucks
nevertheless it is still the most robust tool currently available with which to estimate
toxics emissions from late model vehicles (EPA 1999). Separate equations were
developed for normal and high emitters. The aldehyde emissions are specific to the type
of oxygen added while exhaust benzene and 1,3 butadiene are a function of oxygen
content only for the high emitters. The table below compares the emission rates
predicated by the Complex Model for the US base gasoline adjusted to 1% benzene with
the fleet average emission rates reported for Chicago (EPA 1999).
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Table 109: Air Toxics Emission Rates
Units
Benzene
Acetaldehyde
Formaldehyde
1,3 Butadiene
Particulate matter
Total
Complex Model
Results
mg/mile
51.2
4.4
9.7
9.4
3.0
77.7
EPA Fleet Average Results
mg/mile
53.3
17.8
29.4
7.2
53.6
161.3
It can be seen that in use emissions of air toxics are higher than the Complex Model results which is not
unexpected since the Complex Model is based on just Tier 0 technology. The average fleet results are
calculated by determining toxics as a percentage of VOC emissions from the complex model and then
applying those fractions to the estimated fleet VOC emissions. New vehicles have much lower emissions of
VOC and air toxics compared to the fleet averages.
The Delucchi model calculates not only greenhouse gas emissions on a full cycle basis but also the criteria
emissions. The emission factors used for the production of fuels and vehicles are taken mainly from the US
EPA AP-42 emission factors database. No changes to these emission factors have been made for this
modelling exercise. Evaluating these pollutants on a full cycle basis allows the emissions from production
of fuels, use of the fuel and manufacture of the vehicles to be put into perspective. The next table shows the
emissions of the individual greenhouse gases and the criteria emissions for gasoline for the year 2000. It is
apparent from this table that the different stages in the life cycle contribute different proportions of the
emissions for each of the gases. The upstream stages contribute the majority of methane and sulphur
compounds. The vehicle operations contribute the largest proportions for the rest of the gases, although not
insignificant amounts of NOx and VOC are also contributed by the upstream stages.
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Table 110: Full Cycle Emissions of Individual GHG and
Pollutants
Upstream
Units
CO2
CH4
N2O
CO
NOx
VOC – ozone
weighted
SOx
Particulate
Ozone Forming
Potential58
g/mile
139
0.425
0.009
0.560
0.823
0.376
Vehicle
Operation
g/mile
326
0.167
0.062
19.967
1.435
2.245
Vehicle Material
& Assembly
g/mile
81
0.001
0.003
0.014
0.180
0.003
Total
g/mile
546
0.594
0.075
20.541
2.438
2.624
0.475
0.000
1.279
0.081
0.035
6.532
0.341
0.024
0.185
0.896
0.059
7.996
6.4.2 Ethanol
The impact of 10% ethanol on each of the regulated pollutants and on the air toxics is discussed below. The
discussion includes the impact on the different types of vehicle technology as well as estimates of the
impact on the Alberta fleet.
6.4.2.1 Carbon Monoxide
Carbon monoxide is a colourless, odourless, poisonous gas. A product of incomplete
burning of carbon-based fuels, carbon monoxide consists of a carbon atom and an oxygen
atom linked together. Emissions of carbon monoxide when measured by weight are the
largest of all of the exhaust pollutants.
Carbon monoxide enters the bloodstream through the lungs and forms carboxyhemoglobin, a compound
that inhibits the blood's capacity to carry oxygen to organs and tissues. Persons with heart disease are
especially sensitive to carbon monoxide poisoning and may experience chest pain if they breathe the gas
while exercising. Infants, elderly persons, and individuals with respiratory diseases are also particularly
sensitive. Carbon monoxide can affect healthy individuals, impairing exercise capacity, visual perception,
manual dexterity, learning functions, and ability to perform complex tasks.
Although carbon monoxide is an inorganic gas it is a precursor to ozone formation much like VOCs and
oxides of nitrogen. It is less reactive than the other components by weight but because of the higher weights
emitted can still be a significant contributor to ozone formation. The National Academy of Science
(National Research Council,1999) in a recent review of ozone forming potential of gasoline concluded that
carbon monoxide contributed about 20% of the ozone forming potential of gasoline emissions, much more
than was once believed. Whitten (1999) suggested that CO might be responsible for about as much ozone
as VOCs.
58
Ozone Forming Potential is calculated as the sum of VOC plus NOx plus 1/7 CO.
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Carbon monoxide results from incomplete combustion of fuel and is emitted directly from vehicle tailpipes.
Incomplete combustion is most likely to occur at low air-to-fuel ratios in the engine. These conditions are
common during vehicle starting when air supply is restricted ("choked"), when cars are not tuned properly,
and at altitude, where "thin" air effectively reduces the amount of oxygen available for combustion (except
in cars that are designed or adjusted to compensate for altitude).
Today's passenger cars are capable of emitting 90 percent less carbon monoxide over their lifetimes than
their uncontrolled counterparts of the 1960's. As a result, ambient carbon monoxide levels have dropped,
despite large increases in the number of vehicles on the road and the number of miles they travel. There is
concern that with continued increases in vehicle travel projected; carbon monoxide levels may begin to
climb again unless even more effective emission controls are employed.
Oxygen in the fuel is the primary fuel variable that influences carbon monoxide emissions. The response to
oxygen is dependent on the vehicle technology. New vehicles produce less carbon monoxide and exhibit a
smaller response to fuel oxygen. In the following table the CO effects from the use of oxygenated fuels on
the various vehicle technologies are shown. The conclusions shown are those of the US EPA (Rao) with the
exception of Tier 1 vehicles. The EPA reached their conclusion on Tier 1 vehicles from a limited number of
tests on fuels containing 2% oxygen from MTBE. Two other test programs (Ragazzi, CARB, 1998)
completed since the EPA data was released tested 10% ethanol in Tier 1 vehicles and found a similar
response in Tier 1 vehicles and in Tier 0 vehicles.
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Table 111: EPA Conclusions on CO Effects from the Use of
Oxygenated Gasoline on Light Duty Gasoline Powered Vehicles
CO Effects from the Use Of Oxygenated Fuels
Emitter
classification
Normal
Emitting
Vehicles
< 7g/mile
High Emitting
Vehicles
>7 g/mile
Vehicle Technology
LEV and
Advanced
Technology
(1999+)
Tier 1 (1994-1999)
1988+
TWC/Adaptive
Learning
1986-1987 TWC/
Adaptive Learning
1986+ TWC/No
Adaptive Learning
1981-1985
TWC/Closed loop
Ox Cat/Open Loop
Non-catalyst
LEV and
Advanced
Technology
(1999+)
Tier 1 (1994-1999)
1981+
Ox Cat & Open
Loop
Non-catalyst
# Tests
1
Emissions (Start
and running) per
percent oxygen
Insufficient data
Impact at 10%
Ethanol
Insufficient data
12
133
-3.1059
-3.10
-10.94
-10.9
104
-4.80
-16.8
151
-5.70
-20.2
73
-4.00
-14.0
-9.40
-6.60
-5.3
-32.9
-23.1
-18.6
-5.3
-5.3
-9.4
-18.6
-18.6
-32.9
-6.6
-23.1
134
The fleet average impact for Alberta can be determined by utilizing the fleet distribution data within the
emissions factor model Mobile 5C. In 1995 the impact is estimated to have been an 18% reduction. For
2000 a 12.3% reduction is predicated. The impact beyond 2000 will depend on the response of LEV
technology vehicles and the reduction in off-cycle emissions that result from the implementation of new
vehicle testing procedures in 2001. California recently projected (CARB, 1999a) a 9.1% difference in the
year 2003 between non-oxygenated gasoline and 10% ethanol blended gasoline.
59
This is the conclusion from the (S&T)2 Report on Assessment of Emissions from Ethanol-Gasoline
Blends. On the basis of MTBE blends only the EPA concluded that Tier 1 vehicles show no effect of fuel
oxygen.
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6.4.2.2 Exhaust VOCs
Hydrocarbon emissions result when fuel molecules in the engine do not burn or burn only
partially. Hydrocarbons react in the presence of nitrogen oxides and sunlight to form
ground-level ozone, a major component of smog. Ozone irritates the eyes, damages the
lungs, and aggravates respiratory problems. It is our most widespread and intractable
urban air pollution problem. A number of exhaust hydrocarbons are also toxic, with the
potential to cause cancer.
In this section hydrocarbon exhaust emissions will be discussed. Later sections of the
report will deal with evaporative emissions and with air toxics (some of which are
hydrocarbons).
Ozone is a severe irritant. It is responsible for the choking, coughing, and stinging eyes
associated with smog. Ozone damages lung tissue, aggravates respiratory disease, and
makes people more susceptible to respiratory infections. Children are especially
vulnerable to ozone's harmful effects, as are adults with existing disease. But even
otherwise healthy individuals may experience impaired health from breathing ozonepolluted air.
Elevated ozone levels also inhibit plant growth and can cause widespread damage to
crops and forests.
Like carbon monoxide motor vehicle manufactures have achieved considerable success in
reducing hydrocarbon emissions. Emissions from new vehicles are over 95% less than an
uncontrolled vehicle from the 1960’s.
Oxygenated compounds like ethanol can reduce hydrocarbon emissions from motor
vehicles. This is partly due to the leaning effect that accounts for the CO impact but also
from the dilution in gasoline composition that adding ethanol or MTBE causes and in
some cases from the changes in composition that the high octane of ethanol allows.
(S&T)2 reviewed the literature a part of a review of ethanol’s impact on vehicle emissions
for Environment Canada. The data sets reviewed were reasonably consistent with the
conclusions that EPA has reached in the past on the impact of oxygen on hydrocarbon
exhaust emissions. The following table shows the conclusions reached regarding the
impact of ethanol on exhaust hydrocarbon emissions. The bases for the conclusions are
the factors from the EPA’s AP-42, which have been supplemented by data on Tier 1
vehicles from the Colorado test program (Ragazzi). These are the factors that are
included in Mobile 5 and the EPA is not proposing any changes for Mobile 6.
Table 112: EPA Conclusions on HC Effects from the Use of 10%
Ethanol on Light Duty Gasoline Powered Vehicles
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HC Effects from the Use Of Oxygenated Fuels
Emitter
classification
Vehicle Technology
Normal Emitting
Vehicles
LEV and Advanced
Technology (1999+)
Tier 1 (1994-1999)
Port Fuel Injection
1981+
Throttle Body 1981+
Carburettor 1981+
High Emitting
Vehicles
Emissions
Reduction per wt%
oxygen
-4.060
Impact at 10% Ethanol
-4.05
-4.0
-14.05
-14.0
-2.9
-6.2
-10.3
-21.5
Open Loop Catalyst
pre 1981
-4.5
-15.8
Non-catalyst pre
1981
-6.60
-23.1
No data
No data
-5.8
-6.6
-20.3
-23.1
LEV and Advanced
Technology (1999+)
Tier 1 (1994-1999)
1981+
-14.05
The Alberta fleet average impact was determined to be a 15% reduction in both 1995 and in 2000. The
actual change in 2000 will be lower than in 1995 because the level of emissions is projected to be lower.
The reductions projected by the California Air Resources Board are for organic gases are not appropriate
for Alberta because the non-oxygenated gasoline in California is not representative of Alberta gasoline and
it has been blended to meet California Cleaner Burning Gasoline standards whether ethanol is in the
gasoline or not.
6.4.2.3 Nitrogen Oxides
Nitrogen oxides are a precursor to ozone formation, where NOx and VOCs react in the
presence of sunlight to form ozone. To reduce ozone formation it is generally required to
reduce both NOx and VOCs.
Transportation contributed 32% of the Alberta sources of NOx excluding forest fires in
1995. Gasoline sources contributed 29.5% of the transportation NOx, the largest portion
coming from diesel sources.
Nitrogen oxides are formed during the combustion process by the reaction of excess
oxygen and nitrogen at high temperatures. Nitrogen oxides tend to have an inverse
60
Conclusion based on data presented in the (S&T)2 Environment Canada report.
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relationship with CO and hydrocarbons; NOx tends to be higher when CO and THC are
lower. The addition of oxygen to the fuel will create excess oxygen in the combustion
chamber and elevate peak temperatures and thus tend to increase NOx. Test data supports
this hypothesis. In general similar effects have been found for all oxygenates.
The US EPA has concluded that oxygenates have no impact on NOx. That conclusion is
imbedded in the Mobile models, it is stated in AP-42 and it is part of the Complex Model.
The California Air Resources Board in contrast to the EPA has long maintained that
oxygen does have an impact on NOx and until recently maintained an oxygen cap on
their cleaner burning gasoline. That cap was lifted in December 1998. The California
Clean Burning gasoline regulations still require a gasoline with 10% ethanol to
demonstrate NOx emissions equivalency using their predictive model.
The Colorado test program concluded that ethanol use resulted in a small overall increase
in NOx. A similar conclusion was reached concerning increasing oxygen content with the
1998 California study, although most of the increase there could be attributed to one
vehicle. Almost all of the test programs identified in the literature have found a small
increase in NOx emissions with increasing oxygen content. The increases that have been
found in individual test programs have not always been statistically significant especially
at the lower oxygen levels resulting from MTBE use. This lack of consistent statistically
significant results is probably the reason for EPA’s conclusion that fuel oxygen does not
impact NOx.
It will be assumed that 10% ethanol will increase NOx emissions by 5% for the air
quality impacts calculated later in the report. The same value will be applied to all classes
of vehicle technology. This is considered conservative since not all studies have found
statistically significant increases in NOx from ethanol addition.
Gasoline sulphur content does have an impact on NOx. A drop in vehicle NOx emissions
can be expected when low sulphur gasoline is introduced in 2005. Most of the processes
for removing the sulphur from gasoline also lower the octane of the fuel. Ethanol could
be used to replace the olefins and the octane. By replacing the olefins the impact of
ethanol on NOx will be minimized.
6.4.2.4 Evaporative Emissions
Evaporative hydrocarbon emissions are classified into three types: running losses, hot
soak, and diurnal emissions. Running loss emissions occur when the vehicle is driven and
can originate from a number of sources within the fuel system and from fuel vapour
overflow of the on-board carbon canister. Hot soak emissions occur immediately after a
fully warmed up vehicle is stationary with the engine turned off and are due to high
under-the-hood temperatures. Diurnal emissions occur when a vehicle is parked and are
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caused by daily ambient air temperature changes. Most of these emissions result during
increasing ambient temperatures, which causes an expansion of the vapour in the fuel
tank.
Fuel volatility is the major fuel related parameter influencing evaporative emissions.
Higher emissions result from increasing fuel volatility. Ethanol creates azeotropes with
some hydrocarbon components of gasoline. These azeotropes have a lower boiling point
than the pure hydrocarbon and cause an increase in fuel volatility unless other changes
are made to the fuel, such as removing butane, to compensate for the azeotrope. The
azeotropes only increase the vapour pressure of a blended gasoline at temperatures above
10C. At lower temperatures ethanol can actually depress the true vapour pressure of the
blend. Ambient temperatures also strongly influence emissions particularly diurnal
emissions. The EPA considers evaporative emissions from gasoline to be zero during the
winter months.
Most of the test data available on evaporative emissions compares an ethanol blend with
a higher RVP to a non-oxygenated fuel since in most areas of the US a one psi RVP
waiver is available for ethanol blends.
Evaporative emissions are being evaluated as part of the Mobile6 review. The latest EPA
document on hot soak emissions is Update of Hot Soak Emissions (1999b). The EPA has
developed hot soak emission curves for vehicles based on fuel system, year of
manufacture, fuel RVP and temperature. The impact of ethanol will be a function of
RVP.
Running loss emissions are a function of vehicle age, fuel RVP, speed, trip length and
ambient temperature (EPA 1999c). The EPA has not identified any ethanol specific
factors with running losses.
Diurnal emissions are a function of test temperature and fuel RVP (EPA 1998c). Again
EPA identifies no ethanol specific factors.
Similar conclusions have recently been reached in California. The development of new
predictive models for Phase 3 Reformulated gasoline that included ethanol resulted in
evaporative emissions equations that are only a function of RVP (CARB, 1999b).
The impact of ethanol on evaporative emissions is dependent on several factors. In the
winter, late fall and early spring when ambient temperatures are low evaporative
emissions from gasoline are very low and adding ethanol to the fuel does not have a
significant impact. If ethanol is blended in the refineries to meet the same vapour
pressure as gasoline then the impact of ethanol is again small for most cars. The possible
exception to this would be caused by individuals switching between ethanol blended
gasoline and all hydrocarbon gasoline. The increase in vapour pressure that ethanol
causes in gasoline blends is non-linear. The magnitude of the increase is about the same
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between 3 and 10% ethanol. Mixing two fuels with the same vapour pressure but one
with ethanol and one without causes an increase in vapour pressure. The magnitude of the
increase is dependent on the ratio of the two fuels mixed but is less than one psi increase
in vapour pressure. This co-mingling is beyond the control of refiners and marketers. The
largest increase in vapour pressure occurs when ethanol is added to finished gasoline.
The increase in evaporative hydrocarbon emissions offsets the decrease in exhaust
hydrocarbon emissions. The Canadian emission factors model Mobile5C can be used to
determine the total hydrocarbon emissions for each season. That data for Alberta is
shown below for a 10% ethanol blend.
Table 113. Combined Impact of 10% Ethanol with One psi Higher
Vapour Pressure on Total Hydrocarbon Emissions.
Change in Exhaust
Emissions
(gm/mile)
Winter
Early Spring and
Late Fall
Late Spring and
Early Fall
Summer
-0.35
-0.327
Change in
Evaporative
Emissions
(gm/mile)
0
0.167
% Change in
Total
Hydrocarbon
Emissions
-13.3
-6.5
-0.316
0.217
-4.2
-0.293
0.453
+7.2
It is only in the summer that the increase in evaporative emissions is larger than the reduction in exhaust
emissions. Summer is the season where ozone is the largest problem. A fuel with the same vapour pressure
as gasoline will have a combined impact similar to the winter value all year long if there is no comingling
in the vehicle fuel tanks.
Evaporative emissions have decreased as vehicle technology has improved the same way
that exhaust emissions have. In Canada starting with the 1998 model year on-board
refuelling vapour recovery systems are being phased in over a three-year period. These
systems will further reduce evaporative emissions from vehicles. Total vehicle emissions
are declining as newer technology vehicles constitute a larger proportion of the vehicle
fleet.
6.4.2.5 Hazardous (or Toxic) Air Pollutants
The Complex Model results for a 5.7% ethanol blend were shown in an earlier section of the report. The
results for a 10% blend are shown here. The only significant increase is in acetaldehyde. There are small
decreases in the other air toxics.
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Table 114: US Complex Model Results for Baseline Gasoline
With and Without 10% Ethanol
Baseline Gasoline
Units
Exhaust benzene
Nonexhaust benzene
Acetaldehyde
Formaldehyde
Butadiene
POM
Total exhaust toxics
Total toxics
mg/mile
53.54
5.51
4.44
9.70
9.38
3.04
80.10
85.61
Gasoline with 10%
Ethanol
mg/mile
44.6
5.51
11.16
9.70
8.33
3.00
76.83
82.34
Change, %
-16.63
-0.00
151.53
0.00
-11.2
-1.34
-4.08
-3.82
The California predictive model calculates similar increases in acetaldehyde emissions. There has been
some research performed to try and determine the impact of this increase on ambient air quality. The
Denver area has used ethanol blended gasoline to reduce winter CO emissions since the late 1980’s.
Anderson (1997) compared the concentrations of formaldehyde and acetaldehyde during the winter of
1995/1996 when almost 100% of the gasoline contained ethanol with the levels of the winter of 1988/1989
when 95% of the gasoline contained MTBE. No significant differences in acetaldehyde concentrations
were found. The authors concluded that the photochemical production and destruction of these aldehydes
(secondary effects) suppress the effect of exhaust emission changes.
The California review of air quality impacts of ethanol use in gasoline included airshed modelling (CARB,
1999a) The model tracked both primary acetaldehyde emissions (from vehicles) and secondary emissions
(from atmospheric reactions). They also reported that the secondary reactions had a larger influence on
ambient air concentrations of acetaldehyde than the vehicle emissions. The projected difference in
acetaldehyde concentrations in 2003 between gasoline containing 10% ethanol and non-oxygenated
gasoline was 1.3 ppb. In both cases the concentrations were lower than modeled for the year 1997, showing
the influence of continuing improvements in vehicle exhaust emissions.
Recent determinations of particulate emissions from vehicles using non-oxygenated gasolines and gasolines
containing 10% ethanol were reported by Ragazzi (1999). The results for Tier 0 and Tier 1 vehicles were
reported separately. A much larger reduction for the 10% ethanol blends was found than is predicted by the
complex model. Particulate emissions are receiving much more attention now that their role in respiratory
ailments is better understood. The results reported by Ragazzi are shown in the following table.
Table 115. Particulate Matter Emissions for Tier 0 and
Tier 1 Vehicles
Tier 0 Vehicles
Tier 1 Vehicles
Gasoline
10.3 mg/mile
4.5 mg/mile
10%Ethanol Gasoline
7.0 mg/mile
3.4 mg/mile
Percent Change
-32.2
-25.3
The full cycle emissions for a 10% ethanol blend with the same vapour pressure as gasoline when the
ethanol is made in a dry milling operation processing CPS wheat is shown below. For comparison purposes
the total emissions for gasoline are also shown.
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Table 116. Full Cycle Emissions of Individual Gases and
Pollutants
Units
Fuel
CO2
CH4
N2O
CO
NOx
VOC – ozone
weighted
SOx
Particulate
Ozone Forming
Potential
Upstream
Vehicle
Operation
Total
Total
g/mile
10% ethanol
328
0.174
0.062
16.583
1.490
1.809
Vehicle
Material &
Assembly
g/mile
10% ethanol
80
0.001
0.003
0.014
0.179
0.003
g/mile
10% ethanol
123
0.438
0.010
0.538
0.821
0.429
g/mile
10% ethanol
531
0.613
0.075
17.135
2.491
2.242
g/mile
gasoline
546
0.594
0.075
20.541
2.438
2.624
0.481
0.000
1.327
0.076
0.033
5.668
0.340
0.024
0.184
0.897
0.057
7.179
0.896
0.059
7.996
6.4.3 Alternative Fuels
The discussion on the environmental considerations of the other alternative fuels follows. Some discussion
of the engine for the fuels is necessary to put the fuels into perspective. A poorly set up engine can negate
any environmental benefit that a fuel may offer.
6.4.3.1 Natural Gas
The discussion of natural gas will focus solely on OEM vehicles. The quality of aftermarket conversions is
variable and some conversions may have higher emissions than the original gasoline vehicles.
Most OEM natural gas vehicles are certified to more strict emission standards than Tier 1. The
DaimlerChrysler vehicles are certified to ULEV as are the dedicated Ford vehicles. The bi-fuel Fords and
GM vehicles are TLEV vehicles.
The US DOE has tested some of the OEM alternative fuel vehicles and the similar gasoline vehicles for
comparison. The Ford F-250 pickup truck and the Honda Civic dedicated natural gas vehicles have been
tested. Both the natural gas vehicles meet the ULEV standards. For the Ford the natural gas vehicle had
97% lower non-methane hydrocarbons (NMHC), 63% lower carbon monoxide, 81% lower NOx, and 99%
lower air toxics. Carbon monoxide emissions from the vehicle were 17% lower. The gasoline used for
testing was the US industry average fuel. The Honda exhibited similar reductions, a 96% reduction in
NMHC, 90% less CO, 69% lower NOx and 97% lower air toxics. The Honda levels on natural gas were
1/10 th the ULEV standards.
The tests on a bi-fuel GMC Sierra pickup truck were quite different illustrating the compromises that must
be made for bi-fuel operations. On natural gas the vehicle had 67% lower NMHC, 34% lower NOx, 83%
lower air toxics, but it had CO emissions 68% higher than the gasoline version.
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Methane emissions from CNG vehicles are higher than from gasoline vehicles. Some tests on older
vehicles have shown methane emissions to be an order of magnitude higher. This was factored into the
greenhouse gas emissions for CNG reported earlier.
The full cycle emissions from the Delucchi model are not a fair comparison as a new CNG vehicle would
be compared to the average gasoline powered vehicle in Alberta.
Evaporative emissions are very low from natural gas as the fuel system is pressurized and not open t the
atmosphere. A small amount of gas that is trapped in the fuelling nozzle is released at the end of the
refuelling process.
6.4.3.2 Propane
Only Ford offers an OEM light duty propane powered vehicle. It is a dual fuelled F-250 pickup truck. GM
does have a number of medium duty trucks with a propane option. The testing performed by the US DOE
on this vehicle showed that on propane the NMHC emissions were 55% lower, the CO emissions were 96%
higher and the NOx emissions were 160% higher than when the vehicle was tested on gasoline. The vehicle
did meet ULEV standards on both propane and gasoline. The emissions of air toxics were 98% lower on
propane than on gasoline. The DOE did not test a gasoline powered truck for comparison.
Propane is also stored in a pressurized container so there are no evaporative emissions.
6.4.3.3 Methanol
There is very little data available on emissions from a methanol fuelled fuel cell. One analysis of emission
data from prototype fuel cells projected emissions of 0.001 g/mile of NOx, 0.003 g/mile for carbon
monoxide, and 0.007 g/mile for VOC’s (Mark, 1996). These emissions are very low, at least 95% cleaner
than an ultra low emission vehicle and are one of the reasons for the large interest in fuel cell vehicles
being showed by auto manufacturers.
Evaporative emissions from methanol for fuel cell vehicles will be low as the methanol in its pure state has
a very low vapour pressure.
6.4.3.4 Biodiesel
Diesel engine emissions are quite sensitive to the cetane fuel level particularly when the cetane is between
40 and 50 as it is with Western Canadian diesel fuels. biodiesels emission impact is derived from both its
high cetane value and the fact that it contains some oxygen.
There has developed a large body of data on engine emissions when biodiesel is used in conventional diesel
engines. The information includes both the use of biodiesel in low-level blends and as a neat fuel. Typical
of the data in the literature is work by Spataru and Romig who tested blends of canola methyl ester (CME)
and soy methyl ester (SME) with Federal EPA and California ARB diesel fuels in both engine and chassis
dynamometers operated to US EPA protocols using a Detroit Diesel 6V92TA bus engine.
Table 117: Emission Testing of CME/Diesel Blends
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EPA Diesel
(g/bhp/hr)
Total PM
Soluble PM
Insoluble PM
THC
NOx
CO
CO2
0.265
0.133
0.132
0.435
5.62
1.19
653
20%
CME/EPA
(g/bhp/hr)
0.234
0.145
0.090
0.363
5.87
1.04
652
Percent
Change
-11.7
9.0
-31.8
-16.6
4.4
-2.1
-0.2
California
Diesel ARB
(g/bhp/hr)
0.270
0.141
0.128
0.546
5.34
1.24
653
20%
CME/ARB
(g/bhp/hr)
0.257
0.158
0.099
0.437
5.54
1.20
653
Percent
Change
-4.8
12.1
-22.7
-19.9
3.7
-3.2
0
Emissions of particulate matter, total hydrocarbons, and carbon monoxide dropped, nitrogen oxide
emissions increased and carbon dioxide emissions stayed the same. Chassis dynamometer results showed
similar trends. Other researchers using other engines have found similar results.
Biodiesel is biodegradable which makes it an attractive fuel for some sensitive environments. It is used in
some marine applications in the US where a spill of petroleum fuel would cause problems.
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7. Review of Ethanol Socio-Economic
Studies
7.1 Summary
Numerous socio-economic studies of ethanol production and use in various jurisdictions have been
performed over the past two decades. Approximately 20 of these studies are reviewed below. Most studies
were related to ethanol from corn and were carried out for areas of the United States while a few were
undertaken for Canada. There is considerable variation in the scope, approaches and methodologies
applied.
Most of the analyses concluded that the extra demand for feed grains (mostly corn) had some upward
impact on feed grain prices. The amount of the increase varies year by year due to changes in the overall
supply-demand balance. The studies that considered the whole US market have price increases for corn of
20 to 45 cents per bushel due to the demand created by ethanol production. Due to the interdependent
nature of North American feed grain markets Canadian producers have also received some benefit from this
extra demand.
Most of the studies reported an increase in the number of jobs due to the production of ethanol. These jobs
are weighted towards the rural sector of the economy but indirect benefits accrue to all sectors of the
economy. Most of the studies also report an increase in Gross Domestic Product (GDP) related to the
demand for grain and the production of ethanol. However, these results are mostly in regions that have
large rural populations, and lack an oil refining industry.
The studies are not consistent in their determination of overall costs and benefits to the economy. As a
result the conclusions of the reports vary with respect to the costs and benefit analyses. Some conclude that
the costs to governments and society outweigh the benefits and others reach the opposite conclusion. That
is, the benefits are greater than the costs and that government expenditures drop as a result of ethanol fuel
tax exemptions. Some studies are also internally inconsistent in how they treat issues such as ethanol’s
lower energy content. They calculate the lost government revenue from the ethanol portion of fuels but do
not include the extra fuel tax revenue from the extra gasoline sales caused by the lower fuel economy.
A brief overview of the most recent studies presented by country and in chronological order follows. The
key findings, limitations, and unique aspects of the studies are highlighted.
7.2 United States Studies
7.2.1 Economic Analysis of Replacing MTBE with Ethanol in the United
States. USDA, 1999
This paper analyzes the effects of replacing MTBE with ethanol. The analysis assumed that all MTBE in
the US is phased out and replaced with ethanol on an equivalent oxygen basis. The replacement happens
gradually over the 2000 to 2004 time period. The USDA used an econometric model to estimate crop
production, use and prices of major crops and livestock prices, retail food prices, and net farm income. An
input-output model was used to determine the impact on employment.
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The scenario modeled resulted in a doubling of US ethanol production to 3.0 billion USG per year by 2004
compared to the business as usual scenario. The average price increase for corn over the 2000-2010 period
was forecast to be 14 cents per bushel. This is in addition to the price increases already caused by the
current production level of 1.5 billion gallons per year. Other feed grain prices also increase while soybean
prices decline due to the increased production of high protein feeds from the ethanol plant. Farm cash
receipts average $1.0 billion more over the ten year period.
The increase in farm and ethanol production creates an additional 13,000 new jobs across the economy by
2010.
The US trade balance is expected to improve by $1.3 billion per year. This is caused by a $200 million
increase in agricultural exports and a $1.1 billion per year decrease in US MTBE imports.
There is the potential for a decrease in US farm program costs over the period due to the higher farm
income. The USDA is currently projecting the farm prices for the next decade will be above the threshold
where the loan deficiency payments and marketing loans will kick in and thus payments under these
programs are minimal. The higher farm prices caused by expanded ethanol production will not have an
impact on these programs provided prices stay above the minimums set by the programs. It is
acknowledged that farm prices are highly volatile and if commodity prices drop below current forecasts
these programs could start to make payments and thus there may be future savings caused by the higher
corn prices and farm incomes. It should be noted that the current USDA estimate for the year 2000 projects
a $33.5 billion (US) expenditure for farm support programs. This is $10 billion more than 1999 and is due
to the increased need to address farm income and natural disaster issues (USDA 2000).
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7.2.2 The Costs and Benefits of State-Level Oxygenate Mandates to
Expand Ethanol Production. American Petroleum Institute, January 1999
The principal purpose of this paper was to assess the likely costs and benefits of additional state level
mandates that were being considered by various state assemblies. The analysis concentrates on the state of
Minnesota and calculates the costs and benefits from the mandated program in that state. The paper
concludes that the costs outweigh the benefits by a factor of over four to one. Details of the calculations of
costs and benefits are shown below.
The benefits to corn producers are calculated from the production margin on incremental corn production
required to meet the ethanol demand in Minnesota. The production margin is estimated at $0.64 per bushel
and the increased demand is 52.8 million bushels for a benefit of $25.8 million. The report suggests that the
extra demand will increase corn prices by $0.04 to 0.05 per bushel but does not calculate or include the
benefit to the producers from this higher price. The total increase in revenue from corn produced in the
state from a $0.04 per bushel increase is $44 million.
The indirect benefits accruing to the agricultural sector are calculated from the feed grain multiplier of 2.0
derived from the US input-output accounts. The benefits are calculated from the assumed incremental
production of corn of 52.8 million bushels at $2.19 per bushel and the factor of 2.0 for a total of $115.6
million in extra economic activity from the incremental corn production. The study further assumes that a
10% profit margin on this activity yields a net benefit of $11.6 million. It is not clear why incremental
production margins were used for the corn production but average production margins are used for the
indirect benefits.
There are no direct or indirect benefits calculated from the increase in employment or economic activity
associated with the production of ethanol. The total benefits are calculated to be $37.4 million ($25.8
million + $11.6 million).
The costs of a mandated program are calculated from three components, higher prices paid by consumers,
lost revenue from State ethanol incentives and Federal tax exemptions. The higher gasoline prices are
supported by comparisons of retail prices in Minnesota compared to fourteen other states in the mid west
over a five week period in November and December 1998. The difference in retail prices was $0.03 per
gallon. No adjustments were made for different tax levels in the various states nor for different competitive
wholesale and retail scenarios or distribution costs. The cost difference is further supported by a
comparison of ethanol prices of $1.20 per gallon and wholesale gasoline prices of $0.30 per gallon. No
time reference is given for this comparison and while the ethanol price is not unusual for Minnesota the
gasoline price corresponds to a crude oil price of less than $10 per barrel which is highly unusual. Current
wholesale gasoline prices are about $0.80 per gallon. This cost to consumers is calculated to be $50 million
per year.
The cost of the state incentives is calculated to be $26.7 million per year (132 million gallons at $0.20 per
gallon and $300,000 in loan rate subsidies). The federal tax exemption is calculated to be $79.9 million
(based on $0.54 per gallon plus the small producer payments of $0.10 per gallon on production from plants
of less than 15 million gallons per year. The total costs calculated are $156.6 million. Approximately one
third of that is based on a snapshot of market conditions.
This study is certainly one of the least rigorous of the socio-economic studies performed on ethanol. The
data chosen would appear to overestimate the costs, underestimate the benefits and in fact would not appear
to include all of the potential benefits. For example the impact on corn prices in other areas of the US is not
calculated.
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7.2.3 Ethanol Tax Incentives and Issues. David Andress and Associates for
the US Department of Energy. April 1998
This is not a socio-economic study per se but rather an analysis of the actual cost of the US Federal Tax
exemption and typical state programs. The conclusions are that nominal incentive values for the Federal
and State programs overstate the true cost to governments for several reasons. The first is that fuel taxes are
applied volumetrically and ethanol only has about 65% of the energy of gasoline. Consumers therefore
must purchase more gasoline to travel the same distance and the tax revenues to the government increase.
The US $0.54 per gallon ethanol incentive therefore costs the government only $0.479 per gallon ($0.541/3*$0.184(the gasoline tax rate)). This principle applies to both federal and state programs. Secondly the
US treats the ethanol income tax credit as revenue and thus it is taxed at the taxpayers marginal rate.
Thirdly, there will be some increase in the domestic tax base from the increased economic activity resulting
from the ethanol production.
For states that do not provide differential taxation for ethanol, the report correctly points out collect more
fuel tax when 10% ethanol is used. Based on a typical US State fuel tax of 20 cents per gallon the
additional state revenue is 6.7 cents per gallon. The total cost to governments of the $0.54 per gallon
incentive is then typically $0.412 per gallon.
The paper’s calculation of the impact of the income tax benefit is probably overstated since most blenders
utilize the excise tax exemption rather than the income tax credit. It is well established in the US that the
income tax credit has less value. This is due to the fact that it is taxable and only recoverable once per year
against income taxes owing.
The key finding of this study is the lower impact of ethanol’s energy content on lost government revenues.
7.2.4 The Economic Impact of the Demand for Ethanol. Michael K. Evans,
Kellogg School of Management, North-western University. February 1997.
This study which was commissioned by the Governors’ Ethanol Coalition is based on econometric
modelling of the US corn and ethanol industries. The key conclusions from the study were:
1.
The 1997 ethanol demand of 1.52 billion gallons (not all fuel use) created a demand for 0.60 billion
bushels of corn. This resulted in net new demand of 0.42 billion bushels and a reduction of 0.18 billion
bushels of exports and other uses. This higher demand increased corn prices by $0.45 per bushel
2. The higher corn price increased net farm incomes by $4.5 billion.
3. The higher farm income combined with multiplier effects boosted employment by 169,000 in 1997.
Most of this was off farm.
4. Further employment gains of 13,300 jobs in the ethanol industry including indirect jobs and 12,500
jobs including indirect jobs due to farm equipment purchases were recorded.
5. The total employment increase was 195,200 jobs.
6. The corn growing states experienced $465 million higher state and local tax receipts due to the
economic activity.
7. Federal tax receipts increased by $3.6 billion and unemployment payments declined by $0.6 billion.
This includes personnel income tax, corporate income tax, and social security payments.
8. The cost of the federal fuel ethanol subsidy was $0.6 billion in 1997.
9. Increases in food prices due to ethanol demand was fully offset by declines in energy prices resulting
in no net impact on the cost of living.
10. Trade balance improved by $2.0 billion.
The primary driving force for the benefits is the increased demand for corn and the resulting higher price
for the commodity. Impacts on farm income, employment, taxes, trade and balance of payments are all
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derived from changes in farm income. The author modeled corn prices with and without the demand for
ethanol and compared the results to historical periods where there were large changes in corn exports. He
concluded that the historical data supported the modelling results. The impact on corn prices has increased
as demand for corn for ethanol production has increased. More discussion of the impact of demand on price
is found in a later section.
Increases in corn prices were an order of magnitude higher than was used in the API study described
earlier. This and the much more rigorous modelling of the economy performed for this study accounts for
much of the different conclusions reached in the two reports. The study did not consider the energy content
of the ethanol when it determined the costs to government.
7.2.5 Ethanol Programs. A Program Evaluation Report. State of Minnesota,
Office of the Legislative Auditor. February 1997.
This report considers the cost and benefits of Minnesota’s ethanol program from a state perspective. It does
not consider the costs of the federal tax exemption, nor the impact on national corn prices. The authors used
a state input-output model to determine the impact of the ethanol program on the state economy.
The report concludes that the state’s support of ethanol has significant costs but produces net economic
benefits. The net benefits are quantified at $109 to $260 million per year in addition to a one time benefit of
$174 to $261 from the construction of the plants. The wide ranges in benefits are primarily due to
assumptions that the program could increase farm revenue some years and decrease it other years. This is
due to the co-op structure of many of the ethanol plants where corn producers own the ethanol plants and
are obligated to deliver corn to the plant. In years of low corn prices the ethanol plant may pay higher than
market price for corn and in years of high corn prices it may pay less than the market price. A multiplier of
1.53 is used on farm income to determine the total economic impact. If no impact on corn price is assumed
then the range of net benefits is calculated to be $167 to $202 million.
The benefits are determined by comparing the state economic output from $17 million spent on the ethanol
program to the state output from an equivalent income tax reduction. The analysis assumes that the corn
used for feedstock is incremental to farm production and income. The economic output from the ethanol
program is therefore the total revenue generated from the ethanol and the DDG production. This totals $269
million for 1997 and can be compared to $20 million in economic activity generated by a $17 million tax
cut. Note that the multiplier for the tax reduction is 1.18, considerably lower than the factor used for the
agricultural sector.
The analysis calculated about 900 net jobs before the consideration of the impact of higher fuel costs.
The report calculates the impact of an ethanol mandate on annual fuel costs for consumers. The additional
fuel costs of 2 to 3 cents per gallon for consumers are projected. In addition higher total costs arise from the
lower energy content of the ethanol blended gasoline and the determination that fuel costs will be higher for
the oxygenated gasoline. The data that supports the assumption of higher prices is in part the same as sited
in the API report. The data covers such a large area with different taxes, different competitive pressures it is
difficult to reach absolute conclusions. Week to week price differences are much larger than the average
values that the authors used to calculate total costs. Only nine weeks of data was used in the calculations.
Some of the wholesale price data that is presented would suggest that conventional gasoline prices in
Minnesota were 3 cents per gallon higher than the rest of the Midwest before the oxygen mandate was
imposed. If that were the case then no additional cost has been imposed due to the ethanol mandate. The
same multiplier is used for the extra fuel costs as the tax reduction since both should have similar impacts
on consumer spending.
The total program costs calculated range from $67 to $102 million. This is comprised of $27 million in
producer incentive and blender tax credit (since phased out) impact and $40 to $75 million in higher
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consumer fuel costs. The extra state fuel tax revenue from the increased fuel cost is not calculated and
accounted for.
7.2.6 Tax Policy. Effects of the Alcohol Fuels Tax Incentives. United States
General Accounting Office. March 1997.
This report was developed to address four specific issues;




Whom do the incentives benefit and disadvantage economically?
What environmental benefits, if any, have the incentives produced?
Have the incentives increased the nation’s energy independence?
To what extent has the incentive reduced the flow of revenue to the Highway Trust Fund?
The study was not an socio-economic or cost/benefit analysis and the authors clearly state that it should not
be used for that purpose.
The study found that fuel blenders, ethanol producers and corn and soybean farmers benefit from the tax
exemption. The farmers benefit from higher commodity prices (9.3% for corn and 4.8% for soybeans). The
total farm income is 2.4% higher because of the demand or ethanol production. The magnitude of the total
benefits were not quantified. The tax incentives impact producers and consumer of alternative fuels to
ethanol. The available evidence suggested that ethanol lowers gasoline prices by only a small amount (0.27
%). The consumer benefits from the lower gasoline price, which at least partially offsets the higher cost of
food that higher grain prices would cause.
The impact on the environment was minimal in the view of the authors. In areas with air quality problems
if ethanol wasn’t used MTBE would be used instead and there would be no environmental impact. In areas
that didn’t require oxygenated fuel the view was that air quality would not degrade to the point that air
quality standards were not met. It was thus concluded that ethanol had little environmental impact.
From the fact that ethanol only represents about 1% of the vehicle fuel consumption it was concluded that
ethanol doesn’t significantly reduce oil imports. This was rationalized by comparing oil import levels in
1978 with those in 1995 and finding no change. The fact that oil imports more than doubled between 1982
and 1995 is ignored.
It was determined that revenues flowing to the Highway Trust Fund were reduced by about $617 million in
1995.
The report acknowledged the need for stability in government programs. Without stability investors will
not invest in new technologies and ventures. A number of comments from the US DOE and USDA are
included in the report. Some of these comments disagree with the major conclusions reached by the
authors.
7.2.7 Comments Concerning the Environmental Protection Agency’s
Regulations of Fuels and Fuel additives: Renewable Oxygenate
Requirements for Reformulated Gasoline Proposed Rule. February 1994.
The USDA projected a 3-5 cent per bushel increase in the price of corn for every 100 million bushels of
increased corn demand. At 1999 production levels this equates to increased corn prices of 18 to 30 cents
per bushel. This higher farm income also resulted in lower deficiency payments under Farm support
programs in place at the time. The savings in these programs was projected to be as much as $780 million.
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7.2.8 The Economic Impacts of Renewable Energy Use in Wisconsin. April
1994. Wisconsin Energy Bureau, Division of Energy and Intergovernmental
Relations.
This report discussed the impact of increased ethanol production within the state of Wisconsin. Higher corn
prices from increased demand for ethanol will have the following economic impacts in the state;
 Lower demand and price for soybeans,
 Benefits to cattle and poultry producers from additional supply of high protein feeds,
 Overall increases in net farm incomes,
 Slight increase in food prices.
The study concluded that ethanol gasoline blends would not generate any loss of income or employment
from the displacement of gasoline. The economic impacts from gasoline sales in Wisconsin is limited to the
amount of state tax collected plus the marketing and transportation cost component of the fuel since there is
no oil production or refining in the state.
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7.2.9 Nebraska’s Ethanol Industry. October 1993. Nebraska Department of
Economic Development.
The state used an input/output economic model to determine the impact of an expanded ethanol industry in
the state on job creation and personal and business income. It was projected that in 1995, 213 million
gallons of ethanol would be produced in the state. This would create 455 direct jobs and 1599 indirect jobs.
The direct to indirect multiplier for the ethanol plant jobs was 3.5. There were 2.13 jobs created in ethanol
manufacturing per million gallons of annual production. The annual payroll would be $16.8 million and
$2.4 million would be collected in state income and sales taxes. The state collected a further $2.1 million in
taxes during the construction of the plants.
7.2.10 Ethanol Production and Employment. USDA, Economic Research
Service. Agricultural Information Bulletin Number 678. July 1993.
This study reviewed the economic impacts of expanding ethanol production to 2 billion gallons by 1995
and to 5 billion gallons by 2000. This is considerably faster than the industry was able to expand. The
emphasis was on job creation, agricultural implications, and tax revenues and budget implications. The
1992 ethanol production rate was 950 million gallons.
Increasing production to 2 billion gallons was forecast to create almost 28,000 jobs. These jobs would be
distributed with 15,000 in farming and farm related activities, 10,000 direct and indirect in ethanol
manufacturer (3500 direct) and 3500 construction jobs. The 5 billion gallon scenario creates 108,000 jobs,
34,000 in ethanol processing, 60,000 farm related and 14,000 temporary construction jobs.
The impact on commodity prices was forecast to be relatively small. Corn prices would increase by one
cent per bushel at the 2 billion gallon level, although corn acreage would increase by 3.4%, at the 5 billion
gallons level, corn prices rise by 19 cents per bushel and out put rises by 12%. Soybean prices and output
would fall under both scenarios.
Higher commodity prices would result in lower government farm deficiency payments. At the 5 billion
gallon production level farm deficiency payments drop by $870 million.
7.2.11 Ethanol and Agriculture: Effect of Increased Production on Crop and
Livestock Sectors. USDA, Economic Research Service. Agricultural
Economic Report Number 667. May 1993.
This is a similar study to the previous one but provides more detail of the impact on the agricultural sector.
At the 2 billion gallon level farm income increases by $153 million. This is the net impact of a $407 million
increase in grain prices and output less a $246 million increase in input costs and a drop of $57 million in
federal payments to the farm. Livestock producers net income gains as a result of lower protein costs.
At the 5 billion gallon level the net impact on farm income is an increase of $1.6 billion. The impact on
farm deficiency payments is a reduction of $0.9 billion.
7.2.12 Estimating the Economic Impacts of an Ethanol Plant. Indiana
Department of Commerce. April 1992.
This study looked at the impacts of a single large corn wet milling plant. The plant had an annual output of
$132.8 million and the total output impact was calculated at $449.6 million, $90.8 million in earnings and
4131 jobs. State revenues were forecast to increase by $13.5 million and local revenues by $100,000 to $3
million.
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The expenditure of $117 million during construction would have a total economic impact of $418 million,
create 5604 man-years of employment and increase state revenue by $20 million.
7.2.13 Benefits to Illinois in Developing and Utilizing Ethanol Fuels. March
1992.
This review of the Illinois ethanol industry found that over $1 billion has been invested by the industry in
the state. 800 plant jobs and 4000 additional jobs in service related industries have been created. For every
100 million bushels of corn processed 2250 new rural jobs are created.
It was reported that national corn prices increase by 5 cents per bushel for every 100 million bushels of
demand created. Illinois demand alone was forecast to be responsible for 8 to 10 cents of the national corn
price.
7.2.14 Alcohol Fuels: Impacts from Increased Use of Ethanol Blended
Fuels. US GAO. July 1990.
This study used the Wharton Econometric Forecasting Association model of US agriculture to estimate the
impact of doubling of ethanol production to 2.2 billion gallons and a tripling over an 8 year period.
The model indicated that corn prices would increase by 32 cents per bushel under the high scenario and 19
cents per bushel in the low scenario. The overall farm income would increase by $415 million ($814
million higher prices and $399 million higher expenditures). The consumer price index would increase by
0.1 percent.
The higher farm incomes would decrease the federal deficiency payments by $900 million in the low
growth scenario and $1.4 billion per year in the high growth scenario. The government fuel tax revenues
would decline by $400 million in the low growth scenario and $813 million in the high growth scenario.
The net impact on the federal government resulting from the ethanol program would be a savings of
between $499 million and $608 million per year.
7.3 Canadian Studies
7.3.1 Ethanol Fuel Study. Sypher:Mueller International Inc. Prepared for
Imperial Oil. July 1999.
The objective of this study was to provide a review of ethanol and gasoline with a focus on a number of
issues including economic and social impacts. The review was to be based on analysis contained existing
literature sources.
The economic and social impact section quantified the potential lost government income from a 50%
market penetration of 10% ethanol blends in Canada and the additional cost to consumers caused by
reduced fuel economy. There was some analysis of the groups that benefit and groups that are
disadvantaged by re-allocating monetary resources through ethanol tax incentives.
The calculations of foregone government tax revenues did not adjust for the lower energy content of
ethanol even though for the section on direct consumer impact the extra quantity of fuel consumed was
calculated. Using the report’s own data, they seem to have overestimated the negative impact on tax
revenue by $137 million dollars. Taking the lower energy contact of ethanol into consideration (requiring
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more litres of fuel to be sold and taxed), the lost tax revenue would be calculated as $163 million (not as
$300 million).
The extra cost to consumers was calculated to be $300 million per year from 3% poorer fuel economy
caused by the 10% ethanol blend. There was no discussion of fuel economy variances between gasolines
from different refineries. In Alberta alone the variation in energy content among refineries is more than 7%.
Gasoline fuel economy has not been the only consideration for refiners in the past when they have chosen
refinery configurations nor is it the only measure that consumers consider as evidenced by the market share
of the refiner with the low energy content gasoline in Alberta.
The discussion of groups benefiting and being disadvantaged by ethanol tax incentives draws on two of the
US studies identified in the previous section, the Minnesota study and the 1997 GAO study. The Sypher
study concludes that corn and soybean prices would rise, as would meat prices caused by Ontario corn
supplying the ethanol for 50% of Canada’s gasoline. This conclusion is not the same as the GAO referred
to in the discussion. No attempt was made to determine the impact of higher agricultural prices on
government revenues. The report concludes that at current ethanol production rates the farmers receive no
benefit but at higher production rates the farmers would benefit at the expense of the general public.
7.3.2 Socio-Economic Impacts of the Pound-Maker Feedlot/Ethanol
Complex. Stabler, J.C., Brown, W.J., Olfert, M.R. September 1993.
The focus of this study was on the socio-economic impacts of the Pound Maker operation on the farms and
rural communities within 60 km of Lanigan, SK. The economics of ethanol production itself were not to be
studied and no proprietary cost of production information was to be published. The report considers the
combined costs and benefits of ethanol and cattle production. This limits the value of the report to its
specific scope and context.
The direct impact of the operation on the agricultural economy included the costs and benefits associated
with the crop production, manure utilization and the costs to government. Some of the findings include
slightly higher grain prices were paid by the facility than local elevators, there were reduced grain handling
costs for farmers and there were positive effects from the spreading of manure in terms of reduced fertilizer
costs and higher yields.
Farm profitability was considerably higher over both a five year period and a fifteen year period with
farmers who had more involvement with the Pound Maker operation.
The economic multipliers developed related to the impact on the local economy, not the provincial or
Canadian economies. They are lower multipliers applied in other studies. The local employment multiplier
is 1.39 and the local income multiplier is 1.32.
7.3.3 Kent Ethanol Feasibility Study. Chatham Ethanol Consortium. April
1993.
The primary focus of this study was to determine the financial feasibility of an ethanol plant in Kent
county. This study touched on some socio-economic elements. The benefits from a plant were described as
increased farm revenues, agricultural market diversification, reduction in government farm support, the
potential of new types of crops on less productive lands, a better air environment, and sustainable fuel
development. Since the actual size of a plant had not yet been determined the study did not attempt to
quantify the benefits from the plant development or from secondary development.
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7.3.4 An Assessment of the Costs and Benefits of an Ethanol Industry in
Alberta. Touche Ross, 1988.
This report reviewed an analysis undertaken by the Government of Alberta and refined the analysis based
on additional information the consultants obtained. The report concluded that an incentive level of 29 cents
per litre would be required to get the gasoline industry interested in ethanol. It was assumed that ethanol
plants would process barley and that a number of small 10 million litre per year plants would be
constructed. The study identified a number of Alberta-specific economic multipliers for ethanol plants.
The study found that there would be a net positive impact on the Alberta economy of $19.6 million per year
from the production and use of 130 million litres per year of ethanol. This impact was in the context of
about $200 million worth of economic activity (positive and negative) and within the level of detail
available, the consultants were not able to assign a 100% probability of a positive economic flow.
A number of key issues were identified including the impact on barley prices, incremental grain production
requirements, use of DDG in the cattle feeding industry, revenue gains to the agricultural sector, impact on
oil producers, refiners and marketers. The consultants concluded that there would be a small impact on
grain prices and that some of the grain required for ethanol production would be new production and some
would be a reallocation of exports. Very little credit was given to DDG as a protein source. It was assumed
to be used as a source of energy for the cattle. It was concluded that displacement of crude oil processed in
Alberta was not an issue as the oil would be absorbed by the export market. There would be some costs to
the refiners to incorporate ethanol into the product mix. These were estimated to be 1.5 cents per litre of
ethanol.
The major differences to the current study are the use of wheat as a feedstock for ethanol production, a
lower level of Alberta support required for the ethanol industry and a better understanding of the feed value
of DDG. Simply reducing the cost to the Alberta Treasury from the 29 cents per litre to 6 cents per litre (the
gasoline energy equivalent value of the provincial fuel tax exemption) dramatically changes the results. The
direct impact changes from a cost $12.3 million to a benefit of $18.2 million. By including the spin-off
benefits the net economic impact on the province increases from $19.6 million benefit to $89.7 million.
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7.4 Studies in Other Countries
7.4.1 Brazil
Brazil has the world’s largest ethanol fuel program. It has an economy very different from those of more
developed countries such that it is not practical to compare the impacts of the Brazilian ethanol program to
Canada.
A recent paper (Carvalho, 1999) on the economic impacts of ethanol in Brazil was presented at a
Governors’ Ethanol Coalition meeting. Some of the key features of the presentation were:



The Brazilian ethanol industry is a part of the larger sugar cane industry. The sugar cane industry
employs 1.3 million people in Brazil.
Ethanol production is used in part to support the sugar industry during periods of low world sugar
prices. The economic impact of the industry is dependent on world oil prices and on world sugar
prices. Brazil is still a net importer of oil. The sugar cane industry offsets this through sugar exports
and ethanol substitution for gasoline.
The sugar and ethanol industries are much more labour intensive than the oil industry with 152 times
as many jobs in the ethanol industry as the oil industry for an equivalent amount of energy production.
The degree of government intervention in the sugar, ethanol and oil marketplaces has been declining in
recent years. In 1975 when the Brazilian ethanol program was created the ethanol market and ethanol
production were heavily regulated. When oil prices fell in the late 1990’s some deregulation of the industry
was necessary as it became difficult to economically sustain the program. The industry’s health is now very
sensitive to world oil and sugar prices. At the current time with high oil prices and low sugar prices the
industry is flourishing. The government is currently attempting to encourage the production and use of pure
ethanol vehicles to increase demand for ethanol. Just two years ago when oil prices were much lower and
sugar prices were higher the industry was suffering economically.
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7.4.2 France
France is the only country in Europe with a significant commercial ethanol program. Fuel ethanol
production totals about 60 million litres per year. Wheat and sugar beets are used as feedstocks for the
plants. The crops are grown on agricultural set-aside lands. Farmers are paid to take land out of production
of food crops. Payments as high as $525/t are made. The land can be used for non-food uses such as
ethanol. In France the ethanol is used to produce ETBE for blending with gasoline. The ETBE qualifies for
a reduced taxation level. The incentive is approximately 75 cents per litre of ethanol. The combination of
set-aside payments, payments for the industrial crops and the tax incentives make the French program very
attractive for ethanol producers and users.
No detailed information on socio-economic impact analyses could be located for the French program.
Sourie reported that potential cost savings through economies of scale and R&D programs combined with
Macro Economic benefits convinced the French government to adopt the tax relief.
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8. Potential Socio-Economic Impacts For
Alberta
8.1 Summary
This analysis of potential socio-economic impacts related to more ethanol production in Alberta has
attempted to be consistent with the treatment of costs and benefits in other studies (i.e., with studies
reviewed above) as well as the assumptions with respect to energy and GHG emissions modelling. Direct
impacts are not estimated for all affected entities in the business system. Excluded from the analysis of
direct economic impacts are the transportation sector, grain elevators, machinery business and other
entities. Direct economic impact analysis for these sectors may require system optimization prior to
application of cost models that may not be suitable. Some of the indirect impacts on these and other entities
are inherently encompassed by the application of economic multipliers to direct costs and benefits. Neither
does this study estimate the economic impacts on human mortality or morbidity associated with changes to
environmental quality.
The basis of the analysis was the assumption that 200 million litres of additional ethanol would be
produced and used in Alberta. Although the analysis reflects potential increased ethanol usage in Alberta, it
does not infer any mandatory requirement for oil refiners, wholesalers, retailers or consumers to adopt
ethanol. The analysis estimates the economic implications if these entities were to voluntarily adopt
ethanol. Negative economic consequences identified in this study for some of these entities may relate to
the lack of a large ethanol fuel market in Alberta.
Two production scenarios were examined, the ethanol was produced in two large dry mill ethanol plants or
alternatively there were eight smaller ethanol facilities that were integrated into cattle feedlots. The costs,
benefits, employment impacts, government revenue impacts were calculated for each scenario.
There is an increase in total economic activity estimated for both ethanol production scenarios along with a
net increase in jobs across the whole economy. The impact on provincial government revenue is expected
to be essentially neutral with tax exemptions for ethanol fuel offset by increases in income taxes and other
government taxes and fees. The results are summarized in the following table.
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Table 118: Summary of Socio-economic Impacts
(Includes Direct and Indirect Impacts)
Assumptions
Size of plant (million litres/year)
Number of proposed plants
Total ethanol production (million litres per year)
Economic Impacts
Grain Producers
Ethanol Manufacturers
Government Expenditures
Consumer Spending
Oil Producers
Oil Refiners and Marketers
Net Annual Impacts
Plant Construction Impact (one time)
Small Scale Plant
Integrated to
Cattle Feeding
25
8
200
Large Dry
Milling plant
($ million)
($ million)
78.9
108.8
-18.0
-33.9
0
-3.3
132.5
29.1
129.7
-18.0
-33.9
0
-3.3
103.6
280
245
-13.77
9.31
7.65
3.2
-13.77
7.66
6.29
0.18
29.4
25.7
875
414
-600
689
323
492
-600
215
100
2
200
Impacts on Provincial Revenues
Provincial Tax Exemption
Provincial Income Tax
Other taxes and revenue
Net Annual Impact
Plant Construction Impact (one time)
Employment Impacts
Farm employment, direct and indirect
Ethanol plant employment, direct and indirect
Other sectors
Net Impact
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8.2 Scope and Methodology
The analysis that follows determines some of the important social and economic effects of an expanded
ethanol industry in Alberta. The analysis is limited to direct and only some of the indirect costs and benefits
arising from the potential production and use of ethanol in Alberta. Potential costs and benefits related to
human health and environment arising from the use of ethanol blended gasolines are among the effects not
quantified.
The analysis has been performed from an Alberta perspective. The costs of the Federal excise tax
exemption are not included nor are the benefits that would accrue to Federal government revenues from
increased economic activity.
The analysis has been performed at a general consolidated level. That is, the overall impacts on the
economy are quantified but an attempt is not made to allocate costs or benefits to all individual groups or
sub-sectors within the economy. That level of detail is beyond the scope of this study. There will be sectors
that benefit and some sectors that are disadvantaged by an industry as large as projected here. Some of
these indirect impacts are inherently accounted for through the application of economic multipliers.
The analysis is in the context of the assumption that the ethanol will be produced and consumed within
Alberta. This serves to define the impacts to stakeholders, although does not imply a requirement to buy
and use ethanol. If ethanol were not used in Alberta the costs and benefits will be different. It will be noted
in the following sections that the benefits flow primarily from the production of ethanol and the costs tend
to be associated with the use of ethanol.
8.2.1 Methodology
The base premise that has been used for the purposes of this report is that an additional 200 million litres
per year of ethanol would be produced and used in Alberta. Consideration is given to producing this in two
equal sized, large dry mill plants or in eight small plants that would be integrated with existing cattle
feeding operations. Under both plant scenarios CPS wheat would be the raw material processed. A
comparison of these two scenarios is provided to illustrate the different effects of these different potential
pathways for ethanol development in Alberta.
In the review of socio-economic studies performed in other jurisdictions it was apparent that a variety of
approaches have been used to evaluate the costs and benefits of ethanol production and use. The two basic
approaches were:
1.
2.
calculate the direct costs and benefits to government of an incentive program for ethanol and compare
it to the benefits of higher taxation or reductions in other government expenditures; and
calculate the total economic activity generated by an ethanol incentive and compare that to the
economic activity that would be generated by a tax reduction of an equivalent amount.
Some of the studies combined both approaches to provide the reader with more information while other
studies combined only parts of both approaches. The later can result in incomplete information being
presented.
The second approach may be more preferred by economists. The US General Accounting Office (1997)
states, “In preparing an overall cost and benefit analysis, the real benefits of a government program should
be measured in terms of the extent to which the program expands the total production potential of society.
Similarly the cost of a program should be measured in terms of the lost opportunity to increase production
under an alternative allocation of resources. A program would have a net benefit if it leads to a resource
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allocation that increases production and consumption above what they would have been under the best
alternative resource allocation.” They further state that the total production should include generation of
intangibles, such as energy security, and improvements in environmental quality. Quantitative assessment
of these intangibles is beyond the scope of this report.
A similar philosophy towards socio-economic analysis is presented on the Alberta Agriculture Web Site 61
describing the socio-economic impacts of hog operations in Alberta. An excerpt from that report follows.
“Economic impact analyses estimates the impact of economic decisions (i.e., expansion of hog
operations) on the output of goods and services in an economy and on employment and personal
income. It allows for an objective evaluation of the economic impact of a particular action or
project on the local economy. The flow of goods and payments through an economy may be
divided into two broad groups, basic and non-basic. The basic sector is made up of firms that sell
goods and services to businesses and consumers outside the local economy. The sale of these
goods and services bring new income into the local economy. Most agricultural businesses fall
into this category. This new spending by businesses and consumers from the outside provides the
base on which an economy can grow. Inflows include the sale, or export, of goods and services to
outside entities, investment income from external sources, and payments received from outside.
The non-basic sector is made up of firms that sell goods and services to local businesses and
consumers. Dollars remain in the local economy. Such businesses as grocery store and service
stations fall into this category. An economy can remain prosperous if the basic sector remains
strong.”
“An economic impact analysis is based on the concept of the multiplier. The multiplier is a
numeric value, greater than 1.0, representing the ratio of the total impact, or the sum of the direct,
indirect and induced impacts, to the initial or direct impact. Impacts can be expressed in terms of
direct, indirect and induced effects.



Direct effects are production, income, employment, tax, resource or environmental changes
associated with the immediate effects of a change to the total output of a basic industry of an
economy;
Indirect effects are production, income, employment, tax, resource or environmental changes in
backward-linked industries (i.e., suppliers to the hog operations), caused by the changing needs of
the hog operation, e.g., the additional purchases of inputs to produce more hogs; and,
Induced effects are the changes in regional household spending patterns caused by changes in
income generated from the economic activity of the hog operation.
The ultimate, total impact represents a multiple effect – the value of the multiplier – of the original
output within the hog industry. For every dollar in initial expenditures, total expenditures
throughout the entire economy will increase by a larger amount. The more pervasive the linkages
of the hog industry to other industries within the local economy, the greater this multiple effect.
For example, an increase in the economic output of a hog operation (direct effect) would cause
suppliers of such inputs as feed manufacturing, grain handling, veterinarians, trucking, equipment
suppliers, etc. to increase their production (indirect effect). The direct and indirect effects on
sales, employment, and income would cause household income and spending to increase in
general, further stimulating the economy (induced effect).”
This report follows the methodology recommended in the two references above. Where possible the data on
individual cost and benefit components is provided for comparison purposes.
61
http://www.agric.gov.ab.ca/livestock/exp_dev/index
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It must be acknowledged that economic analysis is not an exact science. As has been seen in the review of
the literature related to socio-economic effects of ethanol production, different economists have taken
different approaches to the subject. The following is one approach to the subject. It is similar to the
approach taken by some of the more detailed studies reported in the previous section.
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8.3 Impacts on Agricultural Sector
The production of 200 million litres per year of ethanol will require approximately 540,000 tonnes of wheat
per year. The ethanol plants would produce distillers grains that would replace some barley and canola
meal in animal rations in Alberta. The displacement ratios depend on how the distillers grain is fed to
animals. Farm income will increase due to the increase in wheat demand and a small increase in wheat
prices due to the increased demand. Farm employment will increase.
Table 119: Summary of Agricultural Sector Impacts
Ethanol Feedlot
Complex
274,000
266,000
0
$32.7 million
875
Net Wheat Requirements (tonnes)
Barley to wheat displacement (tonnes)
Canola to wheat displacement (tonnes)
Increase in Gross Farm Income
Increase in Farm Employment
Dry Mill Plant
350,000
0
190,000
$8.4 million
323
8.3.1.1 Feedstock Production and Farm Income.
The most direct impact on the agricultural sector is the requirement for grain as ethanol plant feedstock.
Production of 200 million litres per year of ethanol requires 540,000 tonnes of CPS wheat. This is less than
10% of the Alberta spring wheat crop but it represents about 18 to 25% of the Western Canada CPS
production (Manitoba Rural Adoption Council). This wheat use is not all new demand since the distillers
grains produced from the plants will displace some barley and canola meal from animal rations. Due to the
different uses of the co-products in the two types of plants under consideration, there will be differences in
the net feedstock requirements.
For the integrated ethanol plant feedlot complex, one tonne of wheat produces 370 litres of ethanol and
0.352 tonnes of WDG. This WDG replaces 0.49 tonnes of barley in the animal ration. (This was also the
basis used for GHG emissions and energy modelling). There is a price premium for wheat over barley most
of the time. A premium of $20 per tonne is assumed. The economic impact for this scenario will be from
274,000 tonnes of net new CPS wheat and the price premium for wheat over barley on a further 266,000
tonnes of CPS wheat that displaces an equivalent amount of barley production.
For the dry mill ethanol plant the gross wheat requirements and the amount of distillers grains produced is
the same but the assumptions on how the DDG is used has an impact on the grains displaced. One tonne of
DDG will replace one tonne of wheat and one tonne of canola to be consistent with the treatment given for
the GHG emission calculations. The net new requirements for wheat will be 350,000 tonnes with a
reduction in demand of 190,000 tonnes of canola where the lower value of the wheat must be accounted
for. A difference of $140 per tonne is assumed. It should be recognized that this is a worst case scenario, as
canola is grown primarily for its oil content and not its protein content. An alternative scenario would see
no change in canola production and an increase in canola meal exports. This was not the basis on which the
GHG calculations were made so it will not be the basis of the economic analyses.
It may be that an ethanol industry in Alberta could develop and result in no new production of wheat but
just a diversion of feedstock from the export market to a new domestic market. This scenario would result
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in less economic ouput than is calculated here. It is also a very different scenario with respect to greenhouse
gas emissions than shown in earlier sections. Greenhouse gas emissions associated with feedstock
production, fertilizer production, land use and feedstock transport would be eliminated from this analysis.
Since this incremental approach was not used for the GHG emission calculations it is not used for the
economic analysis.
In the GHG modelling it was assumed that new wheat production was required for ethanol production and
not just an allocation of existing production from the export market to ethanol production. This assumption
gave the most conservative results for GHG emission reductions. The impact on gross farm income is
therefore calculated from the incremental grain production calculated above. The impact for the two
ethanol production scenarios is shown in the next table.
Table 120. Changes in Gross Farm Income from Ethanol
Production in Alberta
Net Wheat Requirements (tonnes)
Net Wheat Requirements ($ value)
Barley to wheat displacement (tonnes)
Barley to wheat displacement ($ value)
Canola to wheat displacement (tonnes)
Canola to wheat displacement ($ value)
Total value
Ethanol Feedlot
Complex
274,000
$27.4 million
266,000
$5.3 million
0
0
Dry Mill Plant
$32.7 million
$8.4 million
350,000
$35 million
0
0
190,000
-$26.6 million
8.3.1.2 Handling, Elevator and Inventory Costs
Wheat producers may be able to save on all or a portion of the grain elevator and other third part handling
costs for the wheat delivered to the ethanol plant. Elevator costs to farmers are approximately 10 - 15
$/tonne. Wheat growers supplying ethanol plants may need to carry grain inventory and associated costs to
deliver product in equal amounts over the course of the year. What portion, if any, of these costs that would
accrue to the farmer may depend on contract and delivery arrangements made between the ethanol
producer, growers and others involved in delivery. This is an example of the local impacts that may occur
within a sector. Transport modes may shift from rail to road, and there may be lower throughputs in local
elevators. The total economic activity does not change if the prices for the wheat do not change but the
individual activities that comprise the total economic activity can change substantially. As a result there are
“winners and losers” within each sector of the economy. The identification of all these groups is beyond the
scope of this work.
8.3.1.3 Grain Prices
The magnitude of the impact on grain prices from an additional 200 million litres of ethanol is likely to be
very small.
Many of the socio-economic studies carried out in the United States have projected that corn prices are
higher due to the use of some corn for ethanol production. The estimates from the most comprehensive
studies range from 20 to 45 cents per bushel. Given the interdependent relationship between the Canadian
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and American grain markets, Canadian farmers also benefit from higher prices for feed grains because of
the US programs.
The reason for the relatively large range of projected impact on grain prices is that the impact can change
each year depending on grains usage and stocks. The USDA (Westcott) has developed models to predict
grain prices based on grain stocks and use at the end of the crop year. The equations are logarithmic and are
of the form shown in the next figure. Increasing corn usage lowers the stocks to usage ratio by impacting
both the numerator and the denominator in the equation and thus leads to higher corn prices. The results are
non-linear since the equation is logarithmic and partially explain the variance in projected results in the
literature. The impacts on prices are highest when the stock to use ratio is the lowest.
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Corn price $/bu
Figure 6. Corn Price Equation
6
5
4
3
2
1
0
0
10
20
30
40
50
60
70
80
Stocks to use ratio
Using the 5 cents per 100 million bushel ratio used for the Illinois study, the impact in Alberta would be
about 1 cent per bushel. This would impact all feed grains not just those used for ethanol production so the
total impact on Alberta farm incomes could reach $5.8 million. There would also be some impact on
Saskatchewan and Manitoba feed grain prices.
8.3.1.4 Farm Income Multipliers
The higher farm income creates increased demand for goods and services used on the farm and thus has a
multiplier effect on economic activity in the agriculture sector. The studies reviewed in the earlier section
used a range of multipliers. The Evans study had employment multipliers ranging from 1.78 to 2.74
depending on the state, the API study used 2.0 on primary farm income, and the Minnesota study used 1.53.
In Canada the Touche Ross study used 2.1 and the Alberta Hog study used values of 2.62 to 2.94 for all of
the non-wage inputs to a hog barn.
Statistics Canada provides ratios that relate changes in GDP to changes in gross industry value of output for
each sector. The Statistics Canada 1990 GDP ratio (GDP/$ of industry output shock) for the Agricultural
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sector for the Province of Alberta is 2.05.62 This ratio will be used here as the multiplier for the agriculture
sector. This ratio will be applied to the total increase in farm income calculated for the two cases including
the impact of higher prices. The total direct and indirect economic activity generated in the farm sector is
calculated and shown in the next table.
Table 121: Total Farm Economic Activity
($ million)
Ethanol Feedlot
Complex
$32.7
$5.8
Dry Mill Plant
Total Direct Income
$38.5
$14.2
GDP Ratio
2.05
2.05
Total Economic Activity from Grain Production
$78.9
$29.1
Gross Farm Income from Increased Production
Gross Farm Income from Higher Prices
$8.4
$5.8
There will be an increase in farm related employment due to the additional farm income. The total
employment impact is calculated in a later section.
8.4 Impacts from Ethanol Production
The impacts from ethanol production can be calculated in the same general manner as the farm income.
The grain purchases will be subtracted from the total ethanol and distillers grains revenues since this has
been dealt with in the previous section. The following table identifies the relevant factors needed to
calculate the economic activity caused by the production of 200 million litres of ethanol.
62
Statitstics Canada, Catalogue 15F0042XDB Interprovincial Input-Output Tables. Provided by System of
National Accounts, Input Output Division, Consulting and Marketing, Spreadsheet output (ALB 1990S.wk1) made available by Statitistics Canada Vancouver office. Data for year 1990 is latest available.
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Table 122: Ethanol Plant Expenditures
($ million)
Ethanol Feedlot
Complex
8
200
Million Litres
$80
112 $/t
$21.3
2
200
Million Litires
$80 million
160 $/t
$30.4
$101.3
$110.4
Grain Purchases
$54
$54
Number of Plant Employees
Total Wages
200
$8
100
$4
$39.3
$52.4
Number of Plants
Total Ethanol Volume
Ethanol Revenue
Distillers Sales Price
Distillers Revenue
Total Revenue
Net purchases (Sales - grain - wages)
Dry Mill Plant
In the previous table different values have been assigned to wet distillers grains from the integrated
complex compared to the dry mill plant. In the feedlot scenario it was assumed in the greenhouse
calculations that WDG replaces barley in the animal feed ration and is used for both its protein and energy
values. The price is based on the same displacement ratio to barley (1.4) as was used for the greenhouse gas
co-product credit. For the dried distillers grains the sales price is the market value based on current
conditions. The ethanol sales price is lower than current expectations but is typical of the expected price
based on the average crude oil values of the 1990’s. The ethanol sales price reflects the current Federal and
Alberta tax incentives for ethanol.
The multipliers developed for the Alberta Hog study ranged from 2.62 to 2.94 depending on the Census
Division. The StatsCan GDP ratio for Alberta manufacturing industries is 2.30. The lower multiplier of
2.30 is applied to the ethanol plant revenues adjusted for the grain purchases. The results are presented in
the following table.
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Table 123: Economic Activity from Ethanol Production
($ million)
Direct Economic Impact
(Revenue less grain purchases)
Ethanol Feedlot Complex
$47.3
Dry Mill Plant
$56.4
2.30
2.30
$108.8
$129.7
GDP Ratio
Total Economic Activity from Ethanol Production
8.5 Impacts from Capital Construction
The construction of new facilities such as ethanol plants create one time increases in economic activity. The
construction of new plants will not have as great a multiplier when viewed from a provincial or even
national perspective because some of the equipment will come from the United States or other foreign
countries. The GDP ratio will therefore be lower for construction expenditures. Statistics Canada has a
GDP ratio of 1.75 for Alberta Construction Industries. The one time economic benefits from ethanol plant
construction are shown in the following table.
Table 124. Economic Activity from Ethanol Plant Construction
($ million)
Ethanol Feedlot
Complex
8
$160
Dry Mill Plant
Economic Multiplier
1.75
1.75
Canadian Economic Activity
$ 280
$245
Number of Plants
Total Capital Cost
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8.6 Impacts from Government Expenditures
The use of 200 million litres of ethanol in Alberta will have a negative impact on Alberta fuel tax revenues.
Alberta has a gasoline fuel tax of 9 cents per litre that most alternative fuels do not currently pay. The
actual revenue loss to Alberta is on the gasoline displaced by the ethanol, since ethanol has a lower energy
content than gasoline 200 million litres of ethanol replace less than 200 million litres of gas. For the GHG
modelling it was assumed that a 10% ethanol blend achieved a 1% better energy efficiency than gasoline.
This results in about 2.5% poorer volumetric fuel economy. Using that same assumption the 200 million
litres of ethanol replaces 153 million litres of gasoline and the lost revenue to the province is $13.77
million. The consumer will purchase an extra 47 million litres of gasoline (200 –153 million litres) a year.
The lost revenue must be made up of taxes on other goods and services or alternatively it represents a
potential reduction in taxes if the ethanol was not supported. Taxes and tax reductions also have a
multiplier effect. Touche Ross used an Alberta multiplier of 2.3 in their 1988 work. The Minnesota study
used a multiplier of 1.18 for government expenditures. This multiplier was the factor for middle income
household expenditures and represented the impact of a tax cut for middle income taxpayers. Statistics
Canada does not have a multiplier for taxes in their database.
Statistics Canada’s average GDP ratio for secondary industries excluding construction is 1.31 and the
average multiplier for wholesale trade, retail trade, community, business and personal service sector, and
the finance, real estate and insurance sector is 1.24. It is assumed that these sectors are representative of
how consumers would spend any tax reduction that they received in lieu of supporting ethanol. Based on
using the value of 1.31, the impact on economic output to the provincial economy is $18.0 million
(1.31 X $13.77 million). The same value applies to both ethanol production scenarios.
8.7 Impacts on Consumers
Consumers will need to purchase more fuel if 10% ethanol blends are used due to the lower energy content
of the gasoline. Using the same fuel economy data as was applied in the previous section and assuming an
average gasoline price of $0.55 per litre, the additional expenditure on 47 million litres of gasoline is
$25.85 million. Assuming a multiplier of 1.31 the total impact on the economy will be $33.9 million.
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8.8 Impacts on Oil, Refining and Gasoline Marketing Sector
The analysis of the impact on the oil, refining and gasoline marketing sector in Alberta is in the context of
all of the ethanol produced in Alberta being consumed in Alberta. This is a hypothetical scenario
attempting to reflect some the potential impacts on the oil/refining/gasoline sector if gasoline wholesalers
and retailers required ethanol for their customers. This analysis does not imply any mandatory requirement
to adopt purchase ethanol. This is a conservative assumption (i.e., may overestimate the costs on this
sector) since a portion or all of the ethanol could be exported outside of the sales region of the Alberta oil
refiners.
8.8.1 Oil Production
The 200 million litres of ethanol that could be produced in these scenarios represents about 0.16% of the
crude oil produced in Alberta on an equivalent energy basis.
The majority of crude oil produced in Alberta is exported from the province. A small increase in the rate of
exports is not expected to have an impact on crude oil producers or prices. There is sufficient pipeline
capacity to move this extra oil out of the province. It is assumed that the price paid by export customers is
the same as that paid by domestic refiners for the same quality of oil.
There will be an increase in the costs of oil producers to pipeline oil to export markets which will relate to
increased revenues for the pipeline companies due to the extra volume shipped. This is not significant at the
level of confidence in the impacts being calculated.
8.8.2 Oil Refining, Blending, Wholesaling and Marketing
There is the potential for decreased output from the Alberta petroleum refineries due to displacement of
gasoline by ethanol. This displacement is 153 million litres per year or about 0.65% of Alberta’s current
refined products production. (This quantity takes into consideration the impact of ethanol’s lower energy
content.) There are a number of opportunities available to refiners to reduce this impact. Some of these
opportunities include:


adjusting the ratio of gasoline to diesel produced to produce more diesel fuel; and
export gasoline to the United States or other provinces.
Refiners in Western Canada currently import and export both gasoline and diesel fuel to the United States
at different times of the year. Diesel imports usually occur in the winter and gasoline imports are more
frequent in the summer. Substituting ethanol for gasoline will reduce the need for summertime gasoline
imports but will exacerbate the diesel situation in the winter for any refiner that is already operating at the
maximum diesel output condition and the opportunity for gasoline exports is reduced.
To determine the potential magnitude of the impact of reduced economic activity it is assumed that 50% of
the ethanol substitution results in reduced refinery throughputs and that the incremental value-added by the
refinery is 3 cents per litre. The reduced refining economic activity under this scenario is $2.3 million per
year. The Statistics Canada GDP multiplier for the manufacturing sector is 2.30 so the total potential
impact on the economic activity is $5.3 million. (153 million litres*50%*$0.03=$2.3 million)
At the retail level there will be an increase in sales due to the lower energy content of the ethanol blend.
The retail margin is assumed to be three cents per litre and it applies to the total increase in volume of 47
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million litres for a total impact of $1.4 million. The Statistics Canada GDP ratio for retail sales in Alberta is
1.28 so the benefit is $1.8 million per year.
These impacts do not reflect any additional costs that refiners, wholesaler or retailer would incur to handle,
blend, distribute and dispense ethanol/gasoline blends in Alberta. The magnitude of the costs will vary for
each refiner, wholesaler and retailer. If it is assumed that these costs are not passed on to consumers (all
gasoline is still sold at the same price) then these costs do not impact the on the output from the sector.
They do impact individual profitability of the sector participants.
For refiners and wholesalers these costs may be relatively high or can be negligible. Some
refiners/wholesalers that have closely examined the costs have found the costs can range from zero to 5
cents per litre of ethanol depending on the methods of handling and blending.
The ethanol price of 40 cents per litre used in this analysis is equivalent to 21 cents per litre after
consideration of the tax incentives. The retail gasoline price of 55 cents per litre is equivalent to 25 cents
per litre at the refinery rack. The difference of 4 cents per litre is sufficient to cover the costs of transporting
the ethanol to the refinery and blending it with gasoline. The direct economic activity resulting from this
handling cost is $8 million and with a multiplier of 1.47 for transportation and storage industries the total
economic impact is $11.8 million.
The net impact on the refining and marketing and transportation sector is a positive $8.3 million per year.
(The sum of -$5.3 + $1.8 +11.8 million dollars).
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8.9 Net Impacts on Economic Activity
The total impacts on the economy are the sums of the individual impacts calculated above. The results are
summarized in the following table.
Table 125: Summary of Economic Activity from Ethanol
Production in Alberta
($ million)
Farm Economic Activity
Ethanol Plant Economic Activity
Reduced Activity from
Government Expenditures
Reduced Activity from
Consumer Expenditures
Activity of Refineries &
Marketers
Total Annual Impact
One Time Impact from
Construction
Ethanol Feedlot
Complex
Direct
Indirect
Total
$38.5
$40.4
$78.9
$47.3
$61.5
$108.8
-$13.8
-$4.2
-$18.0
Dry Mill Plant
$14.2
$56.4
-$13.8
Indirect
$14.9
$73.3
-$4.2
Direct
-$25.8
-$8.1
-$33.9
-$25.8
-$8.1
$7.1
$1.2
$8.3
$7.1
$1.2
$53.3
$160
$90.8
$120
$144.1
$280
$38.1
$140
$77.1
$105
Total
$ 29.1
$ 129.7
-$ 18.0
-$ 33.9
$8.3
$115.2
$ 245
There is net economic activity generated in Alberta from an ethanol industry located in the province. The
difference between the two types of plants is caused by the different displacement ratios used for wet
distillers grains compared to dry distillers grains. A portion of the difference may be recovered if the
analyses were carried through the livestock sector. That analysis is beyond the scope of this work.
8.10 Employment
There are a number of ways of calculating the number of jobs that would be created by an ethanol industry.
The number of direct jobs in the ethanol plants can be determined accurately from extrapolating from
existing ethanol plants of a similar size and design to those envisioned here. That data was presented in an
earlier section. To determine the indirect employment created or lost Statistics Canada employment
multipliers can be applied. Such statistics indicate that Alberta manufacturing industries have 2.30 total
jobs for every direct job in the sector. This would suggest that a total of 460 jobs would be created from 8
ethanol plant feedlot complexes and 230 jobs from two larger dry mill facilities. This method probably
underestimates the number of jobs in the agricultural sector since they are lower paying than jobs in the
other primary industries.
Statistics Canada also data shows direct and total employment effects per $1,000 of output for the various
sectors. These are for 1990 and must be deflated for 2000 values. In the following table the direct and total
employment effects are calculated from these factors.
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Table 126. Calculated Employment Impacts
Ethanol Feedlot
Complex
565
310
875
Dry Mill Plant
Ethanol Direct Jobs
Ethanol Indirect Jobs
Sub Total
180
234
414
214
278
492
Total
1289
815
Agriculture Direct Jobs
Agriculture Indirect Jobs
Sub Total
208
115
323
The second method is probably more representative of the total employment in a large ethanol industry in
Alberta. These employment rates are within the ranges found in the socio-economic studies performed in
the United States. It must be remembered that the assumption was that new grain production occurs due to
the demand for ethanol. If this is not the case then fewer agricultural jobs will be created but greater
greenhouse gas emission reductions will occur.
The negative economic impacts identified will have a negative impact on job creation. The negative
impacts totalled $39.6 million from tax losses and increased expenditures on fuel. The impact on refiners is
excluded because the incremental impact is too small to have a direct impact on employment. Using the
same methodology as for the creation of ethanol jobs and using the employment impacts for the service
industries adjusted to 2000 there is the potential of 600 jobs negatively impacted from the expenditures.
The net impact on employment is expected to the creation of 215 to 689 jobs.
8.11 Government Revenues
The impact of the fuel tax exemption is the most significant and easiest to measure impact on Government
revenues, however it is not the only impact. There are a number of smaller impacts as a result of the
increased economic activity. These include personal and corporate income taxes, taxes on fuel used to
move the additional goods to markets, taxes on goods such as liquor and tobacco, payments for government
services such as Workers Compensation, property taxes etc.
To estimate the magnitude of these revenues information from the Alberta budget for 2000 is used.
Government revenues are estimated as a function of the provincial GDP. The following table summarizes
that budget information. Not included in the total is revenue from resources, federal transfers and
investment income.
Table 127: Key Alberta 1999 Economic Data
Item
Value
($ billion)
$113.8
Gross Domestic Product
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Personal Income Tax
Corporate Income Tax
Other Taxes
Other Revenue
$4.98
$1.56
$2.35
$3.02
Total
% of GDP
$11.91
10.5%
This data can be applied to the increased in economic activity projected from the expansion of an ethanol
industry. The government revenue factor is applied to the increased economic activity excluding the impact
of the tax exemption since the goal of the exercise is to compare government expenditures and revenues.
The impact on government revenues is shown in the following table.
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Table 128: Impact of an Expanded Ethanol Program on
Government Revenues
GDP
($ million)
Fuel Tax Exemption
GDP from Plant Construction
GDP from Ethanol Program
$245 to $280
$133.2 to $162.1
Government
Revenue
($ million)
-$13.77
$25.7 to $29.4
$13.95 to $16.97
$0.18 to $3.2 million
Total Annual Impact
Excluding Plant
Construction
The projected impact on an annual basis is neutral to a small positive impact on government revenue when
the impact of plant construction is excluded. Amortization of the positive impact of government revenues
from the plant construction would provide a positive annual impact on government revenues.
Governments may chose other methods of analysis of policy options instead of the examples calculated
here. The important factors with respect to ethanol incentives are that the true cost to governments is less
than a simple extension of the per litre incentive and the volume of ethanol consumed. There are benefits in
the form of increased tax revenues (including increased gasoline sales) from increased economic activity
that must also be considered.
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9. Ethanol Policies in North America
9.1 Ethanol Programs in the United States and Canada
Many U.S. states and Canadian provinces have favourable ethanol policies and offer incentive programs to
encourage the production and use of ethanol as a blend with gasoline for transportation fuel. The magnitude
of the value of these incentive programs varies substantially. The programs typically feature tax exemptions
such that their value depends on the existing fuel tax regimes in each jurisdiction. For example, if a
particular jurisdiction applies a high tax level on gasoline sales, for ethanol that is exempt from this tax the
value of the incentive will be high in that jurisdiction, since it will allow ethanol sellers to charge a similar
price to gasoline that is fully taxed. The policies and incentives related to ethanol are constantly changing.
This analysis presents the circumstance as identified in the last quarter of 1999 and the first quarter of 2000.
In the United States, a federal exemption of 4 cents per gallon for alcohol fuels was initiated with the
enactment of the Energy Tax Act in 1978, representing the full amount of the Federal gasoline tax. The last
change to the federal tax incentive came with the Omnibus Budget Reconciliation Act of 1990 that
established a rate of 5.4 cents per gallon of motor fuel containing 10% alcohol by volume. This translates
into a 54 cents tax exemption per gallon (~20 Cdn¢/litre) of ethanol. The act also introduced a tax credit of
10 cents per gallon of ethanol for small producers (producing less than 15 million gallons per year). The
Energy Policy Act of 1992 extended the tax exemption to ethanol/gasoline blends containing less than 10%
alcohol. Mixtures containing 7.7% alcohol receive an exemption of 4.16 cents per gallon, and the
exemption for the 5.5% mixture is 3.08 cents per gallon.
The government ethanol policies in the U.S. states vary and can range from no incentive for ethanol to tax
exemptions coupled with producer subsidies, loans and other vehicles to promote production and use of
ethanol in the jurisdiction. Minnesota, Missouri, Kansas, Montana and North Dakota are some of the states
that have favourable ethanol programs that feature producer incentives. In these states grain growing (or
agriculture) usually forms an important component of the economic infrastructure. States that have small
grain growing industries are less likely to offer highly attractive ethanol policies. Some states are in the
process of reviewing the overall attractiveness of their programs.
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Table 129: U.S. State Government Policies Supporting Ethanol63
State
Alaska
State Excise Tax Exemption
$0.08 per gallon tax exemption for E10
State Producer Credits
No producer payment
Connecticut
$0.01 per gallon tax exemption for gasoline
containing a 10% ethanol content.
4% tax exemption on gasoline products
containing 10% biomass derived ethanol.
Provides a fuel excise tax exemption for
biofuels up to $0.21 cents per gallon for
E10.
2% sales tax exemption for gasoline
containing at least 10% alcohol which is
produced from agricultural products.
No producer payment
Special Information
Tax exemption applies only in Anchorage
and only during the winter months
Anchorage requires all vehicles use E10.
No sunset
No producer payment
No sunset
No producer payment
No sunset
No producer payment
Indiana
None
No producer payment
Iowa
$0.01 tax exemption for gasoline containing
at least 10% alcohol which was produced
with agricultural products grown in the U.S.
Iowa Corn Promotion Board is sending their
economic impact study on the Iowa ethanol
industry
No producer payment
Sunset (7-1-99) legislation is underway to
extend sunset to 2003.
30% reduction in taxes on proceeds of
sales of gasohol before July 1, 2003 exits.
Government vehicles mandated to use
ethanol blended fuels
Provides a 10% gross income tax
deduction for improvements to ethanol
production facilities.
Subsidized Loans Grants for construction
of ethanol facilities (among other
qualifying facilities). Cap of $900,000 per
facility.
Government vehicles mandated to use
ethanol blended fuels
Hawaii
Idaho
Illinois
63
Renewable Fuels Association; Clean Fuels Paving the Way for America’s Future, 3 rd edition, 1998; California Study; Iinterviews with state agencies.
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State
Kansas
State Excise Tax Exemption
No tax exemption; had blenders tax around
12-13 years ago
Minnesota
No tax exemption on 10% blend (was $0.02
which was stopped in 1997), $0.058 tax
exemption on E85
Missouri
Excise tax exemption of 2 cents per gallon
exists for ethanol/gasoline blends which
have 10% or greater ethanol content.
State Producer Credits
Avg. $0.07 per gallon; total funds
available are $2.5 million annually which
is divided by the total gallons produced
annually (approximately 43-45 million) to
reach the approximate $0.07 per gallon
producer incentive; fund created in mid1980s; all existing ethanol plants were
already operating when the fund was first
created.
$0.20 per gallon producer credit through
to 2010; applies to up to 15 million
gallons per year maximum (i.e. Maximum
of $3,000,000 per facility per year); each
plant qualifies for 10 years (i.e. Maximum
of $30,000,000 over the lifetime of the
facility). No funds are left for new ethanol
production facilities however. Program
expires June, 2010.
$0.20 per gallon applies to the first 12.5
million gallons, $0.05 per gallon applies
to the next 12.5 million gallons; no credit
for production above 25 million gallons;
maximum of $3,125,000 per facility per
year; ethanol has to be produced using
Missouri agricultural products;
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Special Information
$2.5 million is split amongst all producers
(there are 4 currently); for several years
the payout was approximately $0.08-0.09,
but capacity expansions has decreased the
average pay-out to around $0.07; there is
a limit of $0.20 per gallon that has been
established; sunset 2001
No loan guarantees specific for
constructing ethanol facilities are in place
Subsidized loans of up to $500,000 per
plant for construction of ethanol facilities
(loans are at 4% or half of what the
current rate offered by banks). Revolving
loan account, however no money is
currently in the account.
State-wide year round use of motor fuel
with 2.7% oxygen mandated in 1997.
Only state with such a requirement
(Nebraska, Iowa are assessing the
potential of this requirement)
The state of Missouri has $6 million set
aside for the producer credit program;
producer credit is only eligible for 60
months of operation. Program just
recently got extended to 2007.
Requirement that 50% of all state vehicles
run on e10 by 2000.
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State
Montana
State Excise Tax Exemption
No tax exemption
State Producer Credits
$0.30 per gallon producer credit (ethanol
has to be made from Montana agricultural
products); funding has a $6,000,000
annual cap with a $3.0 million annual
company restriction. The policy is in
place to 2005.
Nebraska
No tax exemption
Past tax exemption of 5 cents per gallon was
stopped around 1992, with the funds being
utilized to provide new tax credits to ethanol
producers.
Policy Being Phased-Out This Year
$0.20 per gallon producer credit if
produced from cereal grains or domestic
agricultural commodities; applied to
facilities with a minimum production of 2
million gallons and was capped at 25
million gallons annually per facility;
maximum of $5,000,000 per year per
facility for 5 years
$0.50 per gallon tax credit for ETBE
made from ethanol produced in the state.
Policy Being Phased-In This Year
0.075 per gallon credit for ethanol
produced at new facilities or in expanded
capacity at existing facilities on
production up to 10 million gallons
annually for a period not to exceed 3
years.
183
Special Information
New business incentive in place were
property and equipment taxes have been
reduced to 3% (from around 11% - varies
by county) for the first 10 years of any
new ethanol plant or expansions to
existing plants (in place to 2005)
E85 infrastructure grants to convert
service stations. Total of $45,000
available to June 2001.
State law requires that all state vehicles
be fueled with ethanol gasoline blends
when competitive with gasoline.
Policy Being Phased Out This Year
Producer credit applies for the first 60
months of any plant operational prior to
12-31-95
Government vehicles mandated to use
ethanol blended fuels
CHEMINFO
State
New Mexico
State Excise Tax Exemption
Partial exemption of fuel excise tax provides 4
cents per gallon benefit for all alternative
fueled vehicles - phased in over 6 years. .
None
State Producer Credits
No producer payment
North Dakota
No tax exemption
$0.40 per gallon producer credit if
derived from agricultural products; up to
750,000 gallons per facility. A total of
$3,657,000 was appropriated to fund this
producer incentive in 1995.
Ohio
Provides a $0.01 per gallon income tax credit
for sale of E10 with a maximum of $15 million
per year.
None
No producer payment
South Dakota
$0.02 tax exemption (if the ethanol component
is 98% pure and is derived from cereal grains)
for E10 and $0.12 for E85
Wyoming
$0.04 tax exemption for 10% ethanol blended
fuels (available to June, 2000). Issues credit
vouchers to ethanol producers which are
redeemable by gasoline wholesalers with tax
liability (E10) or gasoline.
$0.20 per gallon producer credit (if
produced from cereal grains and blended
with gasoline); plant had to be
constructed after July, 1986; maximum
of $1,000,000 per year per facility with a
cap of $10,000,000 over the lifetime.
No producer payment
North
Carolina
Oregon
No producer payment
No producer payment
184
Special Information
Since 1987 has provided corporate and
personal income tax credit for
construction of some ethanol plants.
Producer credit applies only to ethanol
that will be sold in the state of North
Dakota. Sunset 2007
All state vehicles must be fueled with
E10 when possible.
Loan guarantees are available for
construction of ethanol plants.
Fleets in three state agencies have to use
E10 whenever possible.
Five year, 50% property tax exemption
of new ethanol production facilities;
incentive is effective through 2008.
$1 million per year limit - sunset $10
million cap
Government vehicles mandated to use
ethanol blended fuels
Effective through July 2000.
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In Canada, the federal government excludes ethanol used as transportation fuel from excise tax. This
represents a 10 ¢/litre exemption for the ethanol portion used in gasoline. The provincial governments have
different rates of tax on gasoline and therefore the value of exemptions varies. Provincial tax exemptions on
ethanol used in gasoline were not identified for the Atlantic provinces.
Table 130: Provincial Tax Exemptions for Ethanol
Transportation Fuel
Province
Provincial
Exemptions for Ethanol
Ontario
14.7 ¢/litre
Quebec
16 to 20 ¢/litre
106% to 130% of 15 ¢/litre
Manitoba
25 ¢/litre*
Alberta
9.0 ¢/litre
B.C.
11.0 ¢/litre only for E85
Saskatchewan
15 ¢/litre
Source: Cheminfo Services Inc.
Includes provincial tax exemption of 11.5 ¢/litre plus 13.5 ¢/litre producer incentive.
9.1.1 Quebec’s Ethanol Policy
The rationale underlying Quebec’s favourable ethanol policy relates mainly to fostering economic
development. Specifically the provincial government, led by the Energy Division within the Ministry of
Natural Resources (which includes the Oil and Gas group) expects positive net socio-economic benefits
from the construction and continued operation of a large ethanol plant in Varennes, QC. The ethanol policy
is not driven by environmental concerns of expected benefits. According to Quebec’s Ministry of Natural
Resource officials, some environmental organizations do not regard ethanol as an optimal solution for
pollutant reduction in transportation.
According to Quebec government officials, Commercial Alcohols is still evaluating the project.
Construction has not been initiated. Costs of construction and related financing are reported issues. The
proposed plant would have a capacity of 110 million litres per year, with the possibility to expand capacity
to 150 million litres per year. Petro-Canada would be a major potential customer for the facility, taking the
majority of the output for use in gasoline blending. The Quebec Liquor Control Board would take a portion
of the remaining production.
The tax policy to support the new proposed plant features a tax exemption equal to between approximately
106% and 130% of the provincial road tax of 15 ¢/litre. This equates to approximately 16¢ to 20 ¢/litre of
ethanol. A formula would be used to calculate the exact amount of the exemption. The amount of the tax
exemption could reach approximately $30 million per year if the production reaches 150 million litres per
year. The exact formula to be applied in the calculation has yet to finalized, so that there is not certainty
with respect to the final amounts. The federal tax exemption of 10 ¢/litre would continue.
There is also some uncertainty with respect to whether the flow of funds regarding the exemption. Since the
amount of the incentive exceeds the tax exemption amount, the question arises as to who should receive the
excess (difference between the 15¢ and 16 to 20 ¢/litre.). The tax exemption is not applicable to the
existing Tembec facility in Quebec that relies on spent liquor biomass for ethanol production. This facility
currently does not have the capability of supplying the anhydrous ethanol required for the fuel market.
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9.1.2 Saskatchewan’s Ethanol Policy
The Saskatchewan government’s ethanol policy was recently changed in its March 2000 budget. The
province reinstated an exemption of 15 ¢/litre for ethanol blended with gasoline in the province up to 10%
content64. (Such an exemption had existed in the early 1990s, but was phased out in the 1994/95 period).
The exemption has a maximum value amount that corresponds to some portion of the ethanol produced and
sold in Saskatchewan (quantities not clear and could escalate over time). Essentially, the policy assists the
existing producer in Saskatchewan to compete with producers enjoying similar programs in other
jurisdictions. (The term of the policy is believed to be 5 years, although this is not confirmed. Written
details of the policy were requested but were not available in time for preparation of this report.).
Saskatchewan is also considering special programs aimed at attracting potential new ethanol plants to the
province. These may require special incentive programs.
9.1.3 Manitoba Ethanol Policy
The Manitoba government exempts ethanol from provincial tax (11.5 ¢/litre) and provides a 13.5 ¢/litre
incentive for the single ethanol plant in the province. The total incentive for ethanol, including the Federal
exemption of 10 ¢/litre, is 35 ¢/litre.
64
Personal conversation with Eugene Bendig, Manager Industrial Development, Industry Development
Branch, Saskatchewan Agriculture and Food. March 2000.
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10. Stakeholder Input and Additional
Considerations
10.1 Introduction
This section provides analysis of additional policy considerations. 65 In many cases these additional
elements were identified by stakeholders as being important for consideration in the Committee's
deliberations regarding ethanol policy. Groups of stakeholders that were contacted to obtain input included:









oil refining companies not blending ethanol with gasoline;
oil refining companies blending ethanol with gasoline;
gasoline wholesalers/retailers not blending ethanol with gasoline;
gasoline wholesalers/retailers blending ethanol with gasoline;
Alberta Environment;
Alberta Economic Development;
existing and potential ethanol producers;
farm co-operatives, the Canadian Wheat Board; and
related industry associations.
There is quite a large and diverse set of perceptions surrounding ethanol among the stakeholders contacted.
For most issues identified by stakeholders, the consultant conducted follow-up research and analysis to
clarify some input and provide additional context. However, the depth of analysis may be limited in some
areas, since the number of issues and divergence of stakeholder input was in some cases substantial and
could not be resolved in the context of this study. To address and resolve some technical, economic and
other issues identified by stakeholders requires further focused and detailed analysis, beyond the scope,
purpose and resources available for this study. Areas where further research could be conducted have been
identified.
10.1.1 Written Input From Canadian Petroleum Products Institute (CPPI)
The Canadian Petroleum Producers Institute (CPPI) is an organization representing oil refiners and
marketers in Canada. Most of the companies operating refineries in Canada are members of the
organization. Exceptions are Irving Oil in New Brunswick, North Atlantic Refining in Newfoundland, and
Consumers Co-op in Regina, SK.
The CPPI provided a written submission as direct input to the Committee for their consideration in
preparing this report and developing suitable ethanol-related policies.66 This section documents that input67,
and provides some additional information and context based on follow-up research and analysis. The field
research included telephone interviews of 5 members of the CPPI (asterisked below in table), interviews of
other stakeholders along with literature review and analysis of related information sources. Some issues
identified by the CPPI are covered in previous sections of this report and are not analyzed further in this
section.
65
Additional to any environment, energy and socio-economic factors covered in previous sections.
CPPI, January 2000. Fax from Alberta Grain Commission to Cheminfo Services Inc., January 11, 2000
67
Input regarding environmental and socio-economic considerations are dealt with elsewhere in this report.
66
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Table 131: CPPI Member Companies – 1999
Refining and Marketing Members
Chevron Canada Ltd.
Husky Oil Operating Ltd.*
Imperial Oil Ltd. *
NOVA Chemical (Canada) Ltd.
Petro-Canada *
Shell Canada Products Ltd. *
Sunoco Inc., Suncor Energy Inc. *
Ultramar Ltd.
Marketing Members
ARCO Products Company
Canadian Tire Corporation Ltd.
Safety-Kleen Canada Inc.
* Interviewed for this study
Location
Vancouver
Calgary
Toronto
Sarnia
Calgary
Calgary
North York
Montreal
BC
AB
ON
ON
AB
AB
ON
QC
Los Angeles
Toronto
Breslau
CA
ON
ON
Some members of the CPPI purchase ethanol for blending into their gasoline products. Therefore, their
experience, perspective and orientation toward ethanol are different than those members that are not using
ethanol. A major reason for the different views on ethanol is the different business, operating and
marketing orientations of the different organizations. These differences are, in part, due to the competitive
nature of the oil refining and gasoline markets. Refiners have different oil refining capabilities, raw
materials, regional or product market strengths, as well different blending, storage and product distribution
systems. Companies, in general, use different strategies in the competitive business dynamic.
In general, most of CPPI’s input seems to be the context of a mandatory requirement to use ethanol in
gasoline in Alberta. In this study, the information and analysis surrounding CPPI’s as well as other
stakeholders’ input should not be interpreted as intending or implying any mandatory requirement to use
ethanol in gasoline blends in Alberta.
10.2 Scope of Analysis
Some stakeholders had input on the scope and purpose of this analysis. The scope, approach and research
methodologies for this study were determined in the context of the Committee's original Terms of
Reference, time and resources available to undertake analysis as outlined in the consultant’s competitive
proposal. Similar to other ethanol studies reviewed, this study is limited in scope and does not address all
possible social, technical and economic elements involved with the ethanol industry and related business
areas. Although this study (as others) may exclude analysis of some elements the results meet the
objectives of the project and the client’s requirements. A balanced presentation of available literature and
analysis is provided and any exclusion (due to scope limitations) is not an attempt to mislead or confuse.
The CPPI expressed concern regarding the scope of analyses that are typically carried out.

…CPPI is not positioning these comments as conclusions that should be drawn by the
study but as issues that need to be addressed by this study or a subsequent review. We
expect opinions may vary, even within the CPPI, as to the relevance of these factors and
the degree of uncertainty that exists. Nevertheless, an assessment of ethanol
use/production without the inclusion of these issues would be incomplete and the ability
to make sound policy decisions on ethanol support would be compromised.
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
A comprehensive technical review of ethanol covers a wide spectrum of economic,
environmental and technology related issues. In past studies, CPPI has been concerned
that not all impact areas have been considered or we may disagree whether an impact
exists or the estimated magnitude of certainty of an impact. In some cases CPPI believes
that selected information has been used which misleads or confuses the reader with
respect to relevant factors. This can have serious consequences.
Available literature reviewed for this project is similarly limited in scope and unique approaches and
methodologies are applied to meet specific study objectives. This does make comparison of different
studies difficult. Due to limitations of scope, approaches and methodologies chosen, some elements of the
complex business system surrounding ethanol are not fully analyzed in these studies (similar to this
project). Readers and decision-makers need to keep in mind the scope and limitations of this and other
studies to avoid incorrect interpretation and conclusions.
10.3 Environment Perspectives
Although not unanimous, the general consensus among stakeholders interviewed for this project is that
ethanol provides overall environmental benefits. The CPPI points out that there are both positive and
negative aspects ethanol as a transportation fuel as it relates to VOC, NOx, CO, PM, SOx (the criteria air
contaminants or CAC), greenhouse gases and toxics emissions. However, there exists conflicting
information and perceptions even among CPPI members as well as other stakeholders interviewed in this
study with respect to magnitude and accuracy of environmental advantages and disadvantages of ethanol.
This study does include a comprehensive lifecycle-based analysis of environmental implications for ethanol
with explicit assumptions. However, similar to any study, simplifying assumptions are made. In the
ongoing process of refining these estimates over time, other assumptions based on improved information or
different scope may be more appropriate.
10.3.1 Alberta Environment and Bureau of Climate Change Input
Currently, it is premature to determine the priority of ethanol as an environmental or climate change
management tool for development by Alberta Environment. Although ethanol does yield overall reductions
in criteria air contaminants (CAC) and GHG emissions, it may be part of a bundle of options to achieve
environmental results, rather than a measure in isolation.
One consideration is the degree of air quality improvement required in Alberta. Urban centres such as
Calgary and Edmonton are generally meeting current National Air Quality Objectives, as reflected by the
Air Quality Index. This does not mean that ethanol would not be environmentally favoured if used in
gasoline blends since improvements in air quality would be expected, even though general objectives are
being met most of the time. Ethanol blends would improve air quality for some contaminants (e.g., carbon
monoxide), but may not improve with respect to some other contaminants (i.e., NOx, aldehydes).
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Table 132: Ambient Air Quality in Edmonton and Calgary
(percentage of time achieved during year)
Air Quality Index
Good
Fair
Poor
Edmonton
1998
1999
93.58%
98.63%
6.3%
1.37%
0.06
0%
Calgary
1998
1999%
99.49%
99.78%
0.51%
0.22%
0%
0%
Source: Alberta Environment, Personal conversation Long Fu Environmental Sciences Division, .
The province is also expected to be able to meet the new proposed Canada-Wide Standards (CWS) for
particulate and ozone concentrations that are due to come into effect in 2010 and 2015, respectively.68
Table 133: Current and Proposed Canadian Air Quality
Standards69
Contaminant
Particulate (PM2.5)
(particles less than 2.5
microns in diameter)
Ozone
Current
National Objective
no current objective
82 parts per billion – 1 hour)
(equivalent to 65 ppb –8 hour)
Proposed
Canada-Wide Standards
30 µg/meter3
(24 hour average)
(effective 2010)
65 ppb –8 hour
(effective 2015)
All provinces and the federal government are actively engaged in the National Climate Change Process
(NCCP) that is developing a strategy to addresses Canada’s Kyoto Protocol commitment for a 6%
reduction in greenhouse gas emissions over the period 2008 to 2012, versus 1990. Alberta has taken a
proactive step in establishing the Bureau of Climate Change, which is made up of Alberta government,
industry and other stakeholders. This group will identify GHG emission reduction opportunities and
recommend measures to address Alberta’s future obligations. One Alberta Environment representative on
the Bureau did not view ethanol as a priority tool for addressing GHG emissions from transportation within
the province’s climate change overall strategy. There may be better options for the province. However,
Alberta’s strategy to address GHG emissions is under development, such that ethanol may turn out to be a
more important element in the future.
10.4 Refinery, Wholesaler, Retailer Considerations
There are technical and related economic considerations associated with any potential changes involving
blending ethanol with gasoline. These considerations embrace the complete fuel production and delivery
system, including oil refinery, blending, transportation, storage and retail operations.
68
Personal conversation with Long Fu, Alberta Environment, Environmental Sciences
Canadian Council of Ministers of the Environment (CCME), Canada-Wide Standards for Particulate
Matter (PM) and Ozone, Accepted November 29, 1999. For endorsement in May 2000. Nov., 29, 1999.
69
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In general, the technical issues and magnitude of costs or potential benefits associated with incorporating
ethanol into gasoline are company specific. Refiners, wholesalers and retailers that are not using ethanol
have technical and economic concerns. Refiners, wholesalers and retailers that are using ethanol have
overcome technical and economic hurdles. The study provides input from both types of stakeholders.
However, it is beyond the scope of this study to undertake any company-specific analysis of the merits or
drawbacks of ethanol.
10.4.1 RVP Considerations
Regarding vapour pressure of fuels, CPPI points out that:


Producing an ethanol blended gasoline requires a low RVP base stock gasoline. The
typical summer gasoline would have 72 kilopascals (Kpa) vapour pressure such that
adding even a small percentage ethanol (e.g., 10%) would increase vapour pressure by 7
Kpa. To compensate, refiners will need to install facilities to remove butane from
gasoline. Market conditions will dictate the value of the butane removed. In the past, the
value of butane has typically decreased from gasoline value to fuel value if a suitable
market isn’t found. This represents a significant economic loss for a refiner.
Some refiners will have to remove both C4-butanes and C5-pentanes to meet the RVP
spec, especially if condensate makes up a substantial portion of their feedstock.
Input from oil refiners contacted for this study pointed out that the economics of excluding butane,
pentanes and/or propane from gasoline and using ethanol are refinery specific, such that individual refiner’s
circumstance and economics vis-à-vis ethanol will vary. Typically, some butane is added or merely
excluded from gasoline blends as part of normal refinery and blending operations, depending on seasonal
RVP requirements and other refinery–specific considerations. The amount of butane (and/or pentanes
and/or propane) that would potentially be excluded from gasoline to accommodate any ethanol, which may
be used, would need to be defined for each refiner. This quantity is not necessarily equal to the amount of
ethanol blended in the gasoline, according to some refiners.
The research for this study found one refiner that did not require the installation of additional refinery
facilities to remove butane from gasoline to accommodate ethanol. This refiner pointed out that butane
(similar to ethanol) can be considered as an additional blending component of the many blending
components available to refiners (i.e., a range of different hydrocarbons) to meet product specifications.
However, in some cases, additional refinery facilities may be required, the costs of which would need to be
defined by the refiner.
Any displaced butane would require less production or disposition in alternative markets for butane. Most
of the butane (and propane) consumed in Canada originates in Western Canadian provinces. Some of the
quantity is pipelined from western Canada to Ontario, where natural gas liquids (NGLs – e.g., propane and
butane) is separated and stored before being sold. Most of the butane (and propane) storage capacity in
Canada is in very large underground salt storage caverns. Butane can be stored in above ground metal
spheres, although the quantities these containers can accommodate are much lower than underground
caverns. When demand for propane and butane is lower during the summer, it is stored and brought up
from the caverns in the winter months for use in heating fuel, transportation gasoline blending or other
markets. Propane and butane have a variety of alternative market applications to straight blending with
gasoline. Some of these applications (including some fuel markets) feature higher market prices than
blended gasoline.
Table 134: Canadian Market Application for Propane and Butane
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Applications
Petrochemicals
Butane
Used for MTBE in Alberta
Used in Quebec,
Sarnia depending on value
Alkylate feed.
Packaged fuel, heating
Refinery
Retail
Solvent flood for
enhanced oil recovery
Export
Mostly in AB All in Western Canada.
Exported from western and eastern
provinces. Mostly to USA.
Propane
Some use in Alberta
Used in Sarnia
Alkylate feed. Polygas feed.
Packaged fuel (e.g., BBQs),
heating, some transportation use
Mostly in AB.
All in Western Canada.
Exported from western and eastern
provinces. Mostly to USA
The total amount of propane and butanes produced from gas plants in Canada is on the order of 17 billion
litres per year70, of which butane represents nearly 35-40%. Additional amounts are produced from crude
oil refining operations, ethane straddle plants in Alberta and petrochemical facilities in Alberta, Ontario and
Quebec. Total butane and propane production (including refineries and petrochemical facilities) in Canada
is roughly 20 billion litres/year (1997). The amount of displaced butane potentially resulting from ethanol
blending in gasoline in Alberta (not prescribed) is very low and should not result in significant market
effects. However, impacts may be significant for some refiners.
Table 135: Historical Uses for Butane and Propane
Applications
Butane
Exports
30-40%
Refinery
25-40%
Retail
10-15%
Petrochemicals
5-15%
Solvent flood for oil recovery
1-5%
Other applications
0-5%
Source: Natural Resources Canada. NGLs Report
Propane
35-50%
1-3%
35-45%
10-15%
5-10%
0-5%
The CPPI points out that some refiners may have to displace butanes or other light hydrocarbons from
gasoline to meet RVP specifications, especially if condensate makes up a substantial portion of the their
feedstock. The CPPI indicates that storage and disposal of butane can be a significant economic issue, if the
displaced butane has to be shipped over long distances, or is used as a low price fuel. The potential cost of
storage, transportation and alternative disposition (fuel or otherwise) that may need to be incurred is not
estimate in this study. Such an estimate would require detailed investigation and optimization of refinery
operations, transportation and storage systems. However, costs associated with a relatively low amount of
butane (especially in proportion to the total butane in the market) displaced by ethanol are likely to be quite
low in most cases.
In some cases, the potential replacement of light hydrocarbons with ethanol can provide an advantage for
refinery logistics and economic benefits. One refiner that blended ethanol with gasoline found there were
economic advantages in being able to use heavier gasoline base stocks with ethanol. Linear programming
(LP), which is routinely carried out by refiners, was an important part of an optimization process to identify
the most profitable methods to blend ethanol with gasoline.
70
Natural Resources Canada, Canada’s Energy Outlook: An Update, December 1999.
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The CPPI points out that “most issues that pertain to butane also pertain to pentane removal”. There are a
few additional concerns with pentane removal that need to be considered, namely:



pentane removal causes a heavy octane penalty since isopentanes are no longer part of the
gasoline blend;
pentanes can’t be burned in refinery fuel gas, like butane, since they are not volatile
enough. Therefore, they must be sold often at distressed prices into other markets; and;
removal of pentanes can very significantly impair the ability of the gasoline blend to meet
the DI even with smaller additions of ethanol. If DI isn’t met, vehicle performance will
become an issue.
The associated net costs (or benefits) to overcome issues related to reducing the amount of pentanes in
gasoline require refinery-specific analysis and LP optimization. Since pentanes have favourable octane
ratings, some refiners may benefit in having access to more ethanol for incorporating in some blends.
10.4.2 Drivability Index
The CPPI points out that butane removal makes the Drivability Index (DI) specification for gasoline more
difficult to achieve. Even if butane is not a factor, ethanol/gasoline blends have poorer drivability than
conventional gasoline with the same DI. It is more costly to produce blends with the same drivability
performance as conventional gasolines since the distillation characteristics of the gasoline blending
component have to be adjusted to compensate for the ethanol impact on DI. The costs of these potential
changes are not estimated in this study. Such an estimate would require detailed investigation and
optimization of refinery operations and blending operations. Linear programming at refinery operations
would identify the optimal solution for each refiner.
10.4.3 Octane
As the CPPI points out, ethanol would increase gasoline octane. Gasoline blending would be adjusted to
meet the octane specifications (i.e., less reformate/alkylate) so gasoline would be sold with little or no
octane giveaway as it is today. Consumers should not expect higher octane gasoline as a result of ethanol
blending. However, refinery implications may vary.
The economic benefits (or costs) of ethanol’s octane-enhancing capability will be refinery-specific. In some
cases, refineries may have no requirement for octane-enhancing molecules for gasoline blending. Others
may face octane shortages, or ethanol may provide an alternative octane source that could displace the
potential use of products destined for chemicals production, such as aromatics (e.g., toluene or xylenes).
There are other octane-enhancing options such as MTBE, toluene, MMT, reformate. The CPPI points out
that unless highly subsidized, it is unlikely ethanol can compete with most available alternatives. Recently,
crude oil derived products such as benzene, toluene and xylenes (mixed isomers) have increased in price as
a result of crude oil price escalations, such that ethanol in the U.S. market is more competitive. However,
these prices are expected to decline with expectations of lower crude oil prices.
Table 136: Octane Ratings and U.S. Prices For
Some Octane Products
Product
Methanol
Octane
Rating
115
193
Feb. 24, 2000
Price
(Cdn¢/litre)
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Isobutane
121
n-butane
91
MTBE
110
Toluene
103
Ethanol
113
Benzene
101
Source: Octane Week, February Issue.
27
27
37
40
42
55
10.4.4 Gasoline/Diesel Ratio, Potential for Decreased Production or
Exports
The CPPI identified additional refinery and blending considerations. These include:


A 10% addition of ethanol to gasoline in Alberta would cause a significant shift
(reduction) in the gasoline to distillate (G/D) ratio. Unlike US and eastern Canadian
refiners, Alberta refiners already produce a diesel dominated product slate. Further
reducing the G/D may be more or less constrained at a given refinery due to crude feed,
process configuration or product slate requirements. This could trigger costly
investments.
Increased ethanol would mean crude runs in Alberta could decrease by up to 5% along
with some petroleum based co-products. Otherwise gasoline exports out of Alberta would
need to increase.
The assumption in this study is that export markets are available and that increased gasoline that might be
available could be exported. Given this assumption, Alberta refineries would not need to decrease
production of gasoline and petroleum based products. The basis of this assumption is that Alberta’s
refineries currently export a large portion of their petroleum products. In addition, future increases in
gasoline and other petroleum product market demands could offset decreased demands for gasoline
components. Natural Resources Canada projects that motor gasoline consumption in Alberta will increase
by 11% between 2000 and 200571. This increase is based on the growth in economic activity, larger vehicle
fleet, and continued vehicle fleet efficiency improvements. A greater increase (17%) is projected for diesel
(on-road and off-road transportation) as a result of Alberta’s rapid economic expansion in oil sands
refining, petrochemicals and other sectors. Faster growth in diesel versus gasoline may also assist refiners
to offset the market driven reduction in the gasoline/diesel (G/D) ratio.
Table 137: Projected of Gasoline and Diesel Consumption for
Alberta and G/D Ratios for Major Provinces
(petajoules) (Projections between 2000 and 2020)
Alberta Demand
Motor Gasoline
Diesel
71
1990
159.5
90.6
1995
152.5
123.7
1997
163.0
159.7
2000
175.3
159.7
2005
195.0
187.4
2010
209.8
200.3
2015
226.0
227.9
2020
244.8
244.2
Total
250.1 276.2
Gasoline/Diesel (G/D) Consumption Ratios
for Major Provinces
Alberta
1.8
1.2
322.7
335.0
382.4
410.1
453.9
489.0
1.0
1.1
1.0
1.0
1.0
1.0
Natural Resources Canada, Canada’s Energy Outlook: An Update, December 1999.
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Saskatchewan
1.5
1.1
BC
1.8
1.8
Ontario
3.1
2.7
Quebec
2.5
2.2
Source: Natural Resources Canada72
1.0
1.6
2.5
2.1
1.1
1.8
2.8
1.9
1.2
1.8
3.0
1.8
1.2
1.8
3.0
1.8
1.3
1.9
2.9
1.8
1.3
1.9
3.0
1.8
With diesel market demand potentially increasing faster than gasoline (at least according to Natural
Resources Canada), some refiners may find ethanol can alleviate the requirement for lighter gasoline
blending components. According to the CPPI, “if a refiner wanted to increase gasoline production but
wanted to minimize capital investment, ethanol addition would facilitate this objective. The suitability of
this option would be dependent on the given refinery”.
72
Natural Resources Canada, Canada’s Energy Outlook: An Update, December 1999
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10.4.5 Transportation and Storage Logistics
The CPPI points out that ethanol would need to be shipped by truck, as opposed to pipeline due to potential
water contamination. In addition to potential contamination with water, this study identified other potential
problems associated with shipping ethanol by pipeline. These included possible contamination by other
petroleum products, dirt, grease, or oils. One refiner/wholesaler who blends ethanol in gasoline and had
studied the potential use of pipelines pointed out that they should not be used to transport ethanol blends.
Blending can be carried out at blending racks (not necessarily in-line), which are not necessarily located at
refineries. Truck or rail deliveries of ethanol would be required. In Alberta these blending site for ethanol
could be in Calgary or outside of the Edmonton-area refineries. Ethanol plants would need to be located
near Calgary or Edmonton to minimize transportation costs to these or other blending sites. In terms of
blending logistics, ethanol should be viewed as another one of many available blending components needed
to make different grades of gasoline meeting different specifications. Generally, refiners have some
flexibility can be innovative in addressing constraints. However, a detailed transportation/storage logistics
optimization analysis (including potential backhauls, computerized mixing, etc.) would be required to
determine the actual costs of handling, blending and transportation. If the distribution/storage systems are
properly designed, these costs can be similar to other gasoline blending components, at least according to
one refiner with ethanol experience.
10.4.6 Consumer Problems, Retailer Concerns
Canadian wholesalers/retailers of ethanol/gasoline blends contacted for the purposes of this study
(including two CPPI member companies) did not identify vehicle performance problems for blended
grades. Generally, these firms claim market advantages and consumer satisfaction. However, consumer
rejection is difficult to measure since consumers that are not satisfied may not re-purchase the product after
initial dissatisfaction (rather than complain about performance).
Historically in the 1970s and 1980s, there were some performance problems associated with
ethanol/gasoline blends. As the CPPI points out:

Performance of ethanol blended gasolines in the retail marketplace has been less than
compelling. Retailers, like Citgo, the largest North American marketer of ethanol treated
gasoline in the 1980s retreated in the early 1990s because of reoccurring problems and
customer rejection. Most Canadian retailers that offer ethanol blended gasolines usually
do so in certain regions and/or certain blends. With the existing track record, retailers will
be cautious about getting into ethanol blended gasolines
According to gasoline wholesaler/retailers selling ethanol blends, typically these problems were related to
water contamination. Ethanol is quite hygroscopic (attracts water), such that moisture can contaminate the
handling, transportation and storage systems. The first time that ethanol/gasoline blends are added to a
vehicle tank, performance problems can occur if there is water in the tank. These problems are not likely to
reoccur upon subsequent filling of the tank with ethanol blends.
Wholesalers/retailers take routine precautions to avoid water contamination. For example, special pastes
that indicate the presence of water are used with dip-sticks that measure inventory levels in the
underground storage tanks. With this and other precautions to prevent contamination of the fuels water and
related performance issues are negligible.
The experience of one wholesaler/retailer in western Canada (contacted for this study) that test marketed
ethanol/gasoline blends found that at a couple test outlets there was a significant increase in demand in the
short term but the preferred demand for ethanol/gasoline blends subsided from high levels after a period of
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time. Over time, the few test outlets selling ethanol achieved marginal increases in sales volume. The
perception of this wholesaler/marketer is that there is no substantive market need for ethanol among its
customer base (largely rural). Concentrated promotional efforts may be required to sustain higher demand
for ethanol/gasoline blends and increase market share.
10.5 Incentives and Ethanol Plant Financing
Incentives or subsidies for ethanol are prevalent and are likely to be continued in most jurisdictions
interested in attracting ethanol investments and creating value-added business in agricultural communities.
Ethanol investors in ethanol are seeking the most preferable locations for new facilities. Criteria used to
identify these locations include the magnitude of incentives or direct subsidies that are available.
Governments interested in attracting such investments need to have competitive inducements versus
governments in other jurisdictions.
The ethanol “industry” in Alberta and Canada is relatively small in comparison to the US ethanol industry
and in comparison to the oil refining and gasoline industries. Although a new plant was built in Alberta
during the last decade, the size of the provincial industry has not substantially increased relative to the
North American total. Whether incentives or subsidies would be required given a large industry with
competitive scale and scope requires detailed and focused feasibility analysis.
Stakeholders interviewed in this project who were interested in ethanol stated that the duration of any
incentive would need to be long enough to cover financing and providing returns to any investments. This
would reduce the risks associated with making an ethanol incentive in Alberta. That period was identified
as between 8 to 10 years, or more.
10.5.1.1 API Grain Processors
API Grain Processors is a partnership which is jointly owned by Agri Partners International Inc. (API), a
privately held Alberta based corporation, and the Edmonton Pipe Industry Pension Trust Fund. API Grain
Processors operates a somewhat unique grain fractionation and processing facility in Red Deer, Alberta.
The plant, which was operational in 1998, uses wheat as its feedstock to make standard patent flour, vital
wheat gluten, fuel grade ethanol and livestock feed. The main products are flour and wheat gluten, such
that ethanol contributes a minor portion of revenues. Total capacity for ethanol is approximately 22 million
litres per year, although production is less. Agri Partners International Inc. invested in the plant with a view
to capitalize on what they saw as expanding opportunities in agriculture and food processing in Western
Canada. API’s orientation is not focused on ethanol.
Practically all of the company’s production of ethanol is sold to the United States and mostly in the Pacific
Northwest (PNW) region, where a regional supply shortage exists. The company is easily able to sell all its
ethanol in the fuels market. In shipping to the PNW market, the company claims transportation cost
advantages versus mid-west ethanol competitors. Therefore it is not overly concerned about mid-west
competitors and subsidies that may receiving.
API recognizes that government policies can greatly affect an industry’s ability to utilize identified
opportunities. Agri Partners International monitors government initiatives that may impact the industry and
individual projects. When evaluating opportunities in the value-added agri-food marketplace, API will
carefully consider the political and economic climate, technological developments and consumer habits.
Additionally, API is proactive in working with governments as an advisor at every appropriate opportunity.
API has built a reputation as initiators of change. This, combined with API's market knowledge and strong
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working relationships with its market partners and government, opens a large window of opportunity in the
value-added agri-food industry.73
API Grain Processors management desire a “level playing field” and therefore, similar to some other
jurisdictions, would prefer:


an ethanol incentive paid directly to the ethanol producer; and
harmonized ethanol tax incentives (timing and magnitude of exemptions or other
incentives) across Canadian provinces.
API Grain Processors has not been able to attract substantial customers for its ethanol among oil refiners
and wholesalers in Alberta. Although API has had expression of interest by some potential customers,
contracts to purchase a large portion of the company’s ethanol production have not materialized. The
economics for these potential customers are not favourable and there are technical, logistic and marketing
barriers that need to be overcome. Although environmental regulations mandating ethanol blends for
transportation fuel would create market opportunities, API does not believe there is environmental
justification for this in Alberta. Faced with competing in the U.S. market, API would benefit from and
therefore prefer an ethanol incentive program that was paid directly to ethanol producers. However, the
company points out there may be potential countervailing trade action considerations that need to be
studied in greater detail. U.S. producers may view some incentive programs paid to Canadian exporters as
causing injury to their businesses.
The recently reinstated ethanol policy in Saskatchewan which provides a 15 ¢/litre provincial tax
exemption for ethanol sold and produced within the province is an example where non-harmonized policies
lead to favourable business conditions for competitors. API management would prefer to have access to the
Saskatchewan ethanol market, through alleviation of the policy constraint that only ethanol produced in
Saskatchewan is exempt from the provincial tax. API points out the contradiction regarding Alberta’s
ethanol policy that provides the exemption, even if the ethanol is not produced in Alberta74.
Another important policy consideration for API Grain Processors is the time of duration of the 9 ¢/litre
incentive. Consideration should be given to extending the period of duration as well as harmonizing the
expiry of these incentive programs with other provinces.
API stresses and is very appreciative for the raw material- grain supply, marketing, transportation logistics
and other facilitating efforts the Alberta government has provided. However, many of detailed operational
and marketing elements have been addressed through the learning process.
API has strong interest to participate in research and development projects related to its business. It would
appreciate more assistance on this front.
73
74
API Website
Personal conversation Cary Keating, General Manager, API Grain Processors
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10.5.1.2 Parkland Refining
Parkland Refining in Bowden, AB operates a small refinery with a capacity of 6,300 barrels/day based on
using natural gas condensates as the feedstock. Natural gas condensates are lighter than crude oil and
contain a higher benzene content (approximately 3%). Parkland makes gasoline blending components using
a platformer (a type of reformer) and isomerization unit. Additional reformate is purchased from Shell
Canada Ltd. (The Bowden refinery once belonged to Shell which had diminished use for the refinery after
their Scotford refinery was operational). Parkland also operates nearly 400 retail outlets in Western Canada,
stretching from Manitoba to British Columbia.
A major recent operational and economic issue for the refinery was the requirement to achieve a 1% by
volume of benzene content in its gasoline product by July 1999. This has necessitated increasing the
severity of the platformer unit (i.e., higher temperatures) that has reduced the throughput capacity of the
unit, which in turn has required a reduction in the raw material condensate throughput.
Parkland senior management prefers a level playing field for transportation fuels of all types and therefore
prefers tax exemptions for ethanol be eliminated. At the same time, Parkland also believes that all fuel
taxes should be closely examined and possibly reduced in Alberta.
In comparing ethanol as a fuel for its retail operations, Parkland is primarily focused on economic
considerations. Ethanol is considered to be uneconomical for Parkland and consequently not desired at the
present time. Senior management believes that supporting ethanol production would have the effect of
potentially increasing wheat prices which would in turn increase the price of the fuel. That mechanism
reduces the incentive to use ethanol in gasoline.
10.5.1.3 CPPI
The CPPI points out that:

Ethanol subsidies have been in place in Alberta for almost a decade. Ethanol is as
dependent on subsidies today as it was when subsidies were introduced and will continue
to be dependent on subsidies in the foreseeable future. This is an ongoing cost to the
Alberta and Canadian taxpayer on the basis of foregone tax revenues.
10.5.1.4 Canadian Renewable Fuels Association
The Canadian Renewables Fuels Association (CRFA) represents a broad set of stakeholders that favour the
development of ethanol production and markets. Members and affiliates include some representatives of:
ethanol feedstock producers making corn and other grains; ethanol producers; fuel wholesalers and
retailers; livestock feed suppliers; health and environmental organizations; engineering and construction
firms; and government groups.
According to the CRFA, obtaining debt financing for new ethanol plants is often a barrier for investors.
Banks have difficulty accepting the risks associated with the investment and often require substantial
equity, guaranteed tax exemptions for extended periods of time and other risk reducing elements be in place
before providing debt. In Canada, the 66 million litre/year, $44 million Seaway Valley plant project slated
for Cornwall, ON has had some difficulty obtaining financing, despite approximately $32 million in
community and equity capital already in-place.
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An important policy consideration provided by the Canadian Renewables Fuels Association is that tax
exemptions guarantee periods be extended to at least 10 years. This reduces the risks perceived by banks
providing debt financing as well as other investors. Any policies and actions that governments can
implement to reduce the risks associated with investment enhance the likelihood of ethanol development.
An important step to reducing investment risk would be to extend the period of guarantee for tax incentive
programs.
Input from the CRFA suggests that some Canadian ethanol investors have had difficulties dealing with
Canadian lending institutions. One factor is that some capital resource groups that have been approached
have recently been undergone ownership changes. This may be coincidental and not systemic. However,
there are some differences with respect to financing between Canadian and U.S. growers interested in
ethanol production. Some of the large Canadian banks are perceived to be less able to internalize the
complexities associated with the ethanol business, which increases the perception (and reality for them) of
risk. Another factor is the flexibility and interest of farmer credit co-operatives in Canada (which may be
less than farm co-operatives in the United States). New generation co-operatives (NGC) have financed a
significant portion of the ethanol plants in Minnesota.
10.5.1.5 Iogen Corporation Input
Iogen Corporation is a privately-held biotechnology company which markets industrial enzymes in the pulp
and paper, textiles and animal feed industries. It was established in 1974, it had a staff of about 60 in 1997,
of whom more than half were involved in research and development. Iogen Corporation has been
developing enzyme technology and related production processes for ethanol made from biomass. A
commercial demonstration facility is currently being developed in the Ottawa area that would use straw as
raw material. Practically any type of straw can be used. The facility is larger than a lab-scale pilot plant and
can produce close to 3 million litres of ethanol per year.
In 1997, Petro-Canada signed an agreement with Iogen Corporation of Ottawa to invest in the technology
of using renewable resources such as straw, wood wastes and grasses to make the motor fuel ethanol. PetroCanada and Iogen were to jointly fund research and development for 2 years. Petro-Canada was then to
fund construction of a plant to demonstrate the commercial feasibility of the technology. Petro-Canada will
earn exclusive rights to use the technology in Canada for plants to meet its own needs.
Currently, Iogen is investigating alternative locations to install an ethanol production plant. The company
hopes to make an investment decision within 6 months. Although smaller plants are possible, Iogen is
envisioning a plant that would:





make 225 million litres of ethanol per year;
cost between $100 and $200 million to build;
employ approximately 110 people;
require approximately 714,000 tonnes of straw (one tonne of straw per tonne of wheat
grain – very rough); and
pay approximately $5 to $20 million for raw material straw to farmers.
Iogen is evaluating different states and provinces and comparing them with respect to various criteria that
include:



raw material availability;
infrastructure;
incentives available;
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


regional markets;
transportation; and
regulatory environment.
Iogen has found that government representatives from the U.S. states and some provinces are very keen to
attract ethanol investments to their jurisdictions. Iogen is considering Iowa, Nebraska, Saskatchewan,
Alberta, Utah, and other locations (none excluded from list purposefully). According to an Iogen executive,
the mid-west states are particularly aggressive, well co-ordinated and present attractive investment
enhancement packages related to ethanol investments. They are “swooning” to attract new investments in
ethanol plants. Regional U.S. state programs are supported by U.S. federal programs for “agricultural
value-added businesses”. In Iowa, the governor has become actively involved in promoting and
communicating the state’s keen interest in ethanol. This creates a favourable impression on potential
ethanol investors. A group of 30 people (including growers) are reportedly going to Ottawa to visit Iogen’s
commercial demonstration plant.
Iogen has three main points with respect to ethanol government incentive policies. These are:
1.
2.
3.
There are fuel tax exemptions and other incentives in many jurisdictions such that any
province or state that hopes to attract an ethanol plant would require competitive
inducements;
The duration of the guaranteed tax exemptions needs to be extended to at least 10 years,
with the duration periods harmonized across Canada to reduce risk for investors;
Environmental standards and automobile fuel efficiency standards (similar to the United
States) are required to enhance and match the market potential for ethanol in Canada
versus the United States.
Iogen’s ethanol policy input for consideration relates to elements that reduce the risks to equity and debt
investors. Some of the banks that Iogen has approached indicate that to make their involvement worthwhile
a series of ethanol plants across the continent would be required. This may present an issue for Iogen,
which would need to consider optimizing its plant investment decisions across different regional featuring
diverse market, environmental regulations for fuels, incentive regimes and other business factors.
Iogen points out that a period of five years for tax exemptions is too short. Banks and other investors have
concerns that governments may not renew exemptions after short periods of time. Even the Canadian
federal government does not have a guaranteed period of time over which the 10 ¢/litre tax exemption
applies. This creates uncertainty on behalf of ethanol customers, producers and investors.
Harmonizing the periods for which tax exemption programs are in place is also recommended for the
different provinces. This would allow ethanol investors to make the optimal investment choices base on
other business factors. For example, if one province’s exemption expires within one year, that province has
a reduced chance of attracting an investment, even though there may be attractive business factors relating
to locating a plant in that province.
10.5.1.6 Petro-Canada
Petro-Canada operates refineries in Montreal, Oakville and Edmonton and markets gasoline across the
country. The company also has a lubricants plant in Mississauga, ON. Petro-Canada has been involved in
developing new ethanol technology based on using biomass such as wheat straw and corn stover, rather
than the actual wheat and corn grains. It assisted in financing the development of Iogen’s commercial
demonstration facility that is expected to be operational in 2000.
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According to Petro-Canada, current cost of ethanol production from the facility is too high (with raw
material straw priced at 30 to 40 $/tonne) to make output competitive with refinery gasoline. It is hoped
that costs of approximately 20¢/litre can be demonstrated, at which point ethanol would be competitive to
gasoline production costs at crude oil prices of 20 US$/barrel.
Petro-Canada’s interest in ethanol is in the context of:



developing a climate change response to Kyoto Protocol requirements;
having access to an alternative octane source that would help in optimizing its refining
and petrochemical production in eastern Canada, especially in the context of operational
changes to meet the Low Sulphur in Gasoline Regulations, that will begin taking effect
between 2002 and 2005; and
commercial interests in Iogen’s technology. Petro-Canada will earn exclusive rights to
use the technology in Canada for plants to meet its own needs.
Petro-Canada has signed an agreement to purchase a portion of the ethanol from the proposed 150 million
litre/year Commercial Alcohol facility for Varennes, QC. Commercial Alcohols is seeking to secure
financing, which in part may be contingent on the Quebec government’s final ethanol exemption rules.
On an environmental basis, Petro-Canada points out that ethanol derived from wheat straw biomass can be
70 to 90% less GHG-intensive than gasoline. This estimate reflects no GHG emissions associated with use
of fertilizer applied to grow wheat. The economics of ethanol can also vary from refiner to refiner. The
economics may look more favourable for refiners that are short of octane components or require large
investments to produce more octane. Other economic factors include:




petrochemical operations and values;
anticipated operational changes and costs to meet the new low sulphur levels in gasoline;
price of oil and cost of making gasoline; and
provincial tax exemptions incentives.
A major factor for investing in new ethanol facilities in the duration of the incentive. When selecting a
location, investors desire security that the incentives will be in place for a long-enough time to cover the
returns on the investment.
10.5.2 Improvements in Ethanol Technology
The CPPI points out that:

past projections of improvements in ethanol production technology and reduction in
production costs do not seem to have been realized, as ethanol is not becoming more
market competitive. The certainty of future production for large cost reductions, step
changes in technology or the emergence/dominance of ethanol from waste biomass
should be viewed with great caution. If these events do come to pass and ethanol is
market competitive, government intervention should not be required.
A comprehensive historical analysis of production cost trends was not identified. Neither is there a study
comparing past projections of improvements from new technology and the realized costs when that
technology has been applied. While the basic fermentation technology in the ethanol industry may not have
changed, the increasing size of the industry and newer larger plants can result in reduced production costs.
As the industry increases in size, experience curve economics (i.e., production costs slowly decline as the
cumulative amount of the industry’s output increases) dictate that production costs will decline. Companies
such as ADM have been able to reduce production costs as they increased the size as well as scope (product
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scope) of their ethanol operations. Whether this is reflective of the industry as a whole requires special
focused analysis.
10.5.3 Price Increases for Food
The CPPI points out that


If ethanol production caused in an increase in market price for the feedstock, wheat or
barley, these increased prices would be applied to all operations that use this feedstock.
These higher prices would be passed on to all operations that use this form of higher costs
of foods. These economics must be factored into overall economic assessment.
The ability of ethanol use in Alberta to increase local wheat prices is questionable since
wheat is an international commodity and the increase in market demand caused by
Alberta ethanol use is expected to be insignificant. It may be very difficult to distinguish
an change with respect to the impact on Alberta agriculture, the market demand for wheat
or the price of wheat. This requires further study.
The effect on wheat prices of hypothetical production of 200 million per year of ethanol has been analyzed
elsewhere in this report and found to be very small (e.g., 1 ¢/bushel).
10.6 Economic and Trade Considerations
Economic implications related to potential ethanol production plants in the context of Alberta were covered
in Section 3. Following in this subsection are brief analyses related to other economic elements identified
by and of concern to stakeholders.
10.6.1.1 Attractiveness for Refiners/Wholesalers
Oil refiners and gasoline wholesalers interviewed for this study indicated that, at a minimum, ethanol needs
to be competitive with the rack price of gasoline. Some stakeholders pointed out that it may even need to be
lower than the rack price of gasoline to overcome any additional handling, transportation, storage and
retailing costs. The rack price of gasoline can be considered to represent the full cost (including returns on
equity) of making gasoline. It is also an indication of the value at which refiners are willing to sell gasoline
to wholesalers/retailers or purchase gasoline from other refiners to meet market requirements.
Some input on economic and trade considerations from the CPPI is summarized below.

At today’s cost of ethanol, which is about 40-45 ¢/litre, a 19¢ subsidy may not he enough
to create a business case for ethanol. The 1988 Touche Ross report for the Alberta Grain
Commission indicates a 29 ¢ subsidy would be needed for ethanol to be of interest to the
refining industry. This factor should be undated.
A major factor affecting costs is the market price of crude oil, which affects raw materials and energy costs.
Crude prices fluctuate due to supply/demand circumstances such that the competitiveness of ethanol will
vary in the context of different crude oil prices and gasoline production costs. Currently (March 2000), high
crude oil prices have resulted in a favourable competitive position for ethanol that is favoured by tax
exemptions. Most industry sources contacted in this study believe that the high crude oil prices will drop
from currently high levels.
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The CPPI points out that: “Wheat and crude oil prices can fluctuate dramatically. This variability is
considered a risk by the oil industry looking at ethanol. Crude oil fluctuations have caused the rack price of
gasoline to increase from 17 ¢/litre in February 1999 to 28 ¢/litre in December 1999. Similar fluctuations
have occurred for ethanol.”
Ethanol variable production costs are largely related to raw material, energy and by-product values. The
ethanol cost structure and market dynamic is quite different to oil refining and the gasoline business which
is largely influenced by crude oil prices. To reduce risks associated with dissimilar cost structures and
many market variables, refiners/wholesalers using ethanol have worked closely with ethanol producers to
establish long term contracts for ethanol purchases. Contracts can feature pricing mechanisms that
minimize the downside risks of higher corn or ethanol prices, as well as taking advantage of price increases
in crude oil and gasoline.
Table 138: Approximate Alberta Gasoline Delivery Economics
Cost components
15
US$/barrel
C¢/litre
14
5
20
US$/barrel
C¢/litre
18
6
30
US$/barrel
C¢/litre
27
7
40
US$/barrel
C¢/litre
36
8
Rack price of gasoline
Provincial tax
Federal excise tax
Wholesalers distribution costs
Wholesalers margins
Retailer margin
G.S.T.
19
9
10
1
2
3
3
24
9
10
1
2
3
3
34
9
10
1
2
3
4
44
9
10
1
2
3
5
Retail price of gasoline
47¢
52¢
63¢
74¢
Price of raw material crude oil
Refiners’ cost to make gasoline
(sum of above)
Sources: Industry sources
Ethanol, purchased at 40 ¢/litre, which is exempt from provincial (9¢/litre) and federal excise tax (10¢/litre)
can be competitive with gasoline at crude oil prices in excess of 20 US$/barrel. This assumes that handling
and distribution costs are less than 3 ¢/litre (conservatively high) versus gasoline. With crude prices at close
to 30 US$/barrel and ethanol purchase prices at 40 ¢/litre, there is an economic incentive favouring taxexempt ethanol, if the ethanol is sold at the retail price of gasoline. Companies selling ethanol/gasoline
blends claim it is best to assume that these blends will not command a premium price in the marketplace.
Wholesalers contacted in this study believe that the recent substantial increase in crude oil prices resulting
in crude oil at approximately 31 US$/barrel and gasoline retail prices in Alberta at nearly 62 ¢/litre, is a
temporary phenomenon. Prices for crude oil are expected to decline, which would affect the current
attractiveness favouring tax-exempt ethanol.
Table 139: Estimated Ethanol Delivery Costs to Retail
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Cost components
Price of ethanol
Provincial tax
Federal excise tax
Wholesalers’ handling, distribution costs
Wholesalers’ margin
Retailers’ margin
G.S.T.
Cost of ethanol delivery
Tax
Exempt
C¢/litre
40
0
0
4
2
3
3
Tax
Exempt
C¢/litre
50
0
0
4
2
3
4
Not Tax
Exempt
C¢/litre
40
9
10
4
2
3
5
52
63
73
(sum of above)
Without federal or provincial tax exemptions, the price of crude oil would need to be approximately 40
US$/barrel to make ethanol purchased at 40 ¢/litre competitive with gasoline for wholesalers. It is likely
that the price of crude oil would even need to be slightly higher, since increases crude oil prices increases
the cost of energy, transportation fuels involved in ethanol production.
Table 140: Wholesaler Incentive to Handle, Distribute Ethanol at
Different Crude Oil and Related Gasoline Retail Prices
Cost components
Retail price of gasoline
Delivery cost of ethanol
15 US$/barrel
C¢/litre
47
52
20 US$/barrel
C¢/litre
52
52
30 US$/barrel
C¢/litre
63
52
-5¢
0
+11
(at ethanol purchase price of 40¢/litre)
Wholesaler incentive if ethanol sold
at same retail price as gasoline
Wholesalers contacted in this study have concerns about the long-term viability of ethanol. During periods
when price of for crude oil are less than 20 US$/barrel ethanol can be economically unattractive to
wholesalers. Wholesalers also believe there is a lack of secure supply of ethanol in Alberta. One issue with
respect to purchasing ethanol from the United States is the volume/weight restrictions on trucks in the
United States. U.S. transportation regulations limit loads to 33,000 litre, while Canadian shipments can be
56,000 litres. The smaller load sizes in the U.S. increase the distribution costs for ethanol imported from the
United States.
10.6.2 Business Risks and Viability of Ethanol Facilities
The scope and purpose of this report do not include a business feasibility analysis for ethanol production in
Alberta, which would address Alberta-specific business viability, risks, and opportunities. Such as study
would need to be carried in context of specific plant sizes, markets and all other important business factors.
The relative importance of factors will likely be different than other provinces or states, and different
depending on market conditions (e.g., relative price of crude oil, gasoline and raw material wheat). The
magnitude of risk and viability of are very business and investor specific. Ascertaining these parameters
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requires detailed feasibility analysis of the investment at hand. This study provides limited anecdotal
information and results of other one study that considered these factors.
The CPPI points out that:

Ethanol subsidies in Minnesota exceed 30 ¢/litre, not including the availability of low
interest loans. Yet the Minnesota Office of the Legislative Auditor considers ethanol
plants as risk ventures. For plants less subsidized, we would assume the risk increases
substantially.
Regarding business risks, the Minnesota Office of the Legislative Auditor study identified and analyzed the
following risks facing the industry:




the possibility that ethanol plants will not be able to make money at prevailing prices for
corn and ethanol;
the possibility that Minnesota plants will lose out in competition with larger, more
efficient producers;
the possibility that the federal government will withdraw all or much of its current 54
US¢/USgallon (~10 Cdn¢/litre) tax credit for ethanol, or its requirement that oxygenated
gasoline be used in certain areas;
the possibility that new technologies of ethanol production will become commercially
viable and compete with corn-based production.
The Minnesota Office of the Legislative Auditor’s report also considered future scenarios that would be
beneficial for the ethanol industry. These were:


the price of crude oil increases; and
the national market for ethanol expands for any reason (e.g., MTBE phased out of
markets and oxygenates still required).
In general, some of Minnesota’s plants are smaller than larger scale plants in some other states. Larger
plants enjoy better economies of scale and product scope than smaller plants. However, there are many
plants in North America that have been viable for many years and are smaller than plants in Minnesota. The
average profit for plants was determined based on monthly prices of ethanol, DDG, and corn between 1994
and 1996. Although the average profit was positive with and without 20 US¢/USG subsidy, for many
months profitability was negative.
Table 141: Average Ethanol Profits For Minnesota
Between 1994 and 1996
Ethanol Price (US¢/US Gallon
DDGS (US$/short-ton)
Corn Price (US$/Bushel)
Profit (US$/US gallon
(With 20 ¢/gallon producers payment)
Percent of months when profit was negative
Profit (US$/US Gallon
(Without 20 ¢/gallon producers payment)
206
Average in
US Funds
$1.30
$128.20
$2.55
$0.28
Range
$1.09 to 1.81
$93.10 to 184.38
$1.96 to 4.65
-$0.25 to 55
25%
25%
$0.08
-$0.45 to 35
CHEMINFO
Some of the key report’s conclusions to be considered include:

If the future economics of ethanol production are favourable, there is nothing to prevent
growth in Minnesota to 220 million gallons per year (836 million litre, the state’s goal).
However, we think there are reasons to doubt the wisdom of state support for one
industry, especially one where there are significant risks to future profitability. One
danger is that ethanol subsidies will drive out other opportunities for economic
development in rural Minnesota. A substantial amount of private capital is invested in
Minnesota’s ethanol plants and when the state and federal governments ultimately
withdraw their financial support as they are now scheduled to do within ten years, this
private capital which could have gone to other local investments is put at risk.
10.6.2.1 US EPA Decision on MTBE and Oxygenates in Gasoline
For new ethanol plants in Alberta or elsewhere in North America, the risks associated with relying solely
on environmentally driven markets and supporting legislation for business success over a long period of
time are evident. One case in point is Alberta’s MTBE plant which is heavily reliant on mandated demand
for oxygenates in gasoline in the United States. The prospects of phasing out MTBE have resulted in
uncertainty for the Edmonton producer. Similarly, Methanex’s methanol production which feeds MTBE
plants across North America is vulnerable.
California requested the US EPA to allow it to opt out of mandated oxygenated gasoline requirements (2%
oxygen content) in context of environmental releases of MTBE. The Governor points out that, “ethanol
may well play a large role in California’s future fuel supply. But if California, or any state, can meet the
emission standards of the Clean Air Act – with or without the use of oxygenates – we should be permitted
to do so”.75 The USEPA recently announced its response to these requests.
On March 20, 2000, EPA Administrator Carol Browner and Agriculture Secretary Dan Glickman
announced actions to be taken by the Administration to significantly reduce or eliminate use of the fuel
additive MTBE and boost the use of safe alternatives like ethanol. The actions are in order to protect
drinking water from MTBE contamination, preserve clean-air benefits, and promote greater production and
use of renewable fuels like ethanol.76
Browner and Glickman released a legislative framework to encourage immediate Congressional action to
reduce or eliminate MTBE and promote renewable fuels like ethanol. The legislative framework being sent
to Congress includes the following three recommendations:


Congress should amend the Clean Air Act to provide the authority to significantly reduce
or eliminate the use of MTBE. This step is necessary to protect America's drinking water
supplies.
Second, as MTBE use is reduced or eliminated, Congress must ensure that air quality
gains are not diminished. The Clinton-Gore Administration is deeply committed to
providing Americans with clean air and clean water.
75
Letter from Governor Gray Davis to Senator Dianne Feinstein, March 29, 1999.Letter from Governor
Gray Davis to Carol M. Browner, Administrator EPA.
76
U.S. EPA, U.S. DA MARCH 20, 2000, Clinton-Gore Administration Acts To Eliminate MTBE, Boost
Ethanol, March 20, 2000
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
Third, Congress should replace the existing oxygenate requirement in the Clean Air Act
with a renewable fuel standard for all gasoline. By preserving and promoting continued
growth in renewable fuels, particularly ethanol, this step will increase farm income,
create jobs in rural America, improve energy security, and help protect the environment.
"Threats posed by MTBE to water supplies in many areas of the country are a growing concern," Browner
said. "Action by Congress is the fastest and best way to address this problem. We need to begin now to
eliminate MTBE from gasoline and move to safer alternatives, like ethanol because Americans deserve
both clean air and clean water -- and never one at the expense of the other."
"These principles provide a strong, unified framework for promoting the continued growth of renewable
fuels like ethanol," said Glickman. "Ethanol will play an important role in ensuring that we maintain the air
quality gains we have achieved to date, and the renewable fuels standard will encourage substantial new
growth in the use of ethanol and other renewable fuels across the country. That's good news for our
farmers, for our energy security, and for the environment."
In addition to the legislative framework, Browner also announced that EPA today formally began
regulatory action to eliminate or phase down MTBE, issuing an Advance Notice of Proposed Rulemaking
under Section 6 of the Toxic Substances Control Act. "To ensure that our water supplies will be protected, I
am also directing EPA to take an additional insurance policy by starting a regulatory process aimed at
phasing out MTBE," Browner added. "However, this action can require time to complete; that is why it is
in the best interest of the American people for Congress to take quick action now."
Section 6 of the Toxic Substances Control Act gives EPA authority to ban, phase out, limit or control the
manufacture of any chemical substance deemed to pose an unreasonable risk to the public or the
environment. EPA expects to issue a full proposal to ban or phase down MTBE within six months, after
which more time is required by the law for analysis and public comment before a final action can be taken.
The USEPA’s and USDA’s announcement on MTBE and ethanol provides some uncertainty for ethanol
investors. On the one hand the phase out of MTBE seems more certain. However, it has come in the
context of eliminating the Clean Air Act’s 2% oxygenate requirement in gasoline. This may have removed
the environmental legislative underpinning of the ethanol (as well as other oxygenates) market. The
implication of this change is that states may use alternative control options to achieve environment
standards. These options may or may not include oxygenates.
On the other hand the Glickman’s remarks sound encouraging with respect to ethanol. That is, “Ethanol
will play an important role in ensuring that we maintain the air quality gains we have achieved to date, and
the renewable fuels standard will encourage substantial new growth in the use of ethanol and other
renewable fuels across the country. That's good news for our farmers, for our energy security, and for the
environment." However, the form of nature of this renewable standard is not evident. It may present legal
difficulties in context of environmental requirements (considering the elimination of the mandated
oxygenate requirement). The standard may indeed have climate change underpinnings, although this is not
yet clear.
The business risks for any potential Canadian ethanol production destined for U.S. markets may be high. If
the yet-to-be-defined “renewable fuels standard” is oriented toward “promoting” agriculture businesses and
assisting farmers, or is a climate change response (using “renewable” resources) for the United States (and
not linked to any mandated renewable or oxygenate level for gasoline to address ambient air quality
environment standards), then ethanol made in Canada may not fit the U.S. framework and its intended
objectives. If in “promoting” the development of ethanol, the US government provides increased levels of
financial assistance to US ethanol producers, it would make it more difficult for Canadian exports to
compete. In addition, if the US is developing ethanol to support farmers or address climate change,
subsidized ethanol produced in Canada may be more prone to trade actions under these circumstances.
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10.6.2.2 Prices, Buyer-Seller Relationships to Reduce Risk
Ethanol price-setting mechanisms that are based solely on the rack price for gasoline (i.e., rack price plus
provincial and federal sales tax incentives) may not make economic sense for both fuel wholesalers
(buyers) and ethanol sellers. Large quantity buyers of ethanol as well as ethanol producers may need to take
into consideration fluctuations in the market place both on crude oil and on grain pricing. Ethanol sales
contract could consider tie-ins to gasoline rack price as well as embody mechanisms to reduce business
risks. To reduce risks, these features for ethanol transactions could be taken into account:



hedging against low crude oil prices (that may result in ethanol prices being too low to
support ethanol producer profitability);
protecting against high crude oil price that results in potential windfall profits for ethanol
producers (and no upside incentives for refiners/wholesalers); and
protecting against high grain prices and low or medium crude oil prices that can hurt the
ethanol producers.
10.6.2.3 Trade Issues
A direct government subsidy to an ethanol producer whose ethanol or co-products (e.g., DDG) are exported
to other countries (notably the United States) make the business vulnerable to trade actions. As a general
rule, instruments (i.e., incentives or subsidies) that are broad and not focused on providing assistance to any
one specific industry (e.g., all manufacturing) are generally less vulnerable to countervail actions. Whether
various forms of incentives are indeed direct subsidies subject to countervail trade actions is dependent on
the design and scope of the incentive, the quantities and values of products involved, market conditions,
and other factors. Producers in the country of destination need to prove financial harm resulting from the
subsidized products. If successful, import duties may be placed on the products.
The CPPI has questions regarding the scope of economic support for ethanol:

It is unclear if economic support for ethanol is only intended for ethanol produced in
Alberta or if it would be extended to imported ethanol. In addition, it is unclear what the
trade implications would be of disadvantaging imported ethanol (NAFTA and
interprovincial trade) and supporting only ethanol produced within the Province of
Alberta.
The scope, intent, design and mechanism of a change in Alberta Agriculture Food and Rural Development's
(AAFRD) guarantee on the current government of Alberta’s provincial tax exemption policy have yet to be
defined, and are not the subject of this study. This study provides input for consideration.
Information and further analysis related to international and interprovincial trade issues may be required,
depending on: the nature of AAFRD's policy on the guarantee of the current current exemption; the design
of incentive programs in other jurisdictions; and the actual amount of trade between provinces and
internationally.
The elements of international trade law are complex, such that consideration should be given to seeking a
formal “opinion” from the Federal Department of Foreign Affairs and International Trade (DFAIT) when
designing financial or other incentives to specific to an industry. These opinions may be obtained from
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Trade Remedies division of DFAIT. The contact person is Mr. Michael Robertson, Deputy Director (613944-9108) in Ottawa.
10.6.3 Economic Development, Alternatives to Aid Farmers
Some stakeholders pointed out that ethanol incentives may not be the optimal vehicle for developing and
diversifying the Alberta economy. Generally, the attitude toward ethanol was conservative, rather than
negative. One consideration that was identified by a couple of stakeholders is that there are no ethanol
government department or private sector “champions”, promoting and crafting ethanol industry
development strategy for Alberta.
10.6.3.1 Alberta Economic Development
Alberta Economic Development priorities have been on upgrading the province’s oil and natural gas
(especially ethane contained in natural gas) resources into value-added products such as petrochemicals.
Ethanol has not been a priority or focus for development. Upgrading natural gas into petrochemicals has
been a natural process for Alberta due to the abundant supply of raw materials. Petrochemical investment
has generated major investments and contributed significantly to the economic prosperity and growth in the
province. In part, petrochemical development has occurred as a result of policies favouring the extraction
and use of ethane in Alberta. This has created opportunities for petrochemical developers using ethane in
the province.
Future priorities for Alberta Economic Development are oriented toward more petrochemical production
including the potential for upgrading available propylene into polypropylene and other derivatives, as well
as additional ethylene and polyethylene capacity, which will depend on the availability of ethane.
The business case for ethanol is less certain than petrochemicals, and more difficult to assess. The benefits
for ethanol are not clear. There may also be other fuels that should be considered such as biodiesel. Ethanol
is not viewed as a strategic climate change tool, yet.
10.6.3.2 Saskatchewan Wheat Pool77
Saskatchewan Wheat Pool is Canada's largest publicly traded agri-business co-operative. The Pool is an
integrated and diversified company engaged in five distinct but interrelated agri-businesses. Based on sales,
it was the largest company in Saskatchewan in 1998 and is the largest Canadian publicly traded agribusiness co-operative with over 70,000 members. The company's principal business is handling and
marketing grain. It is also one of western Canada's largest marketers of farm supplies and services. In
addition, the company markets livestock, maintains a feed processing operation, and is involved in hog
production. The Pool is also extensively involved in agri-food processing with products sold world wide
and publishes The Western Producer, a weekly farm newspaper. Pool shares are traded on the Toronto
Stock Exchange.
Saskatchewan Wheat Pool is organized around five strategic business segments which largely servicing
western Canada, with head office in Regina and regional offices in Alberta and other provinces:
•
•
Grain Handling & Marketing;
Agri-products (elevators, fertilizers blending and distribution);
The background information on the Saskatchewan Wheat Pool is from the Pool’s website:
http://www.swp.com/corpprofile/overvw2.html
77
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•
•
•
Agri-food Processing;
Livestock Production & Marketing; and
Publishing and other (agro-economic information, insurance, etc.).
Through its strategic diversification into Agri-food processing, the company expands markets for
producers' commodities and leverages its grain handling and marketing operations. Included in this
segment are CSP Foods, a division of the Pool, CanOat Milling, a wholly owned affiliate, CanAmera Foods
(33% ownership interest), Fletcher's Fine Foods Ltd. (44% ownership interest, Prairie Malt Limited (42%
ownership interest) and Robins Foods Inc. (35% ownership interest).
Its livestock businesses include operations conducted by the Pool's 89.9% owned affiliate, Heartland
Livestock Services, and the production and sale of hogs through wholly owned, Heartland Pork
Management Services. CanGro Processors Ltd. (100% owned) is the Pool's feed manufacturing operation.
The Pool also has interests in Medicine Hat Feeding Company, Poundmaker Agventures and Agro Pacific
Industries Ltd.
At the present time, economic development personnel at the Saskatchewan Wheat Pool have concerns
regarding the viability of ethanol production ventures. In addition, the impact to wheat farmers (members
of the co-operative) ethanol plants may not provide high direct benefits for farmers.
Investments in new ethanol facilities are not currently a priority for the Pool.
10.6.3.3 Canadian Wheat Board78
The Canadian Wheat Board (CWB) is the export marketing agency for Western Canadian wheat and barley
growers. Its role is to market these grains for the best possible price. All proceeds from sales, less the
marketing costs, are passed back to farmers. With annual revenues of over $6 billion, it is one of the
country's biggest export firms and one of the world's largest grain marketing organizations.
A Canadian Wheat Board manager79 confirms that wheat sold for domestic ethanol production would not
need to go sold through the Board. There are no concerns regarding the supply of wheat to support ethanol
production in western Canada. The Board is interested in value-added opportunities for farmers in western
Canada. However, it has some concerns regarding the viability of ethanol plants and farmers investing in
such plants through co-operatives (New Generation Co-operatives or other forms). There are also questions
regarding the effects on the mix of wheat varieties grown. The positive impact on prices obtained grain
farmers supporting an ethanol plant would likely be very low. There may be better incentive for farmers
regarding lowering their elevator costs (which can be 10 to 15 $/tonne) for the portion of wheat sold to an
ethanol plant.
The Board also points out that the price of wheat in Manitoba and Saskatchewan is likely to be less
expensive that in Alberta. The rationale for this relates to the pricing mechanism for wheat in western
Canada. This mechanism is such that the netback to farmers is the border price (say at the port of
Vancouver) less the transportation cost to get it there. Given a hypothetical price of 200 $/tonne of wheat in
Vancouver, the price in Alberta may be 180 $/tonne, and 170 $/tonne in Saskatchewan and even slightly
less in Manitoba. Ethanol plants therefore may have favourable raw material prices in Manitoba and
Saskatchewan, according to the Board.
The background information on the Canadian Wheat Board is from the Board’s website:
http://www.cwb.ca/
79
Personal conversation with Earl Geddes, Senior Program Manager (Value-Added Businesses)., Mar.
31,2000
78
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