Environmental and Economic Study of
Alternative Motor Fuels Use
Report to Congress
In Response to
The Alternative Motor Fuels Act of 1988
Final Draft - November 1991
U.S. Environmental Protection Agency
Office of Mobile Sources
Emission Control Technology Division
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Environmental and Economic Study of
Alternative Motor Fuels Use
Report to Congress
In Response to
The Alternative Motor Fuels Act of 19 88
Volume 1: Executive Summary and Report
Final Draft - November 199 1
U.S Environmental Protection Agency
Office of Mobile Sources
Emission Control Technology Division
-------
Environmental and Economic Study
Alternative Motor Fuels Use
Report to Congress
Final Draft - November 1991
Prepared In Response to the
Alternative Motor Fuels Act of 1988
U.S. Environmental Protection Agency
Office of Mobile Sources
Emission Control Techology Division
Ann Arbor, Michigan
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Environmental and Economic Study of
Alternative Motor Fuels L':>e
Report to Congress
Table of Contents
Main Section Titles Page
Volume 1: Executive Summary and Report
Executive Summary
I. Discussion of the Implications of Alternative Fuel Use in
II. Discussion of Alternative Fuel Use Scenarios vin
III. Areas of Further Study
Environmental and Economic Study of Alternative Motor
Fuels Use
I. Overview of the U.S. Energy Picture: Economic and
Environmental Status 3
II. Potential Fuel/Feedstock Combinations 10
III. Scenarios of Alternative Fuel Use 1 -
IV. Environmental Impacts ot Alternative Fuel Use 1 6
V. Economic Impacts of Alternative Fuel Production and USe 3 6
VI. Summary and Conclusions 5 6
VII. Plans for Future Study - AMFA Report to Congress II 5 9
Volume 2: Appendices
List of Abbreviations l-'i
Appendix T Energy Forecasting Assumptions
Appendix 2: Overview of U.S. Energy Price and Consumption
I. Recent History of U.S. Energy Market
II. Energy Forecast: Economics and Supply
2- I
2-17
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Table of Contents (Cont'd)
Chapter and Main Section Titles Page
Appendix 3: Scenarios of Alternative Fuel Use
I. Scenario I: Maximum Utilization of AMFA Fuel Economy
Credits 3-2
II. Scenario 2: Nine City Program Equivalent 3-8
III. Scenario 3: 1 MMBPD Gasoline Displacement 3-13
IV. Analysis of Scenarios 3-15
Appendix 4: Alternative Fuels Availability and Economics
I. Availability & Costs of Potential Feedstocks 4-1
II. Production Costs of Alternative Transportation Fuels 4-27
Appendix 5: Energy Supply Impacts of Alternative Fuel Scenarios
I. Energy Supply Impacts 5-1
II. Crude Oil Price 5-3
III. Other Energy Supply Impacts 5-4
Appendix 6: Economic Impacts of Alternative Fuel Scenarios
I. Net Consumer Cost 6-1
II. Vehicle Cost 6-12
III. Energy Price/U.S. Table Balance Impacts of Reduced
Petroleum Demand 6-13
IV. Effect of an Alcohol Fuels Program on the Federal
Budget 6-15
V. Summary of Economic Impacts of Alternative Fuel
Scenarios 6-20
Appendix 7: Environmental Impacts of Alternative Fuel Use
I. Regulated Pollutant and Air Toxic Impacts
II. Global Warming Impacts
7-1
7-21
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Table of Contents (Cont'd!
Chapter and Main Section Titles Page
III. Other Environmental Impacts 7-3 8
IV. Environmental Impacts of Alternative Fuel Use Scenarios 7-47
Appendix 7-A: Greenhouse Gas Emissions From Transportation 7-A-1
Appendix 7-B: Options and Economics for C02 Control 7-B-l
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Executive Summary
Table of Contents
Section Title Page
I. Discussion of the Implications of Alternative Fuel Use iii
II. Discussion of Alternative Fuel Use Scenarios viii
III. Areas of Further Study xii
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Environmental and Economic Study
of Alternative Motor Fuel Use
Executive Summary
The Alternative Motor Fuels Act of 1988 established a system of
corporate average fuel economy (CAFE) credits, effective in the 1993
model year, designed to stimulate the production of alternative fueled
vehicles by automobile manufacturers.1 In section 400EE (b) of that
legislation, Congress commissioned the Environmental Protection Agency to
provide a series of four biennial reports, including:
"(A) a comprehensive analysis of the air quality, global climate
change, and other positive and negative environmental impacts, if any,
including fuel displacement effects, associated with the production,
storage, distribution, and use of all alternative motor vehicle fuels
under the Alternative Motor Fuels Act of 1988, as compared to gasoline
and diesel fuels; and
"(B) an extended reasonable forecast of the change, if any, in air
quality, global climate change, and other environmental effects of
producing, storing, distributing, and using alternative motor vehicle
fuels, utilizing such reasonable energy security, policy, economic, and
other scenarios as may be appropriate."
In addition, the Conference Report 100-929, which accompanied the
AMFA, stated that "the analysis and forecast shall be based on a variety of
reasonable scenarios concerning market penetration of the alternative
fuels, their likely feedstocks, changes in fuel consumption in the
transportation sector, any displacement of fuels in other sectors, and
changes in technology." It was further stated that "the Environmental
Protection Agency shall include an assessment of the economic costs and
benefits and shall include a discussion of carbon dioxide impacts from the
use of alternative fuels in the transportation sector as compared to the use
of other fuels in that sector and identify ways to offset any increases that
may result."
The present volume is the first in this required series of reports.
1 Public Law 100-494; Oct. 14, 1988. 102 Stat. 2441
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A great deal of activity has taken place since the passage of the Act,
aimed at spurring the broad-scale introduction of alternative
transportation fuels into the marketplace. In June of 1989, President Bush
announced a proposal for revising the Clean Air Act, which contained
provisions requiring the introduction of clean, alternative fueled vehicles
in the nation's nine highest ozone cities. In the recent Congressional
deliberations over amendments to the Clean Air Act, concepts for an
alternative fueled fleet vehicle program as well as a California clean
vehicles program were introduced; portions of each of these two programs
were adopted in the final Clean Air Act Amendments of 1990.
Each of these proposals and programs has precipitated much debate
over the appropriate mechanisms for promoting alternative fuel use, and
over the proper role of government in setting such mechanisms in place.
Since implementation mechanisms can be controversial and are not
essential to estimating the environmental or economic impacts of
alternative fuel use, it seemed more expedient in this report to define
several possible scenarios of alternative fuel penetration into the
transportation sector, and to analyze the environmental, economic, and
energy supply impacts of each. By using the information which results
from the analysis of the scenarios, the desirability of an array of
combinations of alternative fuels, feedstocks, and degrees of market
penetration can be evaluated, thus providing an analytical framework for
evaluating future alternative fuel initiatives.
Rather than attempting to determine a single, best alternative fuel
for use in the United States, the purpose of this study is to provide
objective information on the environmental and economic potential of a
number of alternative fuels. The following discussion provides a summary
of the major findings of the report. First, a general summary of the
potential environmental and economic benefits of alternative fuel use is
presented. Second, various types of alternative fuel programs are
discussed, key elements and characteristics of a successful alternative fuel
program are identified, and several specific scenarios of alternative fuel
penetration are critiqued in this context. Finally, limitations of the
analysis, and areas where additional research is needed or planned, are
identified.
The technical analysis for this report was completed in the Fall of
1990. Since then, several legislative actions have taken place which will
likely have an impact on the conclusions reached in this study. The Clean
Air Act Amendments (CAAA) were finalized in November 1990. Included
in the CAAA are requirements for EPA to promulgate rules regarding
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reformulated gasoline as well as several programs which may involve ihe
use of alternative fuels. The partial tax exemption for fuels containing
alcohol was reduced, and the exemption extended to the year 2000, in the
Budget Reconciliation Act. In addition, the tax on gasoline was increased
5.0 cents per gallons as part of that same legislation. More recently, the
Administration proposed a National Energy Strategy (NES) that includes
recommendations regarding corporate average fuel economy (CAFE) and
the introduction of alternative fuels and alternative-fueled vehicles.
Future versions of this Environmental Study will need to update this
analysis to include the impact these new programs will have on the use ot
alternative fuels.
I. Discussion of the Implications of Alternative Fuel Use
As discussed in Appendix 2, the nation's energy outlook for the
future raises a great deal of concern. DOE and others predict that over the
next twenty years, real oil prices will double relative to current levels.[ 1 ]
In addition, consumption of oil is expected to increase while domestic oil
production wanes, driving oil imports to between 10.4 and 14.9 million
barrels per day (MMBPD), almost twice current levels, or between 54 and
67 percent of projected oil demand. The trade deficit resulting from oil
purchases is expected to increase from the 1989 level of $47 billion to
between $140 and $180 billion by 2010.2 In summary, a greater reliance
on supplies of oil that have been relatively unstable and have added to the
national debt is predicted.
In addition to these economic impacts, environmental and human
health damages will likely accompany any increase in energy consumption.
Increased consumption of conventional fuels will result in an increase in
the release of harmful pollutants into the atmosphere. In particular, the
increases in fuel consumption projected will result in commensurate
increases in emissions of C02, an important greenhouse gas. Growth in fuel
consumption will also increase total emissions of regulated pollutants, such
as VOCs, SO2, CO, and NOx, both from mobile and stationary sources. This
will strain the ability of major urban areas to attain federal air quality
standards, possibly precipitating requirements for additional, more
expensive pollution control hardware.
2Currently, the transportation sector consumes about 65 percent of crude oil used in
this country, or 8 MMBPD
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As the analysis contained in this report indicates, one potentially
effective option for dealing with both energy and environmental issues
would be to move the transportation sector away from the nearly
exclusive use of petroleum-based fuels. Currently, the transportation
sector (excluding aircraft and offroad vehicles) consumes about 8 MMBPD
of oil, nearly 65 percent of all oil used in the nation. The inability of this
sector to switch to alternative forms of energy severely limits the nation's
ability to reduce its reliance on imported oil. Switching a portion of the
nation's vehicles to alternative fuels would help to reduce our dependence
on imported oil. In addition, many of the alternative fuels discussed in the
report would provide significant environmental benefits relative to
petroleum based fuels, and could have beneficial economics to the
consumer.
The alternative fuel/feedstock combinations examined in the report
are shown in Figure I. Most of the alternative fuels considered would
provide significant air quality and global warming benefits relative to
current gasoline vehicles.3 Obviously, electric vehicles would produce very
few emissions (although emissions at the power plant could increase,
depending on the feedstock used to generate the electricity). However, as
shown in Appendix 4, electric vehicle costs are still somewhat prohibitive.
Each of the other fuels evaluated in the report would also likely produce
fewer emissions than gasoline vehicles, due primarily to reductions in
evaporative and refueling emissions. Emissions of VOCs (volatile organic
compounds), which are responsible for ozone formation, could decrease 35
to- .100 percent over emissions from gasoline vehicles. Air toxics emissions,
could also be reduced; it is estimated that alternative fuels could reduce
vehicle-related cancer incidences by 50 to 100 percent. In addition,
reductions in urban stationary source emissions might be possible for some
fuels produced in remote regions (e.g., fuels produced from Alaskan
natural gas, vented and flared gas, and fuels produced in rural areas).
3 Of course, some uncertainties exist regarding the quantification of the
environmental impacts of alternative fuels. A discussion of the uncertainties
surrounding these numbers can be found in Appendix 7
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Figure I
Fuel/Feedstock Combinations
Feedstock
Municipal Natural Solar
Fuels
Coal
Biomass*
Waste
Gas"
LPG
Energy
CNG
X
X
X
X
...
—
Electricity
X
X
X
X
X
Ethanol
—
X
• - -
—
...
LPG
—
—
—
X
—
Methanol
X
X
X
X
...
* Includes both agricultural and cellulosic sources.
** Includes domestic natural gas, foreign natural gas, natural gas that is
currently vented and flared, and Alaskan natural gas.
The use of many alternative fuels would also provide intrinsic global
warming benefits relative to gasoline. Most prominently, fuels derived
from vented and flared gas, municipal waste, and various other renewable
feedstocks would provide major global warming benefits; emissions of
global warming gases could be reduced by 50 or more relative to
conventional gasoline vehicles. Unfortunately, the quantities of many of
these feedstocks are somewhat limited. LPG and fuels derived from
"produced" natural gas (methanol and CNG) would provide only marginal
global warming benefits (and, under certain conditions, possible
detriments) relative to gasoline.
The use of fuels derived from coal would result in significant
increases in C02 relative to gasoline, although, as discussed in Appendix 7,
technologies exist which could control or capture CO2 emitted from coal-
based alternative fuel plants. If global warming improvements from the
transportation sector are desired, the use of alternative fuels derived from
"low-C02" feedstocks (biomass, municipal waste, vented and flared gas,
etc.) would provide one alternative to raising CAFE requirements. Another
alternative would be to introduce a system of C02 emission reduction
credits which would reward the manufacture of vehicles which operate on
fuels made either from feedstocks which contribute less CO2 than
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conventional fuels or from fuel production technologies which employ C02
recovery.
Several of the alternative fuels considered in the report would
provide economic benefits when compared to gasoline. Tables 1 and II
summarize the estimated gasoline equivalent pump prices in the years
2000 and 2010, respectively, for each fuel/feedstock combination
analyzed. As listed in the tables, fuels derived from remote natural gas
(methanol or CNG) could be supplied in potentially large quantities at a
price likely to be competitive with gasoline. CNG (for a dedicated vehicle)
could be priced profitably at the retail level to compete with gasoline
pump prices on the order of $1.00 per gallon; methanol (used in dedicated
vehicles) could similarly be priced competitively with gasoline. As landfill
costs increase, fuels derived from municipal waste could also become
economically attractive. Of course, the limited availability of the feedstock
and the heterogeneous composition of municipal waste make its large scale
use as an alternative fuel feedstock unlikely. Although limited somewhat
by availability, LPG and CNG produced from domestic natural gas would
also be economically attractive alternative fuel options; several biomass-
based fuels also show economic promise.
The use of many of the alternative fuels discussed in the report
would provide a reduction in oil import requirements as well as net energy
imports, if they were produced from domestic resources. Due to the vast
U.S. coal reserves, coal-based fuels such as methanol, electricity, and
methane would provide excellent near term options for displacing a large
quantity of petroleum fuels from the transportation sector. Several other
underutilized domestic resources, including Alaskan natural gas, biomass,
LPG, solar energy, and municipal waste, could be used to produce fuels
which would be able to displace imported gasoline in the near term, but to
a more limited extent. Solar energy (including biomass-based fuels) has
significant longer term potential as well. Certain of these fuels could also
prove to be cost competitive with gasoline at oil prices below $20 per
barrel.
Even fuels derived from foreign energy sources other than oil (i.e.,
natural gas) could reduce some of the risks associated with imported oil.
Many countries hold significant natural gas reserves which could be used
to provide substantial quantities of fuel for CNG or methanol vehicles. A
large number of these countries are located in South America, Africa, and
the Pacific Rim, in addition to the Middle East. The addition of any or
several of these natural gas-rich countries to the list of U.S. energy
suppliers would add competitive pressures which would serve to restrain
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Table I
Fuel/Feedstock Comparison
Gasoline Equivalent Pump Price, Year 2000 (1989$/gallon)
Gasoline Retail Price = $1.31 per gallon
Feedstock
Municipal Natural Solar
Fuels Coal Biomass Waste Gas ' LPG Energy
CNG '
1.71-2.09
1.32-1.62
1.26-1.53
1.09-1.51
— —
Electricity
1.12-1.87
1.23-2.05
1.12-1.87
••• 1.54-2.57
i
Ethanol
—
1.49-2.37
i
—
— —
LPG
...
—
—
0.87
f
Methanol
1.14-1.43
1.41-1.61
1.60-1.78
0.88-1.36
... —
Table II
Fuel/Feedstock Comparison
Gasoline Equivalent Pump Price, Year 2010 (1989$/gallon)
Gasoline Retail Price = $1.51 per gallon
Feedstock
Municipal Natural Solar
Fuels Coal Biomass Waste Gas LPG Energy
CNG.'
1.74-2.12
1.34-1.63
1.26-1.53 1
1.15-1.66
Electricity
' 1.18-1.96
—
1.28-2.12
1.18-1.96 1.54-2.57
<
Ethanol
—
1.22-2.64
7
— ... —
LPG
0.94
1
Methanol
1.25-1.52
1.41-1.66
1.60-1.83
0.88-1.45
1 Costs presented for CNG vehicles reflect a driving range lower than that of a conventional gasoline vehicle.
If CNG vehicles were designed to achieve an equivalent range, the costs would be commensurately higher.
2 Preliminary estimates based on anaerobic digestion, a highly inefficient process that is unlikely to be used for large scale
production of CNG. Costs could be significantly different if gasification technology were used.
3 Estimate based on landfill gas generation; cost could be significantly different if gasification technology were used.
4 Lower costs are for electric vehicle with driving range of 79-90 miles per charge. If electric vehicles were able to achieve a
range equivalent to conventional gasoline vehicles, the higher cost would likely be realized.
5 Preliminary estimate based on coal-fired generation. The conversion of municipal waste would likely require treatment of
byproducts using additional equipment that could affect the cost of generating electricity by this process.
6 Highest number indicates estimate for fuel mixed with gasoline (E85, M85).
7 The low end of the range is based on SERI's cost estimates for ethanol from biomass.
8 Preliminary estimate based on biomass conversion. Due to the potential need for byproduct treatment, the costs for
municipal waste gasification could be significantly different than those estimated here.
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oil price increases and reduce the risk of crippling energy supply
interruptions. As the preceding discussion illustrates, there are many
factors related both to the environment and the national economy which
must be considered carefully when a national alternative fuels program is
planned.
In summary, several combinations of alternative transportation ruels
and feedstocks could prove to be desirable both from an environmental
and an economic standpoint. The use of transportation fuels derived from
otherwise environmentally undesirable feedstocks, such as municipal
waste, from underutilized feedstocks, such as vented and flared or Alaskan
natural gas, or from domestic renewable resources would result in
significant environmental benefits, reducing emissions of ozone forming
hydrocarbons (VOCs) by 35 to 80 percent and global warming gases by 50
percent or more compared to conventional gasoline vehicles. Use of
alternative fuels derived from low-cost energy sources, such as vented and
flared and remote natural gas, could also result in significant economic
benefits; pump prices could be around SI.00 per gallon gasoline equivalent
for some of the alternative fuels analyzed. Many fuel/feedstock
combinations would result in benefits in both areas. Clearly, if the
appropriate mechanisms to encourage the use of alternative fuels were set
in place, the current and projected environmental impact and total fuel-
related cost of the U.S. transportation sector could be improved. As long as
sufficient flexibilities and fuel neutrality are provided for under an
alternative fuels program, the marketplace will ultimately determine
which feedstocks are most desirable and which fuel production
technologies are viable.4
II. Discussion of Alternative Fuel Use Scenarios
The scenarios of alternative fuel utilization evaluated in the report
provide information on the relative desirability of different levels of and
approaches to alternative fuels use. Three different scenarios of
alternative fuel use are evaluated in detail in the report. As will be
discussed, however, there are really only two basic types of alternative
fuel programs which can be pursued: a relatively broad, geographically
disperse program that attempts to achieve a certain level of alternative
fuel use, and a geographically concentrated, environmentally focused
program which attempts to both maximize environmental benefits and
4Of course, fuel neutrality does not insure that the maximum environmental benefits
of alternative fuel use under these programs will be realized.
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take advantage of available economies of scale. The implications of these
two types of programs are discussed in more detail below.
A broad-based program would provide for the production and sale of
a specific volume of alternative fuels, but would not include requirements
specifying the sale of vehicles to use alternative fuels, where fuels would
be used, or require that any particular environmental goals would be met.
Such a program would most likely begin with the introduction of flexible
fueled vehicles (FFVs) which could operate on either an alternative fuel or
conventional (gasoline) fuels. Although alternative fuel producers and
vehicle manufacturers would likely concentrate sales in high use areas,
each would market their product in the locations most convenient to their
existing business. The full environmental benefits of alternative fuels
would not likely be realized under such an approach, since use would not
necessarily be concentrated in the most polluted areas.
In addition to the reduced environmental benefits which could result
from this type of program, some reduction in economic efficiency could
also result. Since a widespread, developed distribution system for most
alternative fuels does not currently exist, fuel distribution and retailing
costs would be high, particularly during the initial transition period.
Because the locations where alternative fueled vehicles (AFVs) would be
sold would not be specified, a greater number of public refueling stations
would be required. The costs of distributing alternative fuels over a large
geographical area would be high, and investment in the necessary
distribution equipment would be somewhat risky due to uncertainties in
demand for alternative fuels in any given area. Of course, an efficient
market would tend to optimize fuel distribution costs and use would likely
be somewhat concentrated in centralized areas; however, uncertainties in
this type of program would make overall optimization difficult.5
5The fact that an individual segment of the transportation sector would tend to
optimize its operations does not necessarily mean that the economics of an
alternative fuels program would be optimized on the whole. For instance, due to
system logistics, two fuel suppliers may choose to distribute fuel in entirely different
locations, and thus minimize their own costs and investments, but, in so doing, dilute
the concentration of alternative fuel use, and thus require increased service station
modifications and costs. Conversely, auto manufacturers might choose to limit the
number of product lines on which alternative fuel technology is offered, reducing
manufacturing costs. This, however, would tend to expand the geographical area
over which alternative-fueled vehicles are sold, thus increasing fuel distribution
costs. Absent a perfectly efficient marketplace, some lack of overall optimization
would likely result.
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Obviously, for a given level of alternative fuel use, greater
geographical dispersion would allow vehicle manufacturers to be more
selective as to which product lines to make compatible with alternative
fuels. Without geographical constraints on the program, however, there
would be no incentive for automakers to focus alternatively-fueled vehicle
sales in a manner which would minimize alternative fuel distribution and
marketing costs. There would be some number of people in remote
locations who would purchase AFVs simply for the novelty. In order to
sell the desired (or required) volume of alternative fuels, fuel producers
would be required to either supply these customers at a higher cost or
induce additional AFV sales in urban areas through lowering fuel prices.
Thus, either fuel distribution costs would increase, or more alternative fuel
compatible vehicles than are necessary to displace the desired volume of
petroleum would be produced, or a combination of the two would occur,
the classic "chicken-and-egg" problem.
In contrast to the vagaries associated with a broad-based fuels
program, a geographically focused, environmentally driven program would
specifically require both the introduction of the appropriate vehicles and
the use of the alternative fuels in specific areas. This combination of
conditions would help to guarantee that the maximum environmental
benefits of the program would be realized. Alternative vehicle production
and sale, and alternative fuel use, could be targeted in the areas with the
greatest environmental need. Hence, the environmental efficiency of the
program would be maximized.
The economic efficiency of a geographically focused, environmentally
driven program is more difficult to evaluate. If one tries to saturate a
metro area with dedicated AFVs, it may be necessary to use subsidies to
encourage consumers to purchase these vehicles. However, the use of
subsidies to encourage AFV sales would merely involve a transfer of
payment rather than a net cost to society as a whole. The true societal cost
of using the vehicles and fuels would not be substantially changed.
There are other economic efficiencies to be gained from a
geographically focused alternative fuels program. Fuel producers could
locate plants in areas convenient to major markets, limiting transportation
costs for the fuel. The required number of alternative fuel refueling
stations would be reduced. Alternative fuel prices would thus be
minimized, and the consumer would be able to reap the full economic
advantages of alternative fuel use.
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In this context, three distinct scenarios of alternative fuel utilization
were described and evaluated in the report. These three scenarios differ
with respect to particulars of geographical focus, timing, and volume, and
help to illustrate the relative desirability of different levels and degrees of
alternative fuel use. The scenarios were chosen from among many
potential alternative fuels programs that appeared plausible at the time
this analysis was performed. As mentioned in the introduction, these
scenarios do not include any of the programs contained in the final Clean
Air Act Amendments, as these were not completed until November 1990;
EPA had completed the economic and environmental analyses of the
selected scenarios by that time.
The first scenario analyzed in this report addresses the economic and
environmental impacts of using the CAFE credits provided by the
Alternative Motor Fuels Act, an analysis EPA was required by AMFA to
include. In this first scenario, it is assumed that manufacturers take full
advantage of the CAFE credits available for the production of dual-fueled
or flexible-fueled vehicles capable of operating on natural gas or alcohols
(alternative fuels with compositions of at least 85 percent methanol or
ethanol) and that the vehicles are operated on the alternative fuel 100
percent of the time.
The second scenario explores the effects of a geographically focused
program similar to the Administration's Clean Alternative Fuels Program.
During the development of the Clean Air Act Amendments of 1990, the
Administration proposed a program that would require the use of
alternative fuels in the nine severe ozone non-attainment cities. EPA's
second scenario is patterned after this program; it would require the use of
alternative fuels in a percentage of new vehicles sold in the nine worst
ozone areas.
The third scenario looks at the impacts of a more geographically
disperse program, designed to displace a fixed volume of petroleum, one
million barrels per day (1 MMBPD), from U.S. consumption by 2010. This
scenario has been explored in detail by DOE and others as a potential
program for the introduction of alternative fuels into the transportation
fuels market.
The analysis presented in this report indicates that these specific
programs can differ in both environmental and economic efficiency.
Although some alternative fuel use under a geographically disperse
scenario would likely occur in high-ozone areas, the full environmental
efficiencies of alternative fuel use would not be realized. The maximum
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environmental "benefits of alternative fuel use will only be achieved when
use is targeted in the areas with the poorest air quality. From an economic
standpoint, even a low volume program, provided it is geographically
focused in urban areas, can achieve economies of scale, particularly in
distribution and infrastructure costs, and result in economic benefits. To
the extent that a low volume program loses geographic focus, however,
distribution and retailing costs increase, and overall economic impacts
become less favorable. As the affected volume of fuel grows, however,
distinctions between geographically focused and disperse scenarios begins
to fade. The analysis indicates that the level of alternative fuel use
required to displace 1 MMBPD of petroleum is high enough to insure
economies of scale in production and distribution, which makes the
economics of this third scenario attractive. If desired, this concept could
be extended to an environmentally focused program by enlarging it to
include more cities, thus displacing a greater volume of fuel and allowing
fuel producers to take even greater advantage of economies of scale
without loss of environmental benefits.
III. Areas of Further Study
This report is the first step in an ongoing analysis of the
environmental and economic impacts of alternative fuel use. The next
Report to Congress required by the Alternative Motor Fuels Act will be due
in December, 1992. Several important concepts were learned from this
study. Fuels produced from different feedstocks have different economic
and environmental effects which must be considered when choosing the
fuel to use and the feedstock from which it should be produced. The
magnitude of the benefits or costs of alternative fuel use depends on the
volume of fuel used and the geographical concentration of the program.
The three scenarios of alternative fuel utilization evaluated in the report
provide information on the relative desirability of different levels and
degrees of alternative fuels use. Absent a perfect understanding of these
issues, certain actions, e.g., implementing a fuel cycle carbon tax to reduce
emissions of C02, could be taken to insure that no detrimental effects will
result from an alternative fuels program.
EPA must continue to build on the work it began for this report, and
many of the issues discussed here could benefit from further analysis. To
achieve the goal of a complete, comprehensive study of alternative fuels,
EPA plans, and has already begun, to conduct meetings with industry to
explore research and technology developments in the areas of alternative
fuel production, alternative-fueled vehicle technology, and environmental
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protection and control technologies. In addition, EPA has developed an
Alternative Fuels Research Strategy that describes research needed to
improve health and ecological risk assessments of alternative fuels in
comparison to conventional fuels.
In many of the technical areas addressed in this report there is a
great deal of additional work and research which could be done. Many
developments can be expected in alternative fuel production technology
over the next few years, which could reduce the cost of alternative fuel
production. Similarly, much more needs to be learned about
environmental issues, such as global warming, air quality control, human
health effects, and ecological effects of alternative fuel use. Additional
understanding in each of these areas would be extremely useful as
alternative fuel implementation programs are debated.
There are several key areas of uncertainty in the analysis contained
in this report. First, the degree to which manufacturers will take
advantage of the CAFE credits provided in the AMFA is uncertain. The
question remains whether the AMFA credits are sufficient motivators to
cause automobile manufacturers to produce any significant quantity of
alternative fueled vehicles. As discussed in Appendix 2, absent a
significant increase in petroleum-based fuel prices or requirements for
alternative fuel vehicle production and fuel use, it is unlikely that the use
of alternative fuels by the transportation sector will increase substantially.
As the availability of the credits draws nearer, a more precise analysis of
the actual impacts of the legislation would be desirable. Second, as
mentioned above, breakthroughs in alternative fuel production technology
could result in significant reductions in production cost which could
enhance the economic attractiveness of alternative fuels. As additional
development occurs," an even better understanding of the economic
impacts of alternative fuels will develop.
The fuel production technologies and costs presented in Appendix 4
are based on the information and estimates currently available. As
research into some of these technologies continues, the fuel production
costs will likely improve. A clearer understanding of some of the
technologies will make it easier to assess the economics of each design; this
understanding may be gained with further study of emerging technologies.
In addition, a better picture of how distribution and infrastructure costs
may change with different degrees of alternative fuel penetration and
geographical focus would help to improve the estimates of these costs.
xiii
-------
More sophisticated modelling of the relationship between crude oil
price and demand would be useful. As discussed in Appendices 5 and 6,
reductions in crude oil demand resulting from alternative fuel use could
possibly cause the price of oil to drop, resulting in substantial savings in
crude fuel purchases and the net import bill. A greater knowledge or the
response of non-transportation markets to the increased availability c oil
would also be desirable.
The overall air quality impacts, environmental effects (including
ecological concerns), and health effects of alternative fuels must be
explored more thoroughly. The air quality impacts of the entire fuel cycle,
from feedstock to production to vehicle use, must be analyzed to
determine the net changes which can be caused by alternative fuels.
Although vehicular emissions are important, these other areas must be
examined to insure that the environment will experience net beneficial
rather than detrimental results of the use of these fuels. Health effects of
alternative fuel use must also be analyzed to determine potential safety
issues which should be considered. EPA will continue to research these
topics; future versions of this report will address these issues in greater
detail.
Additional research into the effects of greenhouse gases on global
climate change is also desirable. Many uncertainties exist in the analysis
of greenhouse gas emissions. The impact these gases have on the
atmosphere is not yet fully understood. The emissions of greenhouse gases
from both alternative fuels and fuel production processes need to be more
accurately quantified (e.g., energy requirements of feedstock development
and conversion). A clearer understanding of the relationship between
different greenhouse gases and net emissions from mobile sources would
be beneficial. Further study of the emission characteristics of alternative
fueled vehicles would also be useful, as would additional research into
emissions from alternative fuel production facilities.
EPA is continuing efforts in the area of alternative fuels, looking at
many of the environmental and economic impacts of alternative fuels,
including production, distribution, and use. Many uncertainties exist
regarding the health effects both of alternative fuels and of gasoline; more
research is needed to quantify them. In addition, information is lacking on
many of the environmental impacts of alternative fuel production and use.
particularly from an ecological point of view. EPA is continuing research in
these areas; the results of such studies will enhance knowledge of the
potential costs and benefits of alternative fuels relative to gasoline.
xiv
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References
1. Annual Energy Outlook 1990: Long Term Projections. EIA, DOE,
January 1990.
xv
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Environmental and Economic Study of
Alternative Motor Fuels Use
Table of Contents
Section Titles Page
I. Overview of the U.S. Energy Picture: Economic and
Environmental Status 3
A. U.S. Energy Situation 3
B. Environmental Impacts of Motor Vehicle Use 7
II. Potential Fuel/Feedstock Combinations 10
III. Scenarios of Alternative Fuel Use 1 2
IV. Environmental Impacts of Alternative Fuel Use 1 6
A. Regulated Pollutant and Air Toxic Impacts 1 6
1. Vehicular Emissions 1 7
a. Regulated Emissions 1 7
b. Air Toxics Emissions 1 9
2. Stationary Source Emissions 2 2
3. Conclusion 2 3
B. Global Warming Impacts 2 3
1. Overview 23
a. Transportation Perspective 2 4
b. Relative Global Warming Potentials of
Greenhouse Gases 2 4
2. Greenhouse Gas Emissions from Transportation
Fuel Use 2 5
a. Gasoline Vehicles 2 6
b. CNG Vehicles 2 6
c. Electric Vehicles 2 8
d. Ethanol Vehicles 2 9
e. LPG Vehicles 3 0
f. Methanol Vehicles 3 0
C Options for Mitigating Greenhouse Gas Increases
Resulting from Alternative Fuel Production and Use 3 1
-------
Table of Contents, cont'd
Section Titles Page
D. Other Environmental Impacts 3 2
1. Compressed Natural Gas 3 3
2. Electricity 3 3
3. Ethanol 34
4. Liquefied Petroleum Gas 3 5
5. Methanol 3 5
E Conclusions 3 6
V. Economic Impacts of Alternative Fuel Production and Use 3 6
A. Compressed Natural Gas Prices 3 7
B. Electricity Prices 4 1
C Ethanol Pump Prices 4 4
D. LPG Pump Prices 4 8
E Methanol Pump Prices 4 9
F. Other Economic Impacts 5 5
Q Summary 56
VI. Summary and Conclusions 5 6
VII. Plans for Future Study - AMFA Report to Congress II 5 9
References
60
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Environmental and Economic Study of
Alternative Motor Fuels Use
Report to Congress
The Alternative Motor Fuels Act of 1988 (AMFA) established a
system of corporate average fuel economy (CAFE) credits, effective in the
1993 model year, designed to stimulate the production by automobile
manufacturers of vehicles capable of operating on alcohols or natural gas.1
In section 400EE (b) of that legislation, Congress commissioned the
Environmental Protection Agency to provide a series of four biennial
reports, including:
"(A) a comprehensive analysis of the air quality, global climate
change, and other positive and negative environmental impacts, if
any, including fuel displacement effects, associated with the
production, storage, distribution, and use of all alternative motor
vehicle fuels under the Alternative Motor Fuels Act of 1988, as
compared to gasoline and diesel fuels; and
"(B) an extended reasonable forecast of the change, if any, in
air quality, global climate change, and other environmental effects of
producing, storing, distributing, and using alternative motor vehicle
fuels, utilizing such reasonable energy security, policy, economic, and
other scenarios as may be appropriate."
The present volume is the first in this required series of reports.
In addition to the requirements outlined in the Act itself, the
Conference Report 100-929, which accompanied the AMFA, stated that
"the analysis and forecast shall be based on a variety of reasonable
scenarios concerning market penetration of the alternative fuels, their
likely feedstocks, changes in fuel consumption in the transportation sector,
any displacement of fuels in other sectors, and changes in technology." It
was further stated that "the Environmental Protection Agency shall include
an assessment of the economic costs and benefits and shall include a
discussion of carbon dioxide impacts from the use of alternative fuels in
1 Public Law 100-494; Oct. 14, 1988, 102 Stat. 2441
-------
the transportation sector as compared to the use of other fuels in that
sector and identify ways to offset any increases that may result."
Since the AMFA directed EPA to study environmental, global
warming, economic, and fuel displacement impacts of alternative fuel use
but not to perform an analysis of specific implementation mechan,- ns, it
seemed more expedient in this report to define several possible scenarios
of alternative fuel penetration into the transportation sector, and to
analyze the relative environmental, economic, and energy supply impacts
of each. In general, the specific scenarios analyzed fall into one of two
categories: 1) an environmentally driven, geographically focused program,
or 2) a volume driven, geographically disperse program. For each scenario
of alternative fuel penetration, the impacts of using various combinations
of fuels and feedstocks were evaluated. Using the information resulting
from this analysis, the desirability of an array of combinations of
alternative fuels, feedstocks, and degrees of market penetration can be
evaluated, thus providing an analytical framework for evaluating future
alternative fuel initiatives.
A great deal of activity has taken place since the passage of the
AMFA, aimed at spurring the broad-scale introduction of alternative
transportation fuels into the marketplace. In June of 1989, President Bush
announced a proposal for revising the Clean Air Act, which contained
provisions requiring the introduction of clean, alternative-fueled vehicles
in the nation's nine highest ozone cities. In the recent Congressional
deliberations over amendments to the Clean Air Act, concepts for an
alternative-fueled fleet vehicle program as well as a California clean
vehicles program were introduced; portions of each of these two programs
were adopted in the final Clean Air Act Amendments of 1990, which were
passed in November, 1990. Each of these proposals and programs has
precipitated much debate over the appropriate mechanisms for promoting
alternative fuels use, and over the proper role of government in setting
such mechanisms in place. As debates such as these continue, the
conclusions of the studies by EPA will provide useful information on the
environmental and economic impacts of alternative fuels use.
Rather than attempt to determine a single best alternative fuel for
use in the United States, the purpose of this analysis is to provide
information on the environmental and economic potential of a number of
alternative fuels to allow for comparison between these fuels and gasoline.
The main conclusions of this study are presented below, with supporting
data and analysis contained in the Appendices. First, a summary of the
U.S. energy situation and an overview of the effect of transportation on the
2
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environment is presented in Section I. In Section II, the alternative fuels
and the fuel/feedstock combinations analyzed are discussed, including
relative availability of the feedstocks. A discussion of the relative
environmental and economic consequences of different types of alternative
fuel implementation programs is presented in Section III. In Section IV,
the general environmental impacts of alternative fuel use are presented,
and a summary of the economic impacts of alternative fuel use can be
found in Section V. Finally, in Section VI the conclusions of this study are
summarized and issues to be addressed in the next AMFA report are
discussed.
The technical analysis for this report was completed in the Fall of
1990. Since then, several legislative actions have taken place which will
likely have an impact on the conclusions reached in this study. The Clean
Air Act Amendments (CAAA) were finalized in November 1990. Included
in the CAAA are requirements for EPA to promulgate rules regarding
reformulated gasoline as well as several programs which may involve the
use of alternative fuels. The partial tax exemption for fuels containing
alcohol was reduced, and the exemption extended to the year 2000, in the
Budget Reconciliation Act. In addition, the tax on gasoline was increased
5.0 cents per gallons as part of that same legislation. More recently, the
Administration proposed a National Energy Strategy (NES) that includes
recommendations regarding corporate average fuel economy (CAFE) and
the introduction of alternative fuels and alternative-fueled vehicles.
Future versions of this Environmental Study will need to update this
analysis to include the impact these new programs will have on the use of
alternative fuels.
I. Overview of the U.S. Energy Picture: Economic and Environmental
Status
The following sections present a brief overview of the United States'
energy picture and the environmental implications of the essentially
exclusive use of gasoline by the transportation sector. Energy supply and
consumption information, including historical trends and international
data, are discussed in greater detail in Appendix 2.
A. U.S. Energy Situation
The U.S. currently consumes a total of over 80 quadrillion Btu
(quads) of energy each year, with the transportation sector accounting for
over 25 percent of this energy use.[l] As Figure 1 illustrates, the primary
3
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sources of energy used in the United States are petroleum (42 percent),
natural gas (23 percent), and coal (24 percent).[2] Hydropower and
nuclear power are other nonrenewable energy sources used currently in
the U.S.; wood, waste, geothermal, wind, photovoltaic, and solar thermal
energy are also used for electricity generation, though to a much lesser
extent.
Figure 1
U.S. ENERGY CONSUMPTION
Other
Coal
By far, the largest energy resource consumed in this country
continues to be petroleum. Since 1983, consumption of petroleum
products has increased, reaching a current level of roughly 17 million
barrels per day (MMBPD).[1] Currently, about 50 percent of this oil is
imported, at a cost to the nation of approximately $53 billion (in 1989).2
As Figure 2 shows, since 1985, the contribution of domestic production to
oil consumed in the U.S. has declined, and this trend is projected to
continue. The Energy Information Administration (EIA) predicts that by
the year 2010, domestic production of petroleum will have declined to a
level of 6.0-7.5 MMBPD (including natural gas liquids).[2] As domestic oil
production declines and consumption increases, the level of U.S. imports is
projected to increase, to between 54 and 67 percent by 2010. These
imports will increase the trade imbalance and exacerbate the resulting
trade deficit.
^Currently, the transportation sector consumer about 65 percent of crude oil used in
this country, or 8 MMBPD.
4
-------
While crude oil is used in many applications, as shown in Figure 3, by
far the majority is used to provide fuel for the transportation sector, a
sector which is almost exclusively (97 percent) dependent on petroleum
based fuels. As the transportation sector continues to use more petroleum
products, the U.S. will become increasingly dependent on imported oil.
Although vehicles today are more fuel efficient than they were twenty
years ago, vehicle miles travelled by American cars have doubled over
that time period, and continue to grow. Hence, petroleum consumption by
the transportation sector will continue to rise, as will imports of petroleum
products. This increased consumption of petroleum could have significant
impacts on the environment as well.
Figure 2
Total U.S. Petroleum Consumption, 1973-1989
OPEC Imports, Non-OPEC Imports and Domestic Production
Expressed as Percent of Total Consumption
73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
5
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Figure 3
U.S. PETROLEUM CONSUMPTION
Utilities
Residen,ia|
Industry
Transportation
DOE projects crude oil prices to be between about $28 and $34 per
barrel (1989$) in 2000 and $37 and $47 per barrel in 2010, depending on
the economic conditions at the time.[2] Retail motor gasoline prices are
projected to range from $1.13 to $1.40 per gallon in 2000 and between
$1.24 and ol.73 per gallon in 2010.3-4 Regardless of which of the economic
conditions analyzed by DOE are realized, the cost of petroleum products to
the consumer will continue to increase from current levels. For this
analysis, DOE's base case projections of $1.31 per gallon in 2000 and $1.51
per gallon in 2010 were used for comparison.
If a reduction in oil imports is desired, the dependence of the
transportation sector on petroleum products will have to be reduced, and
alternate sources of energy will have to be used to produce transportation
fuels. Historically, three fossil fuels: petroleum, natural gas, and coal, have
accounted for the bulk of domestic energy production. As improved
methods of extraction are developed, oil shale may gain importance as a
fossil fuel resource of the U.S. In addition to these traditional resources,
the U.S. has many alternative energy resources, including renewable
energy resources, available for the production of transportation fuels.
Estimates of the U.S. supply of energy feedstocks are presented in Table
3The prices listed were converted from DOE's prices using the higher heating value
of gasoline, per DOE convention. See any issue of EIA's Monthly Energy Review.
''These projections do not include the highway fuel tax increases which resulted
from the budget deficit reduction efforts of 1990.
1.[1,3,4]
6
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Table 1
Supply of Energy Feedstocks
(Current Annual U S. Oil Consumption = 6.2 billion barrels/year)
Crude Oil
Shale Oil^
Natural Gas
Coal
Biomass, (Annual)
Corn. (Annual)
Municipal Waste, (Annual)
LPG
U.S. Reserves
(Billion OEB1
27
200
33
1,054
0.8-5
0.2
0.3
5
Source of Data
DOE/EIA
Reference
DOE/EIA
DOE/EIA
Various
USDA
SERI
DOE/EIA
[4]
lOn an energy content basis.
2This figure represents shale oil recoverable at a cost of less that $50 per barrel.
As shown by the table, coal is by far the United States' most plentiful
energy resource. Renewable feedstocks, such as biomass, corn, and
municipal waste, which are produced annually, could also contribute
significantly towards displacing petroleum consumption.
In spite of the availability of a large quantity and variety of domestic
energy resources, substantial production of alternative fuels from these
feedstocks will not likely be realized because of the difficulties a new fuel
confronts when trying to penetrate a gasoline dominated infrastructure.
Also, the fuel cost per mile to the consumer of using gasoline is at its
lowest level of the last 20 years, as illustrated in Figure 4. Consumers
alone will unlikely be driven to demand new fuels, and fuel producers and
vehicle manufacturers will only produce what is in demand. If reduced oil
imports are to be achieved, and major environmental benefits (as
discussed in later sections) are desired, specific programs requiring the use
of alternative fuels will have to be initiated.
B. Environmental Impacts of Motor Vehicle Use
The transportation sector is a major source of emissions which
contribute to air quality problems in the U.S. While emissions of pollutants
(including regulated pollutants and air toxics) from gasoline vehicles have
been decreasing slightly in the last decade, motor vehicles still account for
significant percentages of total annual volatile organic compound (VOC),
carbon monoxide (CO), and nitrogen oxide (NOx) emissions, as shown in
7
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Figure 4
1
12 T
9
8
11 --
9
10 ..
c
e
n
9 «.
t
s
8 -¦
P
7 --
e
r
6 --
m
i
1
5 --
e
4
Average Real Fuel Cost per Mile
(LDV - Gasoline)
+
+
70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
Figure 5.[5] During air quality episodes, transportation contributions can
be much greater. VOC contribution increases during the hot summer
periods when the ozone NAAQS is most frequently violated, and CO
contribution is greater during cold winter periods when the CO NAAQS is
most frequently violated. Transportation sources also account for about 58
percent of the emissions of compounds which have been determined to be
proven or probable human carcinogens.[6]
Gasoline fueled vehicles also contribute to greenhouse gas emissions,
through the release of C02 and trace greenhouse gases. These include
methane (CH4), nitrous oxide (N2O), and chlorofluorocarbons (CFCs), among
others. U.S. transportation accounts for approximately 5 percent of total
CO2 emissions, 11 percent of total CFCs, and less than 1 percent of CH4 and
N2O, or about 7 percent of global greenhouse gas emissions. (The
8
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transportation sector contributes roughly 30 percent of U.S. greenhouse gas
emissions.) The greenhouse gas emissions of gasoline and alternative fuels
are discussed in more detail in a later section of this report, as well as in
the Appendices.
Figure 5
Transportation's Contribution to Regulated Pollutant Emissions
NQx Urban VOCs
H Transportation ~ Other Sources
Clearly the transportation sector is one of the major contributors to
air quality problems in the United States. If solutions to air quality
problems are to be found, further improvements from mobile sources must
be seriously considered. These solutions must address all sources of
emissions, from the fuel production facility to the vehicle. Many of the
alternative fuels analyzed in this report have the potential to provide
significant benefits in the area of air quality.
9
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II. Potential Fuel/Feedstock Combinations
In the context of the transportation situation described in Section I,
several scenarios of alternative fuel penetration into the transportation
fuels market were constructed and analyzed for this report. Under each
scenario, the impacts of several alternate fuels were examined.
Compressed natural gas (CNG), electricity, ethanol, liquefied petroleum gas
(LPG), and methanol are the major alternative fuels discussed in this
report. Reformulated gasoline, though it offers certain environmental
advantages relative to conventional gasoline, does not represent an
alternative to petroleum fuels per se, and thus was not considered. In
addition, several alternative fuels such as hydrogen, solar energy, and
others which may play a role in the long term, were not analyzed in this
report due to timing constraints; several of these additional fuels will be
looked at in detail in subsequent versions of this environmental study.
The fuels listed above can be produced from many of the fossil fuel
and nonconventional resources discussed in Section I, as illustrated by the
matrix of Figure 6. In this figure, "natural gas" connotates methane from
four sources: domestic (lower-48) production, foreign production, gas
which is currently vented and flared (natural gas coproduced with crude
oil), and Alaskan natural gas. Biomass feedstocks include both corn
(currently used for ethanol production) and other cellulosic materials. A
complete discussion of each of these feedstocks can be found in Appendix
4.
Many of the feedstocks in Figure 6 are renewable energy sources.
Currently, renewable energy accounts for about 7 percent of the total
energy consumed in the U.S.[1] Several forces, including an increase in the
cost of conventional energy, a growing concern for environmental
problems, and a decrease in the delivered energy cost for renewable
energy technology, will contribute to the increased use of these feedstocks.
Of course, the potential for any of these feedstocks to supply the
demand for an alternative fuel depends on its availability. The breakdown
of recoverable domestic fossil fuel resources can be found in Figure 7.[7]
Proven, recoverable coal reserves account for about 80 percent of the
United States' resources, or about 1050 billion oil equivalent barrels.
(Conventional crude oil reserves are estimated at about 27 billion barrels.)
The U.S. has more coal than any other nation. In contrast, the United
States holds only 4 percent of the world total reserves of natural gas,
equivalent to approximately 33 billion oil equivalent barrels.fl] U.S.
natural gas liquids reserves (which includes both LPG and natural gasoline)
10
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Figure 6
Fuel/Feedstock Combinations
Feedstock
Municipal Natural Solar
Fuels
Coal
Biomass*
Waste
Gas"
LPG
Energy
CNG
X
X
X
X
...
—
Electricity
X
X
X
X
¦ • ¦
X
Ethanol
...
X
...
...
¦ m m
m m m
LPG
—
—
—
—
X
Methanol
X
X
X
X
...
* Includes both agricultural and cellulosic sources.
** Includes domestic natural gas, foreign natural gas, natural gas that is
currently vented and flared, and Alaskan natural gas.
Figure 7
U.S. FOSSIL FUEL RESERVES
Shale Oil
Natural Gas
Crude Oil
Coal
1 1
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have been estimated at over 8 billion barrels but would not likely be
sufficient to satisfy large scale demand for alternative fuels.[8]
III. Scenarios of Alternative Fuel Use
As discussed at the beginning of this report, each of the alternative
fuel programs which have been considered since the Alternative Motor
Fuels Act was passed has precipitated a great deal of debate over the
appropriate mechanisms for promoting alternative fuel use, and over the
proper role of government in setting such mechanisms in place. Rather
than focus on implementation mechanisms in this report, since these can
be controversial and are not essential to estimating the environmental or
economic impacts of alternative fuel use, it seemed more expedient to
define several possible scenarios of alternative fuel penetration into the
transportation sector, and to analyze the environmental, economic, and
energy supply impacts of each. By following this approach, the desirability
of an array of combinations of alternative fuels, feedstocks, and degrees of
market penetration can be evaluated, thus providing an analytical
framework for evaluating future alternative fuels initiatives.
The scenarios of alternative fuel utilization evaluated in this report
provide information on the relative desirability of different levels of and
approaches to the use of alternative fuels. Three different scenarios of
alternative fuels use are evaluated in detail in Appendix 3. As will be
discussed in the following paragraphs, however, there are really only two
basic types of alternative fuel programs which can be pursued: a
relatively broad, volume oriented, geographically disperse program that
attempts to achieve a certain level of alternative fuel use, and an
environmentally driven, geographically focused program which attempts
to both maximize environmental benefits of alternative fuel use and take
advantage of available economies of scale. The implications of these two
types of programs are discussed in more detail below.
A broad-based program would provide for the production and sale of
a specific volume of alternative fuels, but would not necessarily include
requirements specifying the sale of vehicles to use alternative fuels, where
fuels would be used, or require that any particular environmental goals be
met. Such a program would most likely begin with the introduction of
flexible fueled vehicles (FFVs) which could operate on a mixture of an
alternative fuel and a conventional fuel (gasoline). Although alternative
fuel producers and vehicle manufacturers would likely concentrate sales in
high use areas, each would market their product in the locations most
12
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convenient to their existing business. The full environmental benefits of
alternative fuels would not likely be realized, since their use would not
necessarily be targeted in the most polluted areas.
In addition to the reduced environmental benefits which could result
from this type of program, some loss of economic benefits could also result.
Since a widespread, developed distribution system for most alternative
fuels does not currently exist, overall economics would be less attractive,
particularly during the transition period. Because the locations where
alternative fueled vehicles (AFVs) would be sold would not be specified,
and would presumably be spread over a large geographical area, a greater
number of public refueling stations would be required. Distribution costs
would be high, since investment in the necessary distribution equipment
would be somewhat risky due to uncertain and widely dispersed demand.
Of course, an efficient market would tend to optimize fuel distribution
costs and use would likely be somewhat concentrated in centralized areas;
however, uncertainties in this type of program would make overall
optimization difficult.5
Of course, an efficient market would tend to optimize fuel
distribution costs and use would likely be somewhat concentrated in
centralized areas. However, uncertainties in this type of program would
make optimization difficult. Obviously, for a given level of alternative fuel
use, greater geographical dispersion would allow vehicle manufacturers to
be more selective regarding which product lines to make compatible with
alternative fuels. Without geographical constraints on the program,
however, there would be no incentive for automakers to focus
alternatively fueled vehicle sales in a manner which would minimize
alternative fuel distribution and marketing costs. There would be some
number of people in remote locations who would purchase AFVs simply
for the novelty. In order to sell the desired (or required) volume of
5 The fact that an individual segment of the transportation sector would tend to
optimize its operations does not necessarily mean that the economics of an
alternative fuels program would be optimized on the whole. For instance, due to
system logistics, two fuel suppliers may choose to distribute fuel in entirely different
locations, and thus minimize their own costs and investments, but in so doing, they
would dilute the concentration of alternative fuel use, and thus require increased
service station modifications and costs. Conversely, auto manufacturers might
choose to limit the number of product lines on which alternative fuel technology is
offered, reducing manufacturing costs. This would tend to expand the geographical
area over which alternative-fueled vehicles are sold, thus increasing fuel
distribution costs. Absent a perfectly efficient marketplace, some lack of overall
optimization would likely result.
13
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alternative fuels, fuel producers would be required to either supply these
customers at a higher cost or induce additional AFV sales in urban areas
by lowering fuel prices. Thus, either fuel distribution costs would . urease,
or more alternative fuel compatible vehicles would be produced ti ^n are
necessary to displace the desired volume of petroleum, or a combination of
the two would occur: the classic "chicken-and-egg" problem.
In contrast to the vagaries associated with a broad-based fuels
program, a geographically focused, environmentally driven progr .m would
specifically require both the introduction of the appropriate venicles and
the use of the alternative fuels in specific areas. This combination of
conditions would help to guarantee that the maximum environmental
benefits of the program would be realized. Alternative vehicle production
and sale, and alternative fuel use, could be targeted in the areas with the
greatest environmental need. Hence, the environmental efficiency of the
program would be maximized.
The economic efficiency of a geographically focused, environmentally
driven program is more difficult to evaluate. If one tries to saturate a
metro area with dedicated AFVs, it may be necessary to use subsidies to
encourage consumers to purchase these vehicles. However, the use of
subsidies to encourage AFV sales would merely involve a transfer of
payment rather than a net cost to society as a whole. The true societal cost
of using the vehicles and fuels would not be substantially changed.
There are other economic efficiencies to be gained from a
geographically focused alternative fuels program. Fuel producers could
locate plants in areas convenient to major markets, limiting transportation
costs for the fuel. The required number of alternative fuel refueling
stations would be reduced. Alternative fuel prices would thus be
minimized, and the consumer would be able to reap the full economic
advantages of alternative fuel use.
In the context of these two potential types of alternative fuel
programs, three distinct scenarios of alternative fuel utilization are
described in the report. Scenario 1 is constructed assuming the sale of
flexible-fueled alternative-fueled vehicles, beginning in model year 1993,
in quantities sufficient to fully utilize the CAFE credits provided under the
Alternative Motor Fuels Act (AMFA). Scenario 2 is equivalent to the
original Administration Clean Air Act proposal for alternative-fueled
14
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vehicles in the nine highest ozone cities.6 Scenario 3 is based on a scenario
which has been analyzed by DOE in the past, the displacement of one
million barrels per day from U.S. petroleum consumption. In each of these
scenarios, a schedule for the sale of alternative-fueled vehicles is defined,
the amount of gasoline displaced from the transportation sector is
quantified, and the impact of the various assumptions concerning energy
price, VMT growth, and fuel economy are addressed. These analyses may
be found in Appendix 3.
The analysis indicates that the specific programs represented by
Scenarios 1, 2, and 3 can differ in both environmental and economic
efficiency. Although some alternative fuel use under a geographically
disperse scenario would likely occur in high-ozone areas, the full
environmental efficiencies of alternative fuel use would not be realized.
The maximum environmental benefits of alternative fuel use will only be
achieved when use is targeted in the areas with the poorest air quality.
From an economic standpoint, even a low volume program, provided it is
geographically focused in urban areas, can achieve economies of scale,
particularly in distribution and infrastructure costs, and result in economic
benefits. To the extent that a low volume program loses geographic focus,
however, distribution and retailing costs increase, and overall economic
impacts become less favorable. As the affected volume of fuel grows,
however, distinctions between geographically focused and disperse
scenarios begins to fade. The analysis indicates that the level of
alternative fuel use required to displace I MMBPD of petroleum is high
enough to insure economies of scale in production and distribution, which
makes the economics of this third scenario attractive. If desired, this
concept could be extended to an environmentally focused program by
enlarging it to include more cities, thus displacing a greater volume of fuel
and allowing fuel producers to take even greater advantage of economies
of scale without loss of environmental benefits.
6The Clean Air Act Amendments were passed in November, 1990; EPA was finalizing
this report at this time. Although the CAAA does not contain the programs originally
proposed by the Administration, it does contain several alternative fuel programs,
including the national fleets program and the California program. Since the purpose
of the scenarios evaluated in this report is to provide a basis for comparison between
different types of programs, EPA's analysis was not altered. The programs under the
CAAA would be expected to result in commensurate, although lower, environmental
benefits and slightly higher economic costs (due to the decreased economies of
scale) when compared to a program of the size of Scenario 2.
15
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IV. Environmental Impacts of Alternative Fuel Use
This section presents the environmental impacts of the alternative
fuel/feedstock combinations described in Figure 6. For each alternative
fuel/feedstock combination considered, the likely effects on emissions of
regulated pollutants (VOC, NOx, CO, S02, etc.), air toxics, and greenhouse
gases (CO2, CH4, etc.) are quantified. In addition, other important
environmental concerns related to alternative fuel use, such as potential
groundwater contamination and spill issues, are discussed. The
information presented regarding regulated pollutants is primarily a
summary of the results contained in several Special Reports written by
EPA.[9,10,12,19] These documents should be referred to if more details
regarding regulated pollutants are desired. In contrast, most of the
information related to greenhouse gases has been developed since these
Special Reports were written and is presented below in detail. A complete
discussion of each of these issues may be found in Appendices 7, 7-A, and
7-B.
A. Regulated Pollutant and Air Toxic Impacts
Most of the alternative vehicle fuels considered in this report have
certain attractive environmental characteristics. All of the fuels are
projected to result in lower in-use vehicular emissions of ozone forming
hydrocarbons (VOCs) than current gasoline vehicles; reductions of 35 to
100 percent are estimated.7 These estimates are based on the assumption
that mechanisms would have to be put in place to prevent vehicle
manufacturers from reducing the degree of emissions control on AFVs in
order to enhance other features (cost, performance, etc.) of these vehicles.
In addition to reductions in VOC emissions, if further CO reductions are
needed, many of the fuels considered would be able to operate under lean
combustion conditions, thus reducing CO emissions. Many of the toxic
emissions associated with gasoline use, such as benzene and 1,3-
butadiene, would be reduced as well, although the potential for increases
in other toxic pollutants such as aldehydes does exist in some cases.
In addition to vehicular emissions, however, changes in emissions
from fuel production facilities and fuel distribution systems would be
expected to occur as alternative fuels increase their presence in the
7 Since the Clean Air Act Amendments had not been finalized when this analysis was
completed, EPA was unable to make emissions comparisons between alternative fuels
and reformulated gasoline. Future versions of this report will analyze the
environmental and economic impacts of reformulated gasoline.
16
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marketplace. Certain alternative fuels, such as methanol derived from
natural gas, would likely be manufactured in foreign locations, as some of
the gasoline consumed in the U.S. currently is. Other alternative fuels,
such as biomass- and coal-based fuels, would likely be manufactured
exclusively in domestic plants. Emissions from these fuel production
facilities, and the location of those facilities, are thus important
considerations. Both vehicular and stationary source emissions are
discussed in greater detail below.
1. Vehicular Emissions
This section will discuss the impact of the use of alternative motor
fuels on light-duty vehicle emissions. The emissions to be discussed
include the regulated emissions-volatile organic compounds (VOCs) (with
respect to ozone formation), carbon monoxide (CO) and nitrogen oxides
(NOx)--as well as emissions of compounds which have been determined to
be proven or probable human carcinogens. The latter emissions are
commonly called air toxics.
a. Regulated Emissions
The primary environmental benefit in the area of regulated
emissions of the use of alternative fuels will be reductions in urban ozone
levels due to reductions in ozone-forming VOCs. This discussion deals only
with VOC emissions associated with the combustion of a fuel and
evaporative losses from the vehicle; those emissions due to production and
distribution of the fuel are discussed separately. By coupling the mass VOC
emissions with the appropriate reactivity factors, gasoline-equivalent VOC
emissions can be determined. It should be noted that these reactivity
factors are still preliminary; additional work in this area is currently being
performed.
The results of the VOC emissions analysis are shown in Table 2. As
can be seen, each of the alternative fuels analyzed offer significant VOC
benefits over gasoline, though it is important to note that a decrease in
vehicular VOC emissions does not translate to an equivalent reduction in
ozone formation. The effect of other emission sources, and factors such as
local atmospheric conditions must also be considered. The use of CNG
fueled vehicles is expected to significantly reduce ozone formation because
the reactive non-methane hydrocarbons (NMHC) are typically only 5-10
percent of total exhaust HC emissions.[9] Relatively unreactive methane
comprises the other 90-95 percent. By comparison, in a gasoline vehicle
the exhaust is typically 65-95 percent NMHC. LPG-fueled vehicles are
17
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expected to have VOC emission factors similar to CNG, though the ozone-
forming potential of emissions from an LPG vehicle could be somewhat
higher. More data is needed before the VOC impact of LPG vehicle
emissions can be better estimated. In addition, a significant portion of the
emissions from LPG vehicles will be propanes and butanes, due to the
composition of the fuel. Because both CNG and LPG are closed fuel systems,
dedicated vehicles are expected to have no evaporative emissions, in
contrast to conventional gasoline vehicles.
As shown in Table 2, per vehicle reductions of gasoline-equivalent
ozone-forming VOC emissions are 44 and 80 percent for M85 and M100
respectively, compared to gasoline vehicles.[10] This is primarily due to
lower mass emissions of NMHC and to the low reactivity of methanol.
Because of the low hydrocarbon content and low Reid vapor pressure
(RVP) of the fuel, no NMHC evaporative emissions are expected from
dedicated methanol vehicles. Vehicles operated on M85 , or course, will
have NMHC exhaust and evaporative emissions, albeit significantly lower
than those from light-duty gasoline vehicles. The primary emissions from
an ethanol vehicle will be ethanol and acetaldehyde, a two-carbon
aldehyde. Due to a lack of emissions data, ethanol vehicles have been
assumed to have potentials for reducing ozone similar to optimized
methanol vehicles.
TABLE 2
. Projected In-Use. Gasoline-Equivalent VOC Emission Factors fg/mile)
Emission Percent
Vehicle Factor Reduction
Conventional Gasoline 0.951 —
Dual-Fuel CNG* 0.498-0.613 35-48
Dedicated CNG* 0.068-0.195 80-93
Electric Vehicle 0.0 100
Flexible Fuel Ethanol** 0.529 44
Dedicated Ethanol 0.192 80
Flexible Fuel LPG*** 0.498-0.613 48-35
Dedicated LPG*** 0.068-0.195 80-93
Flexible Fuel Methanol 0.529 44
Dedicated Methanol 0.192 80
*Range represents best and worst case (see discussion in Appendix 7).
**Assumed similar to methanol.
***Assumed similar to CNG.
1 8
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Formaldehyde is also emitted from most of the alternative fuel
vehicles, but at about the same levels as from a gasoline vehicle. LPG
vehicles will have no formaldehyde emissions. Methanol vehicles are the
one exception, with methanol and formaldehyde emissions higher than
those of gasoline vehicles.
As stated previously, CO and NOx are the other regulated emissions
primarily associated with light duty vehicles. Limited testing on CNG
vehicles indicates significant CO reductions are possible; however, not
enough data is available on the impacts of alternative fuels on CO and NOx
to confidently quantify these emissions relative to gasoline. Emissions of
CO and NOx from alternative fuel vehicles are expected to be controlled via
engine and catalyst technology. Due to a lack of knowledge about and
development on the specific type of control technologies to be used, it is
difficult to clearly predict CO and NOx emission impacts. Electricity is the
one alternative fuel which will result in no CO or NOx (or any other) vehicle
emissions.
b. Air Toxics Emissions
Alternative fuels, by changing the chemistry of emissions, can also
change the potential for health effects. Since more is known about cancer
risks as compared to non-cancer risks, almost the entirety of the discussion
concerns cancer risks. However, non-cancer effects are also of interest.
For non-cancer health effects, there are two major exposure scenarios:
ambient air and microenvironments. In the ambient air, the key issue is
chronic low-level effects; in microenvironments, such as personal garages,
the major issue is brief peak-exposures that have the potential for acute
and chronic noncancer effects. For conventional gasoline, the major non-
cancer health risks of interest are for the criteria pollutants (i.e. ozone,
nitrogen dioxide, and carbon monoxide) in the ambient air and air toxics
(e.g., formaldehyde) in microenvironments. Generally, the change of
interest in non-cancer health effects of air toxics emissions is within
microenvironments. Compared to gasoline, microenvironmental exposures
to formaldehyde and methanol could increase with methanol fuels;
acetaldehyde and ethanol levels could increase with ethanol fuels; and all
air toxics will likely decrease with electricity. Whether or not these
changes would impact health risks cannot be stated with certainty due to
major gaps in both the health effects and exposure data bases.
However, many of the air toxics of interest can cause non-cancer
health effects. As examples, formaldehyde can cause pulmonary function
effects and lung irritation, raising concerns that people with pre-existing
19
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lung disease such as asthma may be at risk; acetaldehyde is also a lung
irritant. Methanol at high concentrations has exhibited developmental
effects on rats and mice, effects on the nervous system, and other s- tems;
such effects of inhaled ethanol, gasoline and other fuels are virtually
unknown. Knowing that these pollutants have the potential of c asing
effects is quite different from knowing whether they are likely cause
effects under actual exposure scenarios. Given the potential r-.;ge of
effects, it is necessary to achieve sufficient understanding to deve op risk
assessments for both conventional and alternative fuels. This leed is
recognized in both the AMFA and the Clean Air Act Amendments. EPA is
conducting research on these issues and is seeking to stimulate private
sector research as well, through ORD's development of the Alternative
Fuels Research Strategy, currently in draft.
EPA has estimated that 1500-3000 cancer incidences occur in the
U.S. annually due to air toxics; motor vehicle emissions account for about
58 percent of these.[ll] Motor vehicle emissions contribute toxic
pollutants directly and indirectly (indirect emissions are photochemical
reaction products of direct emissions and other atmospheric compounds).
Some directly emitted toxic compounds are uncombusted fuel components
while others are incomplete combustion products. As for VOC emissions,
toxics emissions can occur as evaporative or exhaust emissions; the
evaporative emissions can be further broken down into hot soak/diurnal,
running loss, and refueling emissions.
EPA has currently identified several air toxics as having serious
health risks and being due, in large part, to emissions from gasoline-fueled
vehicles. Most of the cancer incidence attributed to gasoline-fueled vehicle
emissions is due to five air toxics (single compounds or groups of
compounds): benzene, 1,3-butadiene, formaldehyde, gasoline vapors, and
polycyclic organic matter (POM). The California Air Resources Board has
identified five "high-risk" substances as accounting for 98 percent of that
state's motor vehicle-related cancer incidence. These are, in order of
decreasing risk, benzene, 1,3-butadiene, diesel particulate, formaldehyde
and acetaldehyde. The primary difference between the EPA and CARB lists
is that EPA considered individual as well as groups of compounds while the
CARB considered single compounds. The EPA methodology will be followed
in the analysis presented here.
It is important to note that EPA estimates of cancer incidence are
based on exposure to the various compounds listed, not to the mixture
resulting from the combustion of gasoline. Because gasoline is a complex
mixture, and its combustion products even more so, it is difficult to
20
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estimate cancer incidences from the use of gasoline. In addition, current
estimates of cancer risk do not include consideration of atmospheric
chemistry. Transport and transformation are significant considerations
when extrapolating from emissions to exposure. For example, the toxic
compound 1,3-butadiene reacts much more rapidly than benzene in the
urban environment; therefore, equivalent dispersion exposure models
cannot be used for these two compounds. Also, preliminary irradiation
chamber data suggest that atmospheric transformation of innocuous
organic compounds can produce chemical mutagens. Research into the
correlation between exposure to air toxics and incidences of cancer is
continuing.
In the discussion of regulated emissions, it was shown that the use of
alternative fuels can result in a reduced total mass of emissions and/or in
emissions of less photochemically reactive compounds. Both of these
results can reduce motor vehicle contributions to air toxics. Reducing mass
emissions results in reductions of air toxics and their effects simply
because there are less of them. Similarly, compounds which are less
reactive with regard to ozone formation are likely to form fewer indirect
air toxics (depending, of course, on the specific atmospheric chemistry
involved). The number of cancer incidence due to air toxics can be
expected to decrease as well. In Table 3, projected cancer incidence of the
alternative fuels relative to gasoline are shown for the fuels considered
here; for a complete discussion of the origin of these numbers see
Appendix 7.
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TABLE 3
Projected Cancer Incidence
Vehicular Emissions Relative to Gasoline Vehicles
Vehicle
Cancer
Incidence
Conventional Gasoline
100
Dual-Fuel CNG*
Dedicated CNG*
30-48
11-30
Electric Vehicle
0
Flexible Fuel Ethanol**
Dedicated Ethanol
50
15
Flexible Fuel LPG***
Dedicated LPG***
30-48
11-30
Flexible Fuel Methanol
Dedicated Methanol
50
11
* Range represents best and worst case (see Appendix 7).
** Assumed similar to methanol.
***Assumed similar to CNG.
2. Stationary Source Emissions
The displacement of gasoline by some form of alternative fuel will
also affect stationary source emissions. This analysis attempted to
quantify these emissions and compare them to those due to gasoline
refining. The emissions estimates for all of these sources are based upon
current regulations and technology. This analysis is preliminary,
however, due to the limited data available on alternative fuel production
processes and the wide variation between states and localities regarding
legal requirements for emission control technology for stationary sources.
More data is needed before the stationary source impacts associated with
alternative fuel production can be accurately determined. The
improvement of this assessment will be a primary focus of later versions
of this report, particularly the existence of unavoidable or economically
prohibitive impacts. For example, although it is addressed briefly in this
section, the mitigation of the release of C02 from coal (and other
feedstock) conversion facilities is of great concern, and the costs of
mitigation techniques must be analyzed carefully in future reports.
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3. Conclusion
The use of clean alternative fuels will substantially reduce the ozone-
forming potential of motor vehicle emissions relative to the use of gasoline.
The type of reduction depends on the fuel used, but can include mass
emission reductions and emission of compounds which are less
photochemically reactive. Reductions in ozone-forming VOC emissions of
about 80 percent are expected with the use of neat alternative fuels in
optimized vehicles, and reductions of about 40 percent are expected with
the use of optimized flexible-fuel and dual-fueled optimized vehicles.
The use of clean alternative fuels is also expected to reduce the
cancer incidence due to motor vehicle-emitted air toxics. Per vehicle
cancer incidence reductions of about 80 percent for neat fuels used in
optimized vehicles and about 50 percent for near neat-fueled and dual-
fueled optimized vehicles are estimated. Only sparse emissions data is
currently available on dedicated and flexible-fuel alternative fuel
vehicles, which limits further comparison of the air toxics benefits of
alternative fuels relative to gasoline. Additionally, the carcinogenicity and
other health effects of the prominent air toxics are still debated. While
cancer incidence is the primary factor in comparing air toxics effects,
other detrimental health effects can occur as well.
B. Global Warming Impacts
1. Overview
One issue which has come the the forefront in the assessment of
alternative transportation fuels relates to the effect that the use of such
fuels would have on the "greenhouse effect," or global warming. The
combustion of fossil fuels has been identified as one of the major
contributors to the increase in concentrations of atmospheric CO2 since the
beginning of the industrialized era, as well as the build-up of other
greenhouse gases such as CH4 and N2O. In this section, the impact of
various alternative fuels on the amount of CO2 and other trace greenhouse
gases released into the atmosphere is considered. Previous EPA Special
Reports on various alternative fuels do not contain much detail regarding
greenhouse gas emissions. Hence, this section presents EPA's current
analyses as opposed to a summary of previous work.
23
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a. Transportation Perspective
In dealing with this issue it is important to place the U.S.
transportation industry in the proper perspective. Global estimates
indicate that at present over 5 quadrillion grams of carbon are released
into the atmosphere via fossil fuel combustion each year.[13] Estimates of
the effective C02 release due to deforestation are on the order of 1
quadrillion grams of carbon per year. For comparison, the U.S.
transportation industry currently consumes about 125 billion gallons of
fuel each year, which results in the ultimate emissions of about 0.4
quadrillion grams of carbon each year, or about 7 percent of global
anthropogenic C02 emissions.! 14]
The U.S. transportation industry also contributes to greenhouse gas
emissions through the release of trace greenhouse gases such as methane
(CH4), nitrous oxide (N2O), and chlorofluorocarbons (CFC-12), contributing
0.1, 0.7, and 11.0 percent to global emissions of these pollutants,
respectively. Automobiles also contribute to net emissions of greenhouse
gases through emissions of hydrocarbons (HC) and oxides of nitrogen
(NOx) which produce tropospheric ozone (another greenhouse gas) and
through emissions of carbon monoxide (CO), which slows the natural
removal of methane from the atmosphere. Excluding tropospheric ozone
effects, the U.S. transportation industry currently accounts for roughly 30
percent of national greenhouse gas emissions, and roughly 5 percent of
global greenhouse gas emissions.
While the U.S. transportation industry accounts for only a small
fraction of global greenhouse gas emissions, its contribution cannot be
ignored. The industry is one of the single largest individual contributors
to greenhouse gas emissions, and thus the effects of any change in U.S.
transportation fuels or policy should be evaluated carefully. Switching a
portion of the U.S. fleet from import-based gasoline to an alternative fuel
could result in either a greenhouse gas emission reduction or detriment,
depending on vehicle technology and the type and source of the energy
feedstock used to produce the fuel. A more detailed discussion of the
greenhouse gas emission impacts of the various fuel/feedstock
combinations evaluated in this report is presented below.
b. Relative Global Warming Potentials of Greenhouse Gases
The relative global warming contribution of emissions of various
greenhouse gases is dependant on their radiative forcing, atmospheric
lifetime, and other considerations. For instance, on a mass basis, the
24
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radiative forcing of CH4 is much higher than that of C02; however,
methane's effective atmospheric residence time is much lower than that of
carbon dioxide. Other gases, such as CFCs, have both long residence times
and high radiative forcings. The relative global warming impacts of
various greenhouse gases, with consideration given to atmospheric
lifetimes and indirect warming effects, were used to determine "C02
equivalent" emissions for each of the alternative fuel scenarios evaluated
in this report. The preliminary global warming potentials presented by
the Intergovernmental Panel on Climate Change (IPCC) were used in this
analysis, and are shown in Table 4. [34] As indicated in the table, the IPCC
has calculated different global warming potentials for different time
horizons, 20 to 500 years, which reflecting the "short term" and "long
term" global warming effects of these gases. As can be seen, even though
the magnitude of vehicular emissions of CH4, N20, and CO are significantly
lower than emissions of C02, their importance with respect to global
warming is not insignificant.
Table 4
Relative Global Warming Potential Factors (IPCC)
(per unit mass
of emission)
Time
Horizon
Greenhouse
Gas
500 vr
20 Yr
CO2
1
1
CO
2
7
CH4
9
63
N2O
190
270
CFC-12
4500
7100
2. Greenhouse Gas Emissions from Transportation Fuel Use
In this section, the CO2 and trace greenhouse gas production
resulting from the use of gasoline and alternative transportation fuels are
examined. Emissions occurring at all points in the fuel use chain, from
resource extraction, fuel processing, fuel distribution, and vehicular
25
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combustion -are determined.8 Potential reductions in emissions of
greenhouse gases which could occur through the use of a specific
feedstock (e.g., reductions in CH4 emissions by using municipal waste
instead of landfilling) are included in the analysis. An overview of the
analysis results is presented in Figure 8, and in the text below. The range
presented represents both long term and short term effects, based on the
GWPs presented above.
a. Gasoline Vehicles
As can be seen from Figure 8, a gasoline fueled vehicle certifying to
a CAFE standard of 27.5 MPG (with a corresponding in-use fuel economy of
23.1 MPG) produces between 570 and 720 grams of C02-equivalent
emissions per mile travelled, depending on the location of the crude oil
source (domestic or foreign) and the trace gas global warming potential
factors assumed. The vast majority of these emissions occur at the vehicle;
the rest are released at various points in the fuel supply chain, primarily
during refining. One important variable in the gasoline analysis is the
efficiency assumed for refining.
Gasoline displaced by the use of alternative fuels would likely have
been imported. The most likely point of introduction for alternative fuels
is in coastal high-ozone cities, where the environmental reductions of
alternative fuels can be fully utilized, and where the high population of
vehicles make the economics of alternative fuel distribution most
favorable. Much of the gasoline currently supplied to these areas, and an
increasing amount in the future, originates in foreign countries. As
alternative fuel use displaces gasoline, shipments of imported oil will likely
diminish. Thus, for the global warming analysis, it was assumed that all
gasoline displaced from the U.S. transportation market would be import
based. This is reflected in the comparisons made in Figure 8. The use of
reformulated gasoline may change the greenhouse gas emissions associated
with gasoline somewhat. Reformulated gasoline will be added to the
analysis when composition and emissions data become available.
b. CNG Vehicles
CNG vehicles can offer greenhouse gas emission reductions or
increases relative to gasoline vehicles depending on the origin of the
8 Emissions from the manufacture and assembly of vehicles should also be considered
for completeness. Differences in manufacturing emissions between vehicle types
appear to be small, however, and have not been evaluated in this report.
26
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FIGURE 8: Greenhouse Gas C02 Equivalent
Range: Lower to Upper limit of Emissions Possible
mmmm
I.^IIMI'IIIIM '|"IM
&;:V, __J_.
Fuel Source / Type
Crude/Gasoline
Domestic Gas/CNG
Domestic Gas/Methanol*
DomesUc Gas/Elcclric
Remote Gas/CNG
Remote Gas/Methanol*
CoaJ/CNG**
Coal/Methanol**
Coal/Electric**
Biomass/CNG
Biomass/Methanol*
Biomass/Ethanol*
Biomass/Electric
MSW/CNG
MSW/Methanol*
MSW/Hlectric
LPG/LPC.
600 800
CQ2 Equivalent (g/nn)
O Up|)cr Limit Lower Limit
* Alcohol flexible fuel vehicles assumed to use 85% alcohol/15% gasoline blend.
** Docs not include C02 recovery options, which could reduce GMG emissions significantly.
1400
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natural gas and the type of CNG vehicle technology used. Dedicated CNG
vehicles exhibit greenhouse gas emission reductions relative to dual-fueled
CNG vehicles due to their higher engine efficiency, as shown in Figure 8.
When fueled with CNG derived from domestic natural gas, both dedicated
and dual-fueled CNG vehicles offer greenhouse gas reductions ranging from
16 to 39 percent relative to import-based gasoline vehicles. Use of remote
natural gas would detract from the greenhouse gas emission reductions of
CNG use, due to the additional energy required to liquefy and transport
foreign natural gas resources to the U.S. Under such a scenario, CNG would
offer reductions of 1 to 25 percent over gasoline use. The use of CNG
produced from biomass or municipal solid waste, due to the renewable
nature of the feedstock, or from gas which is currently vented and flared,
would offer significant advantages relative to gasoline. Using the
production technologies described previously, CNG derived from biomass
can offer emission reductions of 66 percent for DFVs and 73 percent for
dedicated vehicles. The greenhouse gas emission reductions associated
with municipal waste-based CNG are similar, at 70 and 76 percent
reductions for dual fuel and dedicated vehicles, respectively.9 CNG
vehicles operating on coal-based synthetic natural gas could produce
nearly twice the emissions of greenhouse gases as their gasoline
counterparts, absent technologies to recover C02, described later in this
section.
In summary, the use of CNG as a vehicle fuel could result in any of a
number of greenhouse gas emissions, depending on the location and type
of- energy resource used to produce the gas. The renewable feedstocks
offer the greatest reductions, while "produced" natural gas would also
provide some improvement over gasoline. Of course, the overall
reductions in greenhouse gas emissions that could be realized through the
use of CNG produced from some of these feedstocks depends on the
availability of the feedstock for CNG production. The issues of feedstock
availability are addressed in Appendix 4.
c. Electric Vehicles
In addition to offering excellent emission characteristics, electric
vehicles could also provide significant greenhouse gas emission reductions
relative to gasoline vehicles. Actual greenhouse gas emission reductions
will depend on both the vehicle design and the means of electricity
9The benefits of biomass and municipal wastes as fuel feedstocks could approach 100
percent if production processes were redesigned to maximize C02 emission reductions
(i.e. use renewable fuels to provide process energy).
28
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production employed, however. The sources of electricity for electric
vehicles evaluated include conventional fossil fuels (coal and natural gas),
solar energy, biomass, and municipal waste. As shown in Figure 8, if
electricity from coal or natural gas is used, the greenhouse gas emissions
from electric utilities are less than those due to gasoline production,
resulting in C02-equivalent emissions 0 and 41 percent lower than import
based gasoline, respectively. If any of the other feedstocks is used for
electricity production, substantially greater greenhouse gas emission
reductions would occur. The lower limit values for EVs shown in Figure 8
are based on a vehicle providing a driving range of 70 to 90 miles before
recharging. If a vehicle range similar to that of a gasoline vehicle were
required, the added weight of the necessary batteries would reduce the
performance and efficiency, and consequently increase C02 emissions, of
the vehicle dramatically, as illustrated by the upper limit values.10
d. Ethanol Vehicles
The CO2 emissions due to ethanol production and use have been
estimated, and are compared to the C02 emissions due to the production
and use of imported gasoline. In each step of the cycle, all significant CO2
emissions that come from non-renewable energy, and therefore contribute
net positive amounts of CO2 to the atmosphere, have been quantified. Both
corn and biomass have been considered as ethanol feedstocks. The large
range for ethanol vehicles shown in Figure 8 represents both corn-based,
which require a significant amount of energy in production, and the
biomass feedstocks, which are projected to require less energy to convert
into ethanol. The overall potential for reductions in greenhouse gas
emissions are obviously a function of feedstock availability (corn or
biomass) for ethanol production. A discussion of feedstock availability
may be found in Appendix 4.
CO2 emissions due to the combustion of ethanol from corn in motor
vehicles are not considered a net positive contribution of CO2 to the
atmosphere because they are assimilated by the next corn crop. However,
greenhouse gas emissions due to other processes associated with the
production of ethanol fuel, such as corn farming, fertilizer manufacture and
ethanol and byproduct production, do contribute net positive amounts of
10 It is doubtful that a 3S0 mile range could be achieved at all with Lead-Acid or
Nickel-Iron battery technologies. It is possible that Sodium-Sulfur battery
technology could be used to achieve a driving range commensurate with gasoline
vehicles, albeit at the loss in efficiency and increase in greenhouse gas emissions
described above.
29
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greenhouse gases to the atmosphere because these processes are primarily
fueled by non-renewable fossil fuels. Use in a dedicated vehicle running
on corn-based ethanol could result in reduced emissions of 11 percent,
based on current processing technology. (Future plants are likely to
perform much better.) The use of biomass-based ethanol in a dedicated
vehicle could result in reductions of as much as 68 percent.11
Clearly a number of uncertainties exist in the quantity of C02
emissions from various stages of ethanol manufacture. Determination of
energy requirements and allocation of byproduct credits could result in a
net increase or decrease in C02 emissions from ethanol fuels. However,
future plants and expansions are likely to be more energy efficient. This,
along with increasing yields, could reduce CO2 emissions due to ethanol
fuels.
e. LPG Vehicles
As shown in Figure 8, LPG vehicles offer moderate greenhouse gas
reductions of 14 to 26 percent relative to imported gasoline. Our analysis
assumes only domestic LPG resources. Because the vast majority of these
emissions are due to the vehicle, the reductions achieved are highly
dependent on vehicle efficiency, as discussed previously. A LPG vehicle
efficiency of -5 percent relative to gasoline vehicles was assumed in this
analysis.[16] Improvements in LPG vehicle efficiency would yield
additional greenhouse gas emission reductions.
f. Methanol Vehicles
As with CNG vehicles, the use of methanol as a vehicle fuel can offer
greenhouse gas emission reductions or increases relative to gasoline
vehicles, depending on the feedstock used to produce the fuel methanol
and the type of methanol vehicle used (FFV or dedicated). It is assumed
that FFVs are fueled with M85, with domestic crude supplying the 15
percent gasoline, while dedicated vehicles would use M100. As shown in
Figure 8, dedicated methanol vehicles exhibit greenhouse gas emission
reductions relative to flexible fueled methanol vehicles due to their higher
engine efficiency.
1 ^The benefits of biomass and municipal wastes as fuel feedstocks could approach 100
percent if production processes were redesigned to maximize C02 emission reductions
(i.e. use renewable fuels to provide process energy).
30
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When fueled with methanol derived from domestic natural gas,
methanol vehicles would offer greenhouse gas reductions of 9 to 25
percent relative to import-based gasoline vehicles. (Unfortunately, due to
the favorable economics of foreign gas and limitations of domestic
conventional supply, it is more likely that any significant increase in
methanol demand would be supplied by methanol produced from foreign
natural gas.) If foreign natural gas were used in fuel methanol production,
the greenhouse gas reductions would be 8 to 24 percent over those of
gasoline vehicles (these reductions are not quite as great as those from
domestic gas, due to the increased product transportation required). The
use of methanol produced from biomass or solid waste, or from gas which
is currently vented and flared, would offer significant advantages relative
to gasoline, due to the renewable nature of the feedstock. Clearly this
advantage will only be realized if sufficient feedstock is available to meet
demand for methanol; a discussion of feedstock availability is presented in
Appendix 4. Methanol vehicles operating on coal-based methanol would
produce over twice the greenhouse gases emissions of comparable gasoline
vehicles, although technologies to mitigate these potential greenhouse gas
increases exist, as will be discussed below.
C Options for Mitigating Greenhouse Gas Increases Resulting from
Alternative Fuel Production and Use
The Conference Report to S.1518, the Alternative Motor Fuels Act of
1988, directs EPA to discuss carbon dioxide impacts of alternative fuel use
and propose ways to offset any increases in C02 emissions that may result
from their use. [17] As Figure 8 shows, several of the alternative vehicular
fuel/feedstock combinations evaluated in this report could potentially
result in increased greenhouse gas emissions relative to gasoline. This is
particularly true of coal-based fuels, where per-mile emissions of C02
approach twice those of a conventional gasoline vehicle, due to coal's high
carbon-to-energy ratio.
Much of the emissions from coal-based alternative fuels originate at
the fuel production facility, where C02 is formed during the process of
increasing the hydrogen content of the syngas. Technologies exist for
removing and capturing CO2 formed during combustion in most fossil fuel
applications, but are typically cost and energy intensive due to the low CO2
concentrations found in many stack gases. However, in coal gasification
technologies that produce CNG or methanol, most of the C02 emitted is in
highly concentrated streams. Hence, the economics of CO2 recovery are
more favorable and the environmental benefits of recovery are more
31
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easily justified. Although traditional markets for C02 probably could not
absorb the significant additional quantities recovered from the coal-based
production of alternative fuels in very large quantities, develooing CO2
markets, such as enhanced oil recovery, and several disposal options could
fulfill the need for ways to use recovered C02.[18]
Employing technologies to recover, compress, and pipe CO2 from coal-
based fuel production facilities to a disposal site could bring emissions
from coal-based fuels down to levels below those of conventional gasoline.
Depending on the actual configuration and location of the plant, this CO2
recovery could be achieved at costs ranging from $9 to $11 per ton of C02,
or $0.05 to $0.08 per gallon gasoline equivalent of the fuel product. If
coal-based fuels are used in the transportation sector, CO2 recovery
technologies at this cost could provide attractive alternatives to other
means of C02 reduction (CAFE increases, carbon taxes, etc.).
Control of other global warming gases, such as methane, from
alternative fuel production processes are also worth exploring. Future
analyses should include an assessment of the potential for mitigating the
release of CH4 from coal-based fuels, especially methane emissions
produced from coal mining. Additional research into CO2 control options
should continue to find the most technically feasible and economically
reasonable options available. The ultimate fate of the recovered C02 must
be considered when evaluating any recovery option; if the method of
disposal or use results in only temporary sequestration of the gas, the
environmental benefits will be minimal.
D. Other Environmental Impacts
In addition to the regulated pollutant, health effect and global
warming impacts associated with alternative fuel use, there are a number
of other environmental concerns. These include fuel spill and leak issues,
refueling and fire hazards, and operator safety. Several of the concerns
are specific to the individual fuels, and therefore are only discussed in that
section. Due to the complexity of many of these issues, a great deal of
research is necessary. EPA is engaged in research in many of these areas,
and is currently developing a comprehensive research strategy that will
address many of these issues.
32
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1. Compressed Natural Gas
The most significant concerns associated with CNG vehicle use are in
the areas of refueling, vehicle operation and crashes, and risk of fire. CNG
is stored and used at high pressure (up to 3000 psi), which requires
additional precautions in some areas. As long as normal, properly
functioning equipment is being used, CNG refueling should be generally
less hazardous than refueling with gasoline since there will be no toxic or
flammable vapors escaping from CNG refueling equipment, as there often
is with conventional refueling equipment.! 19] Risks can be minimized by
the design of the refueling equipment. Similarly, proper fuel supply
system and building design can minimize the risks of vapor build-up.
Incorporation of design features such as vents in the vehicle body
and ventilation of garages can mitigate the risks of fuel leakage during
regular vehicle operation. In vehicle collision scenarios, CNG would appear
to pose a level of risk somewhere between diesel fuel and gasoline.
Because of the structural integrity needed by the fuel storage cylinders to
hold compressed natural gas, these cylinders are much more likely than
gasoline or diesel fuel tanks to survive collisions without release of fuel
from the storage tank. Safety devices such as fuel release regulators and
solenoid valves to shut off fuel flow can be used to lessen the severity of
any release of natural gas from a CNG vehicle, and minimize the
significance of collision risks. In the event of a fuel release resulting in a
fire, the resulting problems from a CNG fire are likely to be easier to deal
with than for conventional fuels. Because of its localized nature, natural
gas torch fires can be extinguished by shutting off the fuel source. Severe
explosions are unlikely in any case since CNG cylinders are designed to
handle conditions likely to lead to explosions and will eventually vent off
gas which will burn in a relatively controlled manner rather than
rupturing to produce an explosive release. However, conclusions
concerning CNG vehicle safety are conditional on regulations assuring safe
design and operation.
2. Electricity
One potential environmental impact associated with electric vehicle
use is the disposal of the batteries used. If based on traditional battery
technology, EV batteries would contain acids considered to be hazardous
waste, thus being difficult to dispose of safely. As a solid waste, these
batteries could take up a large amount of valuable landfill space, and
possibly make landfill management more difficult. Additional measures
may be necessary to control acid seepage into ground water reservoirs. It
33
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may, however, be possible to recycle EV batteries, reducing or even
eliminating these disposal problems.
There are expected to be no significant health or safety risks
associated with the widespread use of electric vehicles. The flammability
and inhalation concerns associated with the other fuels do not apply for
EVs. The current literature makes no mention of any other increased risks
or concerns to vehicle operators or maintenance workers. An increase in
electric vehicle use would lead to an increase in electricity generation
requirements. This would result in an increase in any environmental
concerns associated with electricity generation. Of course, the extent of
such concerns would depend largely on the specific energy feedstock used
to produce the electric power and the location of the power plant.
Additional analyses of the environmental concerns of increased electricity
generation will be included in subsequent versions of this report.
3. Ethanol
A primary concern associated with ethanol use is the impact of fuel
spills and leaks. Use of ethanol as a motor vehicle fuel would necessarily
involve more transport of neat or near-neat ethanol and, consequently,
more opportunities for accidental spills of a significant quantity. An
ethanol fuel spill into aquatic systems or on land poses environmental and
health concerns because of the fuel's toxic effects in high concentrations. It
is unknown whether catastrophic alcohol fuel spills or leaks would result
in- greater adverse ecological effects that those for conventional fuels. In
some scenarios, including spills in restrictive waterways (rivers and lakes),
serious acutely toxic environmental effects could result from alcohol spills.
In contrast, gasoline spills would expectedly result in generally chronic
effects. (While gasoline would vaporize more rapidly than ethanol, those
components of the fuel that will partially dissolve would exhibit some
acute effects, like the alcohols, although probably to a far lesser
geographical extent, since they will float and be only slightly miscible with
water. Problems of potential bioaccumulation, however, would likely be
greater with gasoline than with ethanol.) Should an ethanol spill
contaminate a water supply, ethanol has a taste and odor that most adults
can recognize and thus would be likely to avoid. The effects of other fuels
spilled into restricted waters are uncertain.
Slower leaks and continuous releases of small quantities of ethanol
are also of interest. Because of the biodegradability of ethanol, smaller
routine releases in circumstances that allow for good dilution should not
present an environmental problem. For example, transfer losses between
34
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ship and shore or flushing of cargo tanks would at most encourage a higher
local concentration of ethanol-digesting bacteria. Leaks into underground
water are a potentially greater concern with all fuels because of the more
restricted dilution conditions that can exist. However, industry practices in
underground fuel storage are changing drastically in response to recent
legislation, and measures such as requiring the use of double walled
storage tanks would significantly reducing the risk of this type of leak.
The massive production of ethanol from corn that could be
experienced under a large alternative fuels program poses other potential
environmental problems in addition to the risk of spills or leaks. Some of
these potential problems include soil erosion and surface water quality
degradation due to pesticides, fertilizers, and situation of habitat. These
potential effects need further research before their impact can be
quantified.
4. Liquefied Petroleum Gas
LPG must be stored under moderately high pressure (up to 200 psi)
in order for it to remain in the liquid phase. Immediately upon being
released from the pressurized tank, LPG evaporates.[20] Therefore, for the
purposes of this discussion, LPG is treated as a gaseous fuel. The risks
related to the release of LPG would likely be similar to those discussed for
CNG. Any release outdoors will dissipate quickly, unless an ignition source
is immediately present, in which case the LPG could explode. Control
measures to avoid this risk, both indoors and out, are discussed in detail in
the appendix. The LPG refueling concerns and possible solutions are
similar to those for CNG.
5. Methanol
Most of the preceding discussion for ethanol applies equally to
methanol. As discussed in the ethanol section, the effect of a spill in
restricted waterways on the ecosystems is uncertain and requires further
research. Cleanup of methanol spills requires less extensive efforts and
costs than cleanups associated with spills of water-insoluble petroleum
fuels. Methanol's toxic effects after a spill onto land are of shorter
duration than those exhibited by a petroleum fuel spill. Methanol and
ethanol would behave very similarly to each other in an underground spill,
particularly in comparison to their sharp differences from petroleum fuels.
Once again, the use of double-walled tanks could reduce this risk
significantly. Methanol, however, is toxic at concentrations that are of no
35
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concern for ethanol and methanol is not detectable by taste or odor. Dyes
or odorants may be needed for methanol that can be omitted with ethanol.
E Conclusions
As this section has shown, the use of alternative fuels could result in
significant air quality, health and global warming benefits. Many of the
environmental impacts of alternative fuels are currently unclear, and
warrant continued research. Actual benefits depend largely on the
fuel/feedstock combination used, but most fuels offer at least some
benefit. While this analysis has made a preliminary attempt at
quantifying these benefits, additional research is needed in several areas
before the impacts of alternative fuels can be fully understood. As stated
previously, EPA is planning additional research in several of these areas.
V. Economic Impacts of Alternative Fuel Production and Use
Although many reports have been written about alternative fuel
production technologies, few include detailed estimates of the construction
costs for the production facility, and fewer still provide detailed estimates
of the cost of the alternative fuel produced. This lack of information
makes an analysis of fuel production costs difficult, particularly due to the
fact that for many of the technologies discussed no commercial plants
currently exist. In spite of these information gaps, a consistent basis for
evaluating production costs can be developed to allow for equitable price
comparisons between each fuel and each potential feedstock.
For example, many reports have been written about designs for
plants that convert coal to methanol by gasification. These reports were
written over a time period of more than ten years. Each design was
optimized according to the designer's requirements, so one plant may use
20,000 tons per day of coal feed while another may use 26,000, and the
methanol production rates of the two plants may be different due to
differences in the process configuration and conversion efficiency. In
order to compare these processes, they must be scaled to a common rate of
fuel production. Capital and operating costs must be altered to reflect the
capacity changes, and must be escalated to current dollars (1989$ in this
study). A discussion of the economic assumptions used for this analysis is
presented in Appendices 4 and 4-A.
As explained in the Appendix 4-A, the fuel production costs
presented in this report are based on the assumption that a relatively
36
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large and secure alternative fuels program is enacted. Without such a
program, these favorable economics will not be realized. Under scenarios
where, in early years, only flexible-fueled (as opposed to dedicated)
vehicles are required, with no guarantees of alternative fuel availability or
use, investment risks would be higher for both fuel production and
distribution facilities, and hence the production costs could be higher.12
The scenarios evaluated in this report, however, with high alternative fuel
production volumes and a significant number of dedicated alternative-
fueled vehicles in the marketplace, would likely realize the favorable
production economics summarized below.13
The cost of supplying alternative fuels is also dependant on the
degree to which the alternative fuel use is geographically focused. As
discussed in Section III, for a geographically unfocused program, in which
alternative fuels are introduced as a means to displace gasoline
consumption only, without targeting use in certain metropolitan areas, the
distribution and service station markup costs would be higher than those
in a geographically focused one. In contrast, in a scenario which limits the
introduction of alternative fuels geographically, the distribution system
cost will be lower and service station markup will be minimized.
A. Compressed Natural Gas Prices
Compressed natural gas (CNG) can be produced from natural
reservoirs or by various feedstock conversion processes. CNG can be used
in either dual-fueled vehicles (DFV), capable of operating on either
gasoline or CNG and incorporating fuel systems for both fuels, or in
dedicated vehicles, optimized to take full advantage of the attributes of
CNG. Due to CNG's poorer volumetric efficiency and the added weight of
CNG tanks (which must be capable of storing CNG at pressures in excess of
3000 psi, and are therefore much heavier than conventional fuel tanks),
dual-fueled CNG vehicles have exhibited performance characteristics
(power, efficiency) slightly poorer than those of gasoline vehicles. A
dedicated CNG system, however, could take full advantage of the attractive
12 However, under such a program, there may be added incentive to price the
alternative fuel competitively. This would encourage the use of the alternative fuels
and would help to reduce the production costs for the fuels.
13 In the transition period at the start of an alternative fuels program, production
and distribution costs would probably be higher than those estimated in this report.
However, this period of higher costs would likely be short lived; as the number of
alternative-fueled vehicles in service and the volume of alternative fuel sales
increase, production and distribution costs on the order of those estimated here would
be realized.
37
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characteristics of natural gas, and could be optimized for performance, fuel
economy, and emissions. A 10 percent energy efficiency loss and a 10
percent efficiency benefit (relative to gasoline) were assumed for dual-fuel
and dedicated CNG vehicles, respectively, in this analysis.
The cost of a production CNG vehicle will vary, depending on the type
of vehicle, natural gas storage pressure, and the type of storage tanks used.
In mass production, incremental costs (relative to gasoline vehicles) are
estimated to be $1,600 for dual-fuel vehicles and $900 for dedicated CNG
vehicles.[9] CNG vehicle operation and maintenance costs will likely be
similar to those of gasoline.
The projected gasoline equivalent pump prices for CNG in the years
2000 and 2010 are shown in Tables 5 and 6, respectively. Service station
markup includes the costs of all necessary refueling equipment and the
energy needed to run CNG compressors. Taxes are assumed to be applied
at the same rate as gasoline taxes, on an energy equivalent basis.14
As indicated by the tables, CNG could be produced from domestic
natural gas at a price of $1.33 per gallon (gasoline equivalent) for a dual-
fueled vehicle (DFV) and $1.09 per gallon for a dedicated vehicle in the
year 2000 (or from foreign or vented and flared natural gas for slightly
more).15 As discussed in Appendix 4, however, domestic natural gas
reserves have limited availability. CNG produced from Alaskan natural gas
or MSW would be somewhat more expensive, although discussion of any
fuel made from MSW should be caveated by the fact that this feedstock
has little potential for large volume fuel production due to its limited
availability and highly heterogeneous nature. By 2010, increases in
domestic gas price should make foreign gas resources more competitive in
the U.S. market. CNG produced from foreign gas could be priced as low as
$1.15 per gallon gasoline equivalent for dedicated vehicles. CNG produced
from coal or biomass are not competitive with CNG from other feedstocks
but could have limited regional applications (the cost for CNG from coal
could be somewhat lower than projected if technologies are optimized for
the use of bituminous coals).
14The recent Highway Fuel Tax increases which resulted from the budget deficit
reduction actions of 1990 are not included in these estimates.
15Not including the increased costs for CNG vehicles.
38
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Tabic 5
CNG Pump Price Comparisons
(Year 2000)
(Projected Gasoline Pnccs, $/gallon)
Source of Feedstock
Natural Gas
Coal
Biomass1
MSW2
Domestic
Imported
V/F 3
Alaskan
Production Cost ($/MMBtu)
8 45
5.14
4.50
3 14
3 75
3 70
4 37
Distribution Costs4
2.1 1
2.11
2.11
2.11
2.1 1
2. 1 1
2.1 1
Serv. Station Price
10.56
7.25
6.61
5 25
5 86
5.81
6 48
Gasoline Equivalent Cost
1 36
0.94
0.86
0 68
0 75
0 75
0 84
Service Station Markup & Expenses5
0 28
0.28
0 28
0 28
0 28
0 28
0 28
Taxes6
0 24
0 24
0.24
0.24
0 24
0.24
0 24
Total Pump Price
({/gallon gasoline eqv)
1.88
1 46
1 38
1 21
1 27
1 27
1 36
Vehicle Efficiency Facior
(DFV/dedicated)7
1 11/01...
Efficiency Corrected
Price ($/gallon gasoline equivalent)
2 09/1.71
1 62/1.32
1 53/1 26
1 33/1 09
1 41/1 16
1 41/1 16
1 51/1 2
'Based on production of biogas, an inefficient process that makes large scale production unlikely
2 Based on cost of producing landfill gas Costs for CNG produced via gasification could be lower, the economics of this
technology are undetermined
^V/F=vcnlcd and flared
4A geographically disperse program would require an additional SO 05/MMBtu (SO 01/gallon gasoline equivalent)
5For a geographically disperse program, this numba would increase SO 056/gallon gasoline equivalent
6TIiis does iidI include llie highway fuel tax increases resulting from the budget defieil reductions of I *>'X)
' OrV-Du.il fueled vehicle, dedicated^velucle operating only on CNG
-------
Table 6
CNG Pump Price Comparisons
(Year 2010)
(Projected Gasoline Prices, $/gallon)
Source of Feedstock
Natural Gas
Coal
Biomass1
MSW2
Domestic
Imported
V/F3
Alaskan
Production Cost
((/Million Btu)
8.69
5 29
4.50
5 47
4.38
3 70
4.81
Distribution Costs4
2.08
2.08
2.08
2.08
2.08
2.08
2.08
Serv. Station Price
10.77
7.37
6.58
7.55
6.496
5.78
6.89
Gasoline Equivalent Cost
1 39
0.95
0.86
0.97
0 83
0 75
0 89
Service Station Markup3
0.28
0.28
0.28
0.28
0 28
0 28
0.28
Taxes6
0.24
0.24
0.24
0.24
0.24
0 24
0.24
Total Pump Price
1.91
1.47
1.38
1.49
1.365
1.27
1.41
($/gallon gasoline eqv)
Vehicle Efficiency Factor
(DFV/dedicated)7 1 11/. 91
Efficiency Corrected
Price ($/gallon gasoline equivalent) 2.12/1.74 1 63/1.34 1.53/1.26 1.66/1.36 1.50/1.23 1.40/1.15 1 57/1 28
1 Based on production of biogas, an inefficient process thai makes large scale production unlikely
2 Based on cost of producing landfill gas Costs for CNG produced via gasification could be lower, the economics of this
technology are undetermined
•*V/F=vcnicd and flared
4 A geographically disperse program would require an additional $0 05/MMBlu ($0 0l/gallon gasoline equivalent)
5For a geographically disperse program, tins number would increase SO 056/gallon gasoline equivalent
6TIiis does not include the highway luol lax increases resulting from the budget deficit reductions of IDW
^UhV-1hi.iI fueled vehicle, deilicale'il-vehiclc opcrjling only oil CNG
-------
B. Electricity Prices
Prices for electricity generated using conventional (fossil energy)
feedstocks, municipal waste, and solar energy were estimated in this
analysis. Biomass can also be used for generation of electricity, but
insufficient capital cost estimates were available for this feedstock to be
compared with the others.
When considering electric vehicles (EVs), poor performance, limited
range and high cost have been listed as significant limitations in their
production or wide-spread use. Vehicle energy efficiencies, however, can
be extremely high. Average efficiencies of 0.471 kwh/mi, or
approximately 70 miles per gallon gasoline equivalent, have been
reported, including transmission, battery, and charger efficiency (the "total
energy load").[21]16 Recently developed prototype EVs have demonstrated
even higher energy efficiencies.[22]
Current electric vehicles are extremely costly, however, primarily
due to the cost of the battery. An electric passenger car is expected to
have a net vehicle price increase of $5,490 over the cost of a conventional
vehicle.[23] It has been predicted that, under mass production, EVs could
become cost competitive with conventional vehicles.[24] However, for this
report, the full differential price was assumed for electric vehicles.
Maintenance costs for EVs have been projected to be about 50% of those
for conventional vehicles, or about 3.4tf/mile.[16]
In determining a gasoline equivalent price for electricity, the retail
cost of the electricity, costs for recharging equipment, and road user taxes
must be considered. Since electricity is available throughout the U.S., the
existing electrical distribution system can fuel electric vehicles.[25]
Recharging electric vehicle batteries requires a relatively long time (6-8
hours), hence, it is possible that recharging would occur largely at night,
either in the home or in a fleet's garage.[23] If so, the cost of electricity for
vehicles would be expected to be lower than it would be in the peak
(daytime) hours, although significant daytime recharging would also likely
occur. DOE estimates that the recharging equipment, on the average (for
both household and fleet vehicles) would cost 0.012 cents/kWh when
16The range of these EVs is only 70 to 90 miles between recharging, much less ihan
the range of gasoline vehicles. If a driving range similar to gasoline vehicles ib
desired, the energy efficiency of EVs could be 50 percent lower or more, while
vehicle costs would increase significantly.
41
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amortized over the life of the vehicle.[23] Road user taxes for EVs would
cost an additional 0.706 cents/kWh.
The estimated pump price equivalents for electricity in ;ne years
2000 and 2010 are shown in Tables 7 and 8. Conventional .neans of
generating electricity (coal, natural gas, and other feedstocks currently
used) will produce electricity at the lowest cost in the future. Uimg DOE's
projected electric costs and factoring in the costs of recharging, gasoline
equivalent, efficiency corrected prices of $1.12 per gallon in 2000 and
$1.18 per gallon in 2010 were estimated for electricity produced from
conventional (coal, gas) resources.17 Municipal waste-based electricity
appears to be cost prohibitive when compared to electricity generated by
conventional means, but could be more attractive if higher disposal costs
for the waste are realized in the future. However, the use of electricity
generated from municipal waste tor use as a vehicular fuel would have
only limited regional application because of the highly decentralized
nature of this feedstock. Solar energy is currently price prohibitive and
would likely have only limited application in the near future.
17Not including increased vehicle costs and assuming a range of 70-90 miles between
refuelings. As the footnote indicates, these costs could be significantly higher if the
electric vehicles have a range similar to a conventional gasoline vehicle
42
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Table 7
Electricity Pump Price Comparisons
(Year 2000^
Producers Price (p/kwh)
Feedstock
Conventional Solar
6.70
10.0
MSW**
7 5
Avg. Retail Price 9 50 13.3
Recharger Costs 0.01
Taxes - 0 71
Total Price (c/k\vh) 10 22 14 02
Gasoline Equiv Ratio (kvvh/gal) 36.65
0.4
Total Price (S/gal. gas. equiv.) 3.74
Efficiency Correction Factor*
5.14
0 30 - 0.50
4.10
Efficiency Corrected
Price (S/galIon gas. equiv.)
1.12-1 87
1.54-2.57
.23-2.05
*This lactor includes recharging and vehicle clficicncies The lower lactor
assumes a vehicle range of 70-90 miles between refueling Cosis could be
significantly higher ai driving ranges equivalent to current gasoline vehicles, as
represented by the higher correction factor.
**Estimated assuming icfusc derived fuel used in place of coal Because ol special
considerations for MSW handling and combustion, these costs could be higher
Also, due to its limited availability, MSW may be unable to meet the demand lor
electricity under a large volume alternative lucls program
4 3
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Table 8
Electricity Pump Price Comparisons
(Year 2010)
Feedstock
Conventional Solar MSW -
Producers Price (c/kwh) 7 1 1 10.0 7 9
Avg. Retail Price 9 99 13.3 10.9
Recharger Costs 0.01
Taxes 0.71
Total Price (c/kwh) 10.71 14.02 11 6
Gasoline Equiv Ratio (kwh/gai) 36.65
Total Price ($/gal. gas. equiv.) 3.92 5.14 4.25
Efficiency Correction Factor* 0.30 - 0.50
Efficiency Corrected
Price (S/gal. gas. equiv ) 1.18-1.96 1.54-2.57 128-2 12
"Tins lactor includes recharging and vehicle el liciencies. The lower lactor
assumes a vehicle range of 70-90 miles between refueling. Costs could be
significantly higher ai dnvmg ranges equivalent to current gasoline vehicles, as
represented by the higher correction factor.
""Estimated assuming refuse derived fuel used m place of coal. Because ol special
considerations for MSW handling and combustion, these costs could be higher
Also, due to its limited availability, MSW may be unable to meet the demand lor
electricity under a large volume alternative lucls program.
C Ethanol Pump Prices
Ethanol can be produced from either corn (or other agricultural
products) or cellulosic materials (woody plants). Currently, corn is used as
the feedstock in about 95 percent of operating ethanol plants.[261
Estimates of the cost of ethanol production from corn are not easily made
because of the diversity of the existing corn-to-ethanol industry. However.
44
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by combining data from several studies, estimates of $1.05 to $1.47 per
gallon for the year 2000 and $1.25 to 1.67 per gallon in the year 2010
were calculated.
Most work to date on the production of ethanol from cellulosic
material has been done through the Solar Energy Research Institute
(SERI).[27,28,29] A recent DOE White Paper presented cost projections of
$0.99 per gallon in 2000 and $0.55 per gallon in 2010 for ethanol
produced from lignocellulose feedstocks; under a scenario of more intense
research, ethanol from biomass was projected to cost $0.55 per gallon as
early as 2000.[30] Since these technologies are in the development stage
and have not been proven commercially, it remains to be seen whether
these costs will actually be realized. A complete discussion of conversion
technologies for both corn and cellulosics may be found in Appendix 4.
Ethanol can be used in either flexible-fueled vehicles, operating on
E85 (a mixture of 85 percent ethanol, 15 percent gasoline) or in dedicated
vehicles capable of operating on neat ethanol (E100). Flexible-fueled
vehicles (FFVs) using current technology could gain 5 percent efficiency
over gasoline vehicles due to ethanol's improved combustion properties. A
dedicated vehicle optimized for ethanol combustion could yield an
efficiency benefit of 30 percent over gasoline vehicles, due to fact that a
dedicated vehicle could be optimized to take full advantage of ethanol's
high octane and other advantageous properties. EPA has estimated a cost
of up to $300 extra for an ethanol FFV produced at high volumes, and no
overall cost difference for dedicated ethanol vehicles relative to the
production cost of gasoline vehicles.[12] Vehicle maintenance costs for
both dedicated and flexible fuel ethanol vehicles are expected to be
comparable with those for gasoline vehicles.
Table 9 presents the projected gasoline equivalent, efficiency
corrected pump price for E85 in the years 2000 and 2010. As the table
shows, E85 using ethanol made from corn is expected to cost $2.37 per
gallon gasoline equivalent in 2000, and $2.64 per gallon in the year 2010.
Ethanol from biomass would yield E85 at pump prices of $1.80 per gallon
in 2000 and $1.56 per gallon in 2010, if DOE's projections regarding
technological advancements in the conversion of cellulosics to ethanol are
realized.
45
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Table 9
E85 Pump Price Comparisons
2QQQ
2010
Production Price
($/gallon E85)
Distribution Costs^
Serv. Station Markup^
Taxpg
Corn! Biomass^ Corn1 Biomass^
1.03-1.39 0.98 1.23-1.59 0.81
0.06
0.06-0.08
0.16 -
Total Pump Price ($/gallon)5 1.31-1.69 1.26-1.28 1.51-1.89 1.10-1.12
Gasoline Equivalent Ratio 1.42
Efficiency Correction Factor 0.98
Gasoline Equivalent Price
($/gallon)
2.37
1.80
2.64
1.56
*The prices in 2000 are based on com feedstock costs of $2.50 per bushel, and in 2010
on a cost of $3.00 per bushel, based on the feedstock information presented in
Appendix 4.
2Biomass costs are based on DOE projections as discussed in Appendix 4.
3 Under a geographically dispersed program, distribution costs would be $0.18 per
gallon gasoline equivalent.
4 Under a geographically dispersed program, markup would be an additional
$0.01/gallon.
5Total pump prices do not include the current Federal tax credit of $0.60 per gallon
denatured ethanol used (provided the ethanol was produced from a non-fossil fuel
renewable feedstock).
The projected pump prices for E100 are presented in Table 10. As
shown, El00 made from corn is expected to cost $2.04 per gallon gasoline
equivalent in 2000 and $2.27 per gsdlon gasoline equivalent in 2010. E100
made from biomass could cost $1.49 per gallon in 2000 and $1.22 per
gallon in 2010.
46
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Table 10
El00 Pump Price Comparisons
2000 2010
Corn I Biomass.2 Com 1 Biomass^
Production Price ($/gallon) 1.05-1.47 0.99 1.25-1.67 0.76
Distribution Costs^ 0.06
Serv. Station Markup^ 0.06-0.08
Taxes 0.16
Total Pump Price ($/gallon)5 1.33-1.77 1.27-1.29 1.53-1.97 1.04-1.06
Gasoline Equivalent Ratio 1.5
Efficiency Correction Factor 0.77
Gasoline Equivalent Price
(S/gallon) 2.04 1.49 2.27 1.22
tThe prices in 2000 arc based on corn feedstock costs of $2.50 per bushel, and in 2010
on. a cost of $3.00 per bushel, based on the feedstock information presented in
Appendix 4.
^Biomass costs arc based on DOE projections as discussed in Appendix 4. Under DOE's
intensified R&D scenario, the production price for ethanol from biomass is projected
to be as low as $0.55 per gallon by 2000.[30] The pump price would be $0.98 per gallon
if this cost were realized.
3 Under a geographically dispersed program, distribution costs would be $0.18 per
gallon gasoline equivalent.
4 Under a geographically dispersed program, markup would be an additional
$0.01/gallon.
5 Total pump prices do not include the current Federal tax credit of $0.60 per gallon
denatured ethanol used (provided the ethanol was produced from a non-fossil fuel
renewable feedstock).
47
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D. LPG Pump Prices
Liquefied petroleum gas (LPG) is used currently in some fleet
applications and for forklifts, because the low emissions of LPG engines
enable them to be used indoors. Testing and evaluation of prototype LPG
vehicles performed by EPA indicates that an efficiency adjustment factor
of -5 percent relative to gasoline is reasonable to assume for both flexible-
fueled and dedicated LPG vehicles.[31] Differential costs for production of
LPG vehicles over the cost of a conventional vehicle range from $800 for a
dedicated vehicle to $1,500 for a flexible fuel vehicle.f 16]
Table 11 presents the projected future pump prices of LPG. LPG is
projected to cost $0.87 per gallon (gasoline equivalent) in 2000 and $0.94
per gallon in 2010 based on DOE projections of future LPG wholesale
costs.18 Although these prices are attractive compared to projected future
gasoline costs, propane prices can be quite volatile and are seasonal;
therefore LPG prices could be different than those estimated here
especially under a scenario of increased demand. Limited domestic supply
of LPG makes its widespread use as a vehicular fuel somewhat doubtful;
however, limited use of LPG (fleet vehicles, state programs) could continue
to be attractive in the future. A complete discussion of the availability and
costs of LPG may be found in Appendix 4.
18 Vehicle costs are not included in these numbers.
48
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Table 11
LPG Pump Price Comparisons
(Projected Gasoline Prices, $/gallon)
2000
2010
Refinery Price ($/gallon LPG)*
0.29
0.34
Distribution Costs
0.06
0.06
Service Station Markup
0.07
0.07
Taxes
0.17
0.17
Total Price ($/gallon LPG)
0.59
0.64
Gasoline Equivalent Ratio
-1.39
Total Price ($/gal. gasoline equiv.)
0.82
0.89
Vehicle Efficiency Correction Factor
-1.053
Efficiency Corrected Price ($/gallon)
0.87
0.94
•Based on price projections from EIA/DOE.[2] LPG prices are volatile, responding to
market changes and international events. In August 1989 the price was $0.22/gallon,
by August 1990 it had risen to $0.54/gallon. Due to the Iraqi crisis, the price had
risen to $0.91/gallon by October 1990.
E Methanol Pump Prices
Methanol can be produced from coal, biomass, municipal waste, and
natural gas. The technologies and costs for producing methanol from each
of these feedstocks are addressed Appendix 4.
Methanol can be used in flexible-fueled vehicles operating on M85 (a
mixture with gasoline at a ratio of 85 percent methanol, 15 percent
gasoline) or in dedicated vehicles operating on neat methanol (M100).
Flexible-fueled vehicles would likely achieve a 5 percent efficiency gain
over gasoline vehicles, while a dedicated vehicle optimized for methanol
combustion could yield an efficiency benefit of 30 percent over gasoline
fueled vehicles.! 10] EPA has estimated a cost of up to $300 more for a
flexible-fueled methanol vehicle, and no net cost increase for a dedicated
49
-------
methanol vehicle, relative to the production cost of a gasoline vehicle.! 10]
Maintenance costs for both flexible fuel and dedicated methanol vehicles
are expected to be comparable with those for gasoline or about 6.8 :ents
per mile.[16]
Tables 12 and 13 present the projected methanol pump pru,s for
M85 in the years 2000 and 2010, respectively, for all feejstocks
considered in this report. Distribution costs, service station markup, and
taxes were estimated for methanol by adjusting costs for gasoline as
appropriate when energy content is considered.
As the tables show, for flexible-fueled vehicles, M85 using methanol
produced from foreign natural gas has the lowest efficiency-corrected
pump price, $1.12 per gallon of gasoline equivalent, in 2000. In 2010,
M85 from foreign gas is projected to cost $1.23 per gallon gasoline
equivalent. Methanol from vented and flared natural gas would exhibit
similarly low costs. Obviously, methanol could also be produced from
domestic natural gas; however, costs are unattractive when compared to
foreign locations where lower cost natural gas is available. M85 produced
from the other feedstocks would not be economically competitive.
The future price estimates for M100 are presented in Tables 14 and
15. These tables show that methanol made from foreign natural gas will
be the least costly, with an efficiency adjusted price of $0.88 per gallon
gasoline equivalent in 2000 and $0.95 per gallon in 2010. (Vented and
flared gas is also expected to cost $0.88 per gallon.) Methanol made from
coal would be somewhat more expensive, with a gasoline equivalent pump
price of $1.23 per gallon in 2000 and $1.26 per gallon in 2010; coal-based
methanol coproduced with electricity would be slightly less expensive.
Methanol produced from biomass or municipal waste would be
significantly more expensive than methanol from the other feedstocks
based on current technological designs, but could be less costly if the costs
of these feedstocks decreased.
50
-------
fable 12
Blended Price ($/gallon)5
Distribution Costs6
Serv Station Markup7 -8
Taxes9
M85 Pump Price Compansons, Year 2000
(Projected Gasoline Equivalent $/gallon)
Source of Feedstock
Coal Coal Natural Gas1
(D) 2 (CP)2 Biomass3 MSW1 Foreign Alaskan V/l
0 63 0.58 0.71 0.81 0.44
0 03 0 03
0.06
0 06 0 06 0 06
0 14 0 14 0 14
0 06
0 06
0 14
0 03
0 06
0 14
0 59
0 03
0 44
0 03
0 06 0 06
0 14 0 14
Total Pump Price ($/gallon)
Gasoline Equiv. Ratio
Efficiency Correction Factor
0.86 0.81
0 97
1 07 0 67
.... | .75
----0 952
0.82
0.67
Efficiency Corrected Price ($/gallon) 1 43 1.35 1.61
1.78
1.12
1.36
1.12
' Domestic natural gas is not considered since, due to the lower construction costs, most methanol plant designs aie
planned for locations overseas
2 The notation (D) refers to methanol from a dedicated coal to methanol plant, and (CP) refers to methanol
produced by a mcihanol/elcctricity coproducuon plant.
3 SERI estimates that methanol could be produced from biomass for as little as $0 55 per gallon; the cost of M85 would be
significantly lower if this cost were realized
4 Estimated based on biomass-io-methanol plant. Due to special handling and disposal problems associated with MSW, these
costs could be higher for a plant designed for MSW.
^ Gasoline at $0 92 per gallon
6 For a geographically disperse program, ilns would increase SO 02 per gallon
7 This would increase $0 01 per gallon lor a geographically disperse program
8 0 06=+5% efficiency, markup for +30'/ elliciuit-y would be 0 OS
'' Niii nit lulling the it-n.nl higliw ly ta\ increases
-------
Table 13
M85 Pump Price Comparisons, Year 2010
(Protected Gasoline Equivalent $/pallon)
Source of Feedstock
Coal Coal Natural Gas 1
(DL2. (CP)2 Biomass3 MSW4 Foreign AUskan V/F
Blended Price ($/gallon) 5 0 68 0.67 0.74 0.84 0 51 0.64 0 46
Distribution Costs* 0.03 0 03 0.06 0 06 0 03 0.03 0 03
Serv Station Markup7 0 06 0.06 0.06 0.06 0 06 0 06 0 06
T axes9 0 14 0 14 0 14 0 14 0 14 0 14 0 14
Total Pump Price ($/gallon) 0 91 0.90 1.00 1 10 0.74 0.87 0.69
Gasoline Equiv Ratio --- ---1 7 5
Efficiency Correction Factor 0 952--
Efficiency Corrected Price ($/gallon) 1.52 1.50 1.66 1.83 1.23 1.45 1.16
1 Domestic natural gas is not considered since, due to ihc lower construction costs, most methanol plant designs are
planned for locations overseas.
2 The notation (D) refers to methanol from a dedicated coal to methanol plant, and (CP) refers to methanol
produced by a methanol/electncity coproducuon plant.
3 SERI estimates that methanol could be produced from biomass for as little as $0 55 per gallon; the cost of M85 would be s
lower if this cost were realized.
4 Estimated based on biomass-lo-mcthanol plant Due to special handling and disposal problems associated wiih MSW, these
costs could be higher for a plant designed for MSW.
^ Gasoline at $1.11 per gallon.
* For a geographically disperse program, this would increase $0.02 per gallon
7 This would increase $0 01 per gallon for a geographically disperse program
" 0 06=+5% efficiency, markup for +30% clliciency would be 0 08
9 Not including the rcccni highway lax increases
-------
Table 14
M100 Pump Price Comparisons, Year 2000
(Projected Gasoline Equivalent $/gallon)
Source of
Feedstock
Coal
Coal
Natural
Gas1
(m*
(CP)
Biomass3
MSW4
Foreign
Alaskan
V/F
U.S. Landed Cost ($/gallon)
0.58
0.52
0.67
0.79
0.35
0.53
0 35
Distribution Costs5
0 03
0 03
0 06
0 06
0 03
0 03
0 03
Serv Station Markup6 -7
0 05-
0 07
0 05-
0.07
0 05-
0 07
0 05-
0 07
0 05-
0 07
0 05-
0 07
0 05-
0 07
Taxes8
0 ) 2
0 12
0 12
0 12
0 12
0 12
0 12
Total Pump Price
($/gallon)
0 78-
0 80
0 7 2-
0 74
0.90-
0 92
1 02-
1 04
0 55-
0 57
0 73-
0 7 5
0 55-
0 57
Gasoline Equiv Ratio (dedicated) --- 2 1)0
Efficiency Correction Factor 0 769 —
Efficiency Corrected Price($/gal ) 9 123 1.14 1.41 160 0.88 1.15 0 88
' Domestic natural gas is not considered since, due to ihc lower construction cosls, most methanol plain designs are
planned for locations overseas
2 (D)= a dedicated coal to methanol plain, and (CP) =a mcthanol/clcciricity coproduction plant
3 SER1 that estimates a methanol cost of $0 55 per gallon is possible under an intense research program, the pump
price would then be $1.18 per gallon gasoline equivalent
4 Estimated based on biomass-to-mcihanol plant Due to special handling and disposal problems associated wiih MSW, these
costs could be higher for a plant designed for MSW
5 For a geographically disperse program, this would increase SO 02 per gallon
6 0 05=+5% efficiency, markup lor +30% efficiency would be 0 07
7 'I Ins would increase $0 01 per gallon fur a geographically disperse program
^ Not including the recent highway lax increases
>J Assuming dedicated vehicle (i-'5()% efficiency;
-------
fable 15
MIOO Pump Price Comparisons, Year 2010
(Proiected Gasoline Equivalent $/fiallon)
Source of Feedstock
Coal
Coal
Natural
Gas'
(D) ^
(CP)
Biomass3
MSW4
Foreign
Alaskan
V/F
U.S. Landed Cost ($/gallon)
0.60
0.59
0.67
0.79
0.40
0.56
0.35
Distribution Costs5
0 03
0.03
0.06
0.06
0.03
0.03
0 03
Serv. Station Markup6 -7
0 05-
0 07
0.05-
0.07
0.05-
0.07
0.05-
0 07
0 05-
0 07
0 05-
0 07
0 05
0 07
Taxes8
0 12
0.12
0.12
0 12
0 12
0 12
0 12
Total Pump Price
($/gallon)
0 80-
0.82
0.79-
0 8 1
0.90-
0 92
1.02-
1 04
0.60-
0 62
0.76-
0 78
0.55-
0 57
Gasoline Equiv. Ratio (dedicated) 2 00
Efficiency Correction Factor - -0 769 - -
Efficiency Corrected Price ($/gal.)9 126 1.25 1.41 1.60 0.95 1.20 0.88
1 Domestic natural gas is not considered since, due to the lower construction costs, most methanol plant designs arc
planned for locations overseas.
2 (D)= a dedicated coal to methanol plant, and (CP) =a mcthanol/clectncily coproduction plant
3 SERI that estimates a methanol cost of $0 55 per gallon is possible under an intense research program, the pump
price would then be $1.18 per gallon gasoline equivalent.
4 Estimated based on biomass-to-methanol plant Due to special handling and disposal problems associated with MSW,
these costs could be higher for a plant designed for MSW.
5 For a geographically disperse program, this would increase $0 02 per gallon
6 0 05=+5% efficiency, markup lor +30% efficiency would be 0.07
' This would increase $0 01 per gallon foi a geographically disperse program
" Noi including the receni highway lax increases
9 Assuming dedicated vehicle (+30% ellicienty)
-------
F. Other Economic Impacts
The use of alternative fuels in the transportation sector could
provide several other economic benefits in addition to those described
above. The use of alternative fuels would provide energy supply benefits
to the U.S. by providing an expandable energy source in case of a supply
disruption. Of course, this requires that the supply of the alternative
fuel(s) be capable of expansion in the short run. However, the real benefit
may be that even if only a fraction of the U.S. transportation sector has the
ability to switch fuels, the overally likelihood of supply disruptions may be
reduced. Increasing the U.S. fuel switching capabilities in the
transportation sector would also provide some leverage against oil
suppliers, providing a deterrence against wide swings in the price of oil. A
domestically produced alternative fuel would further enhance our control
over energy supply and price and would help to improve the U.S. trade
balance. If sole domestic supply is not feasible, however, the mere
presence of additional energy suppliers would increase competitive
pressures in the market.
As discussed in Appendices 5 and 6, world oil prices could be
suppressed due to the decreased demand for gasoline resulting from the
use of alternative fuels. Of course, other international issues could
compensate for the decreased demand and lower prices; the U.S. market
does not set world oil prices, but can influence them. Many factors,
including the extent to which other markets (such as utilities and home
heating) might respond to depressed oil prices, make it difficult to predict
the extent to which oil prices might fall. The response of OPEC to
decreased global demand is also uncertain; production quotas could be
limited further in an effort to drive prices back up. However, based on
initial estimates by DOE, displacement of 1 million barrels per day
(MMBPD) of gasoline could result in oil price decreases on the order of
$2.20 per barrel and reduce the national energy import bill by as much as
$10 billion per year.19 [33]
19The displacement of 1 MMBPD of gasoline consumption is one of three alternative
fuel use scenarios evaluated. More detailed discussions of these scenarios may be
found in Appendices 3, 5, 6, and 7.
55
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Q Summary
Tables 16 and 17 summarize the pump prices for all fuel/i jdstock
combinations presented in Sections A-E for the years 2000 and 20 )
The main purpose of the analysis presented in this report not to
determine the single best alternative fuel for use in the United St..:2S. The
uncertainties associated with the analysis for each fuel make it i.fficult to
differentiate between the fuels, and the costs for any specific alternative
fuels could prove to be somewhat different than those estimated here.
Rather, the purpose of the analysis is to provide objective information on
the environmental and economic potential of a number of alternative fuels,
and to offer a basis for comparison with gasoline. Ultimately, the market
will decide which alternative fuel(s) are most likely to displace gasoline. It
is possible that a wide variety will be available, perhaps with regional
variations depending on feedstock costs and availabilities.
As can be seen from Tables 16 and 17, a number of alternative fuels
could compete economically with gasoline in the future. CNG or methanol
produced from imported natural gas are two examples. Fuels derived from
large domestic resources such as coal, or renewable resources such as
biomass, could also be priced at levels at or near that of gasoline. As
technological improvements are made, the price of many of these domestic
alternatives is likely to decrease. If transportation is determined to be an
area in which both environmental and energy supply improvements can
be made, there appear to be a number of options available that would be
both economically and environmentally attractive.
VI. Summary and Conclusions
Petroleum products are the largest energy source used in this
country, and more is used for transportation than for any other purpose.
Since domestic production cannot fill the demand, about 50 percent of the
crude oil used in this country is imported. As the transportation sector
grows and continues to use more petroleum products, the U.S. will become
increasingly dependent on imported oil. This increased consumption of
petroleum could have significant impacts on the environment, as well.
If a reduction in oil imports is desired, the dependance of the
transportation sector on petroleum products will have to be reduced, and
alternate sources of energy will have to be used to produce transportation
fuels. In spite of the availability of a large quantity and variety of
56
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Table 16
Fuel/Feedstock Comparison
Gasoline Equivalent Pump Price, Year 2000 (1989$/gallon)
Gasoline Retail Price = $1.31 per gallon
Feedstock
Municipal Natural Solar
Fuels Coal Biomass Waste Gas 1 LPG Energy
CNG '
1.71-2.09
1.32-1.62
1.26-1.53
1.09-1.51
—
I
Electricity
' 1.12-1.87
—
1.23-2.05
1.12-1.87
--- 1.54-2.57
Ethanol '
—
1.49-2.37
T
—
—
LPG
—
—
—
0.87
1
Methanol
1.14-1.43
1.41-1.61
1.60-1.78
0.88-1.36
— —
Table 17
Fuel/Feedstock Comparison
Gasoline Equivalent Pump Price, Year 2010 (1989$/gallon)
Gasoline Retail Price = $1.51 per gallon
Feedstock
Municipal Natural Solar
Fuels Coal Biomass Waste Gas LPG Energy
CNG '
1.74-2.12
1.34-1.63
1.26-1.53 '
1.15-1.66
Electricity
' 1.18-1.96
—
1.28-2.12
1.18-1.96 --- 1.54-2.57
(
Ethanol
• • •
1.22--2.64
r
•
•
•
•
¦
•
«
•
•
LPG
• • •
0.94
i
Methanol
1.25-1.52
1.41-1.66
1.60-1.83
0.88-1.45
1 Costs presented for CNG vehicles reflect a driving range lower than that of a conventional gasoline vehicle.
If CNG vehicles were designed to achieve an equivalent range, the costs would be commensurately higher.
2 Preliminary estimates based on anaerobic digestion, a highly inefficient process that is unlikely to be used for large scale
production of CNG. Costs could be significantly different if gasification technology were used.
3 Estimate based on landfill gas generation; cost could be significantly different if gasification technology were used.
4 Lower costs are for electric vehicle with driving range of 79-90 miles per charge. If electric vehicles were able to achieve a
range equivalent to conventional gasoline vehicles, the higher cost would likely be realized.
5 Preliminary estimate based on coaMired generation. The conversion of municipal waste would likely require treatment of
byproducts using additional equipment that could affect the cost of generating electricity by this process.
6 Highest number indicates estimate for fuel mixed with gasoline (E85, M85).
7 The low end of the range is based on SERI's cost estimates for ethanol from biomass.
8 Preliminary estimate based on biomass conversion. Due to the potential need for byproduct treatment, the costs for
municipal waste gasification could be significantly different than those estimated here.
-------
domestic energy resources, only a minor movement towards production of
alternative fuels from these feedstocks will take place due to the "chicken
and egg" problem: consumers do not have a sufficiently strong economic
incentive to demand new fuels, fuel producers will not market fuels for
which no vehicles exist, and vice-versa. To attain the maximum
environmental and economic benefits of alternative fuel use, some degree
of market intervention will likely be required.
The study in this report shows that many alternative fuels would
likely result in significant environmental benefits relative to gasoline. All
of the alternative fuels considered are projected to result in lower in-use
vehicular VOC emissions than current gasoline vehicles. Many of the air
toxics emissions associated with gasoline could be reduced, as well. Fuels
derived from renewable feedstocks (biomass, municipal waste) and vented
and flared natural gas are attractive from a greenhouse gas emission
perspective. Coal-based alternative fuels would increase emissions of
carbon dioxide; however, methods to mitigate the release of this C02 exist
and could be applied to make coal-based fuels more attractive, apparently
at a reasonable economic cost. There remain many issues associated with
alternative fuels (e.g., their benefit to society or the contributions of new
production facilities to local air quality) that require further evaluation
before a definitive statement can be made on the environmental benefits
of alternative fuels relative to gasoline. However, the projections made in
this study appear promising.
The analysis shows that several of these alternative fuels could be
produced at costs competitive with gasoline at oil prices as low as $20 per
barrel; many more in the $25-$35 per barrel of oil range. The economics
of any alternative fuels program will be most attractive if the fuels and
vehicles are produced in quantities large enough to achieve sufficient
economies of scale, the program is geographically concentrated to minimize
distribution costs, and a market for the fuels is guaranteed by requiring
their use in alternative-fueled vehicles. The use of alternative fuels would
serve to decrease oil imports due to decreased demand for gasoline; as a
result, the trade deficit due to energy imports could be reduced. Although
it is difficult to determine the effect a decrease in U.S. gasoline
consumption would have on world oil prices, the analysis shows that
alternative fuel use could lead to suppression of oil prices by as much as
several dollars per barrel.
58
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VII. Plans for Future Study - AMFA Report to Congress II
This report is the first step in an ongoing analysis of the
environmental and economic impacts of alternative fuel use. The next
Report to Congress required by the Alternative Motor Fuels Act will be due
in December, 1992. Hence, EPA must continue to build on the work it
began for this report, and many of the issues discussed here could benefit
from further analysis. To achieve the goal of a complete, comprehensive
study of alternative fuels, EPA plans, and has already begun, to conduct
meetings with industry to explore research and technology developments
in the areas of alternative fuel production, alternative-fueled vehicle
technology, and environmental protection and control technologies. In
addition, EPA has developed an Alternative Fuels Research Strategy that
describes research needed to improve health and ecological risk
assessments of alternative fuels in comparison to conventional fuels.
EPA is continuing efforts in the area of alternative fuels, looking at
many of the environmental and economic impacts of alternative fuels,
including production, distribution, and use. Many uncertainties exist
regarding the health effects both of alternative fuels and of gasoline; more
research is needed to quantify them. In addition, information is lacking on
many of the environmental impacts of alternative fuel production and use,
particularly from an ecological point of view. EPA is continuing research in
these areas.
Continued analysis of many of the subjects contained in this report
would be desirable to improve the content of the next AMFA Report to
Congress. A more precise analysis of how each individual automotive
manufacturer will respond to Clean Air Act programs and the AMFA CAFE
credits would be useful to more accurately assess the impact of the AMFA
credits. The economics of alternative fuel production will need to be
reassessed as technological advances occur. Further analysis of the use of
recovery methods to mitigate the release of C02 from the production of
transportation fuels, and quantification of the environmental benefits and
economic costs of such technologies, would be useful. Further study of the
costs and environmental impacts of the use of alternative fuels, including
vehicular emissions, stationary source emissions, and other issues related
to health and the environment is also needed to add to the analysis
presented in this report.
59
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60
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Process Evaluation," J.D. Wright, et al, Solar Energy Research Institute
(Golden, CO), 1988.
29. "Ethanol from Lignocellulose: An Overview," J.D. Wright, Solar Energy
Research Institute (Golden, CO) in "Energy Progress," June 1988.
30. "The Potential of Renewable Energy, An Interlaboratory White Paper,"
U.S. DOE, OPPA, March 1990.
31. Letter from R. Bruetsch, EPA to J. Burroughs, National Propane Gas
Association. April 13, 1989.
32. "Coal-to-Methanol: An Engineering Evaluation of Texaco Gasification
and ICI Methanol-Synthesis Route," by Fluor Engineers and Constructors,
Inc., for EPRI, AP-1962, August 1981.
33. "Assessment of Costs and Benefits of Flexible and Alternative Fuel Use
in the U.S. Transportation Sector—Progress Report One: Context and
Analytical Framework," US Department of Energy, DOE/PE-0080, January
1988.
34. "Policymakers Summary of the Scientific Assessment of Climate
Change," Report to the Intergovernmental Panel on Climate Change from
Working Group 1, Fourth Draft, 25 May 1990.
62
-------
Environmental and Economic Study of
Alternative Motor Fuels Use
Report to Congress
In Response to
The Alternative Motor Fuels Act of 1988
Volume 2: Appendices
Final Draft - November 1991
U S Environmental Protection Agencv
Office of Mobile Sources
Emission Control Technology Division
-------
Environmental and Economic Study of
Alternative Motor Fuels Use
Report to Congress
Appendices
U.S. Environmental Protection Agency
Office of Mobile Sources
Emission Control Techology Division
-------
Appendix 3
Scenarios of Alternative Fuel Use
Table of Contents
Section Title Page
I. Scenario 1: Maximum Utilization of AiMFA Fuel
Economy Credits 3-2
II. Scenario 2: Nine City Program Equivalent 3-8
III. Scenario 3: 1 MMBPD Gasoline Displacement 3-13
IV. Analysis of Scenarios 3-15
References 3-18
-------
Environmental and Economic Study of
Alternative Motor Fuels Use
Appendices
Table of Contents
List of Abbreviations 1-a
Appendix 1: Energy Forecasting Assumptions 1 - I
Appendix 2: Overview of U.S. Energy Price and Consumption 2-1
Appendix 3: Scenarios of Alternative Fuel Use 3-1
Appendix 4: Alternative Fuels Availability and Economics 4-1
Appendix 5: Energy Supply Impacts of Alternative Fuel Scenarios 5 - 1
Appendix 6: Economic Impacts of Alternative Fuel Scenarios 6-1
Appendix 7: Environmental Impacts of Alternative Fuel Use 7 - 1
-------
Environmental and Economic Study of
Alternative Motor Fuels Use
List of Abbreviations
AFVs alternative fueled vehicles
AH acid hydrolysis
AMFA Alternative Motor Fuels Act of 1988
atm atmospheres
BAU business-as-usual
bcf billion cubic feet
BPCC byproduct value as a percent of corn cost
Btu British thermal units
bu bushel
CAA Clean Air Act
CAFE corporate average fuel economy
CARB California Air Resources Board
CFCs chlorofluorocarbons
OGF corn gluten feed
CGM corn gluten meal
CH4 methane
CNG compressed natural gas
CO carbon monoxide
CO2 carbon dioxide
COS carbonyl sulfide
CRR capital recovery rate
DDGS distiller's dried grains plus solubles
DFV dual-fueled vehicles
DM dry mill process
DMC direct microbial conversion
DoA U.S. Department of Agriculture
DOE U.S. Department of Energy
DRB demonstrated reserve base
E85 fuel mixture of 85 percent ethanol, 15 percent gasoline
El00 neat (pure) ethanol fuel
EIA Energy Information Administration
EQR enhanced oil recovery
1 -a
-------
EPA U.S. Environmental Protection Agency
EPRI Electric Power Research Institute
EVs electric vehicles
FFVs flexible fueled vehicles
GDP
gross domestic product
HC
hydrocarbons
H2S
hydrogen sulfide
IGCC/OTM
integrated gasification combined-cycle/once-through
methanol
I IF
instantaneous investment factor
IPCC
Intergovernmental Panel on Climate Change
kwh
kilowatt-hour
LNG
liquefied natural gas
LPG
liquefied petroleum gas
LPMeOH
Liquid Phase Methanol
M85
fuel mixture of 85 percent methanol, 15 percent gasoline
Ml 00
neat (pure) methanol fuel
MAIT
maintenance, administration, insurance and taxes
Mcf
thousand cubic feet
MLW
municipal liquid waste
MMBPD
million barrels per day
MMcf
million cubic feet
mpg
miles per gallon
MSW
municipal solid waste
MTPD
metric tons per day
N2
nitrogen
N2O
nitrous oxide
NOC
net corn cost
NMHC
non-methane hydrocarbons
NOx
oxides of nitrogen
02
oxygen
OEB
oil equivalent barrels
OOIP
original oil in place
1 -b
-------
POM polycyclic organic matter
PPI Producers Price Index
ppm parts per million
Pu plutonium
quads quadrillion Btu
RDF refuse-derived fuel
fRDF fluff refuse-derived fuel
dRDF densified refuse-derived fuel
RVP Reid vapor pressure
scf standard cubic foot
SERI Solar Energy Research Institute
SHF separate hydrolysis and fermentation
SNG synthetic natural gas
S02 Sulfur dioxide
SPR Strategic Petroleum Reserve
SRIC short rotation intensive culture
SSF simultaneous saccharification and fermentation
st short tons
tcf trillion cubic feet
TGTU tail gas treatment unit
Th thorium
tpd tons per day
U, U### uranium, isotopes ot uranium
USDA U. S. Department ot Agncultuie
USGS United States Geological Survey
VOC volatile organic compound
VMT vehicle miles traveled
WM wet mill process
1 -c
-------
Appendix 1
Energy Forecasting Assumptions
The following is a discussion of the assumption which EIA uses m the
publication Annual Energy Outlook which forecasts energy prices, supply,
and consumption to the year 2010 assuming a base case, low world oil
price case, and high world oil price case. Table 1-1 is a summary ot the
assumptions and projections used by EI A. [ 1J
Table 1-1
Summary of Assumptions and Projections for the
Market Economies
Projection
Economic Growth Rates
(percent per year)
1988
4.0
2QQ0
2.2-3.0
2010
2.2-3.0
OPEC Oil Production Capacity
(MMBPD)
28.2
34-36
41-45
Oil Prices (1989 $ per bbl)
15.18
20-34
26-47
Oil Production (MMBPD)
Non-OPEC
OPEC
27.1
22.0
25.7-27.4
24.4-32.3
23.5-25.6
28.4-40 1
Energy Consumption
Oil(MMBPD)
Gas(trillion cubic ft.)
Coal(million short tons)
Nuclear(tera watt hrs.)
Other(quadrillion Btu)
50.7
40.7
2299
1510
20.5
53.1-60.7
50.1-70.7
2604-3565
1796-1912
24.5-33 6
53.5-65 0
53.2-82 0
2941-4242
2096-2575
26.5-37 4
Total Primary Energy
(quadrillion Btu)
227
268-282
291-317
1 -1
-------
In the current market, a key determinant of petroleum prices is the
ability of a set of producers (particularly OPEC, which has dominated the
market since the early 1970s and will likely continue to do so) to limit
their production to less than their production capacity. For several more
years, relatively low oil prices are expected as OPEC works to control
members' combined output, and current low oil prices should bring supply
and demand more in balance in the future. However, as future oil
consumption rises toward world production capacity, the forces of supply
and demand are expected to raise prices.
OPEC is expected to dominate the world market with respect to the
resource base. Currently, nearly 70 percent of the world's proven oil
reserves are in the Middle East; the majority of these countries belong to
OPEC. Five countries, China, Mexico, Norway, the U.S., and the Soviet Union,
hold the vast majority of non-OPEC oil reserves, production of which is
expected to peak by the mid-1990s and decline thereafter, leading to :i
steady increase of market share for OPEC. EIA projects that demand tor
OPEC oil will approach capacity in the late 1990s, and that oil prices will
rise. Projected OPEC oil production capacity (maximum sustainable
production, adjusted to reflect current operable capacity in some countries)
is 34-36 million barrels per day (MMBPD) in 2000 and 41-45 MMBPD in
2010. Actual OPEC oil production is expected to be much less, 25-27
MMBPD in 2000 and 23-26 MMBPD in 2010. Non-OPEC oil production is
projected to be 24-32 MMBPD in 2000 and 28-40 MMBPD in 2010. The
development of new oil reserves discovered in some non-OPEC countries
such as Syria, Columbia, India, Brazil, the U.K., Norway, N. Yemen, and S.
Yemen is expected to only serve to offset the decline in oil production trom
other non-OPEC countries. The result of decreasing oil production in non-
OPEC countries will be increasingly concentrated production capacity
within a small group of producers, particularly the Persian Gulf producers
(Kuwait, the United Arab Emirates, Saudi Arabia, Iran, and Iraq).
Improvements in technology on the supply side, which locates
energy resources, plays a role in increasing market supply. Future oil
prices will be influenced by the ccst of development of natural gas
resources. If natural gas proves to be an inexpensive source of energy to
develop, the price of oil will be prevented from rising too rapidly At
present, natural gas principally competes as a boiler fuel with oil, this
market is large enough (especially in Europe) to have a major influence on
oil prices. On the demand side, technology is also an important factor in
determining oil prices. A recent trend toward more efficient energy use,
and use of more energy efficient products, has caused a declining energy
1-2
-------
use per dollar of gross domestic product (GDP) in major countries over the
last several decades.
The greatest growth in energy consumption worldwide is expected
among developing countries. However, energy consumption by the Market
Economies (excluding the Centrally Planned Economies of Eastern Europe,
the Soviet Union, and China), which currently account for approximately 4
out of every 5 barrels of world oil consumption, is expected to continue to
grow in the future. Much of this growth is expected to occur in the United
States.
The U.S. economy is expected to grow at rates between 2.1 and 2.8
percent over the forecast period, with stronger growth in earlier years
leveling off after 2000. The slowdown in growth projected after 2000
occurs as a result of a slower rate of expansion of the resource base of the
economy (labor, capital, energy, etc.), and changes in the productivity of
these factors. Inflation is assumed between 4.0 to 5.5 percent, as
measured by the changes in the implicit GNP price deflator. Interest rates
decline early and by 1995 remain stable for the rest of the forecast period.
1-3
-------
References
1. Annual Energy Outlook 1990: Long Term Projections. EIA, DOE,
January 1990.
1-4
-------
Appendix 2
Overview of U S. Energy Price and Consumption
Table of Contents
Section Title Page
I. Recent History of U.S. Energy Market 2-1
A. World and Domestic Distribution of Resources 2-1
1. Oil Reserves 2-2
2. Natural Gas 2-2
3. Coal 2-3
B. U.S. Energy Supply and Consumption 2-3
C Domestic Production of Energy Sources 2-10
D. Domestic Imports vs. Exports 2-13
E Domestic Energy Price 2-15
F. Effects of Energy Price on Alternative Fuel Use 2-15
II. Energy Forecasts: Economics and Supply 2-17
A. Petroleum and Petroleum Markets Forecasts 2-18
B. Natural Gas Market Forecasts 2-2 2
C Coal Market Forecasts 2-2 4
D. Renewable Energy Market Forecasts 2-2 5
References 2-27
-------
Appendix 2
Overview of U.S. Energy Price and Consumption
This appendix provides an overview of the U.S. energy picture,
including a summary of the recent history of the energy market, a
discussion of the global distribution of energy resources, and a
presentation of energy supply and economic forecasts. An overview of this
nature is important in the context of this report because it describes the
baseline scenario against which the merits of the various alternative fuel
use scenarios (presented in the next appendix) can be compared.
The appendix is divided into two main sections. In the first, the
distribution of world fossil energy resources is discussed, as are historic
trends in U.S. energy consumption and energy supply. In the second
section, forecasts of energy supply and economics are presented and
discussed.
I. Recent History of U.S. Energy Market
A. World and Domestic Distribution of Resources
Domestic resource availability is an important consideration when
evaluating the desirability of alternative fuel use. As energy consumption
continues to increase, the United States becomes more dependent on
foreign sources of energy (especially petroleum) from potentially
politically unstable regions such as the Middle East. In order to provide a
framework, a discussion of world resource availability is included along
with a discussion of U.S. domestic resource availability.
The primary energy sources used in the world are petroleum, coal,
and natural gas. Crude oil is concentrated in the Middle East; in the less
developed countries, located mainly along the equatorial belt; and in the
U.S.S.R. Natural gas is similarly distributed, but with the largest share
concentrated in the U.S.S.R. and Eastern Europe. Coal reserves are the most
abundant of the three, with the U.S. having the largest share. These three
energy sources will be discussed in more detail below.
2-1
-------
1. Oil Reserves
As of 1989, world crude oil reserves were estimated to be between
924 and 991 billion barrels. The Middle East holds approximately 63 to 66
percent of the total reserves. Figure 2-la shows the percentage of
petroleum reserves by world region. Eight countries, shown in Figure 2-lb
below, hold over 80 percent of the world's crude oil reserves. Although
the United States is the largest consumer of oil, it only holds about 3
percent of total world proven reserves (26.8 billion barrels).
In the United States, proven reserves of crude oil, and natural gas
liquids increased every year from 1949 until 1968, when, for the first
time, production exceeded net additions to proven reserves. Proven
reserves have fallen from a 1970 peak level of 39 billion barrels to an
early 1989 level of 27 billion barrels.
In addition to proven reserves, it is believed that the U.S. also holds
significant undiscovered oil resources. In 1980, the United States
Geological Survey estimated undiscovered, recoverable resources of oil in
the U.S. at 83 billion barrels. Onshore resources located in the Colorado
Plateau, Basin, Range and the Gulf Coast accounted for approximately 50
percent, and offshore resources near Alaska and in the Gulf of Mexico
account for over 30 percent.
The United States also has approximately 200 billion barrels of oil
available from oil shale, an undeveloped resource.[4] This figure
represents oil which is recoverable from shale containing over 30 gallons
per ton; recovery of this oil is estimated to be economic at about $50 per
barrel. Total estimated reserves of domestic shale oil total 820-3830
billion barrels oil equivalent. However, with present technology, the cost
of producing these reserves is prohibitive.
2. Natural Gas
As of 1989, world proven reserves of natural gas were estimated to
be about 3900 trillion cubic feet (tcf), the energy equivalent of roughly
7 00 billion barrels of oil. The U.S.S.R. holdings account for about 38
percent and the Middle East for roughly 30 to 32 percent of the world
total. In the Middle East, Iran has the largest gas reserves, accounting for
13 to 15 percent of the world total. The United States holds only 4 percent
of the world total, or 187 tcf. Significant natural gas reserves are also
located in Qatar, Saudi Arabia, Algeria, Venezuela, Canada, and Norway.
Proven reserves of natural gas by region and by country are presented in
2-2
-------
Figure 2-2a and 2-2b. A more detailed discussion of natural gas reserves
and derivative transportation fuels is presented in Appendix 4.
In 1980, the United States Geological Survey estimated undiscovered
natural gas resources in the United States to be 594 tcf, of which, close to
one-third or 161 tcf are located in Federal offshore areas.
3. Coal
By far, the world's greatest fossil energy resource is coal. In 1989,
recoverable world coal reserves were estimated at over 1 trillion tons,
equivalent to about 4 trillion barrels of oil. Anthracite and bituminous
coal, one-fifth of which is recoverable by surface mining, accounts for more
than 70 percent of this total. At 291 billion tons, the U.S. has the world's
largest recoverable coal reserves, containing roughly 20 times the energy
of proven domestic oil and gas reserves combined; of the total, 88 percent
is anthracite and bituminous coals. The U.S.S.R. has reserves of 270 billion
tons, 61 percent in anthracite and bituminous coals. The largest
recoverable world coal reserves are presented by region and by country in
Figure 2-3a and 2-3b. A more detailed discussion of domestic coal
reserves and derivative transportation fuels is presented in Appendix 4.
B. U.S. Energy Supply and Consumption
Energy consumption in the U.S. more than doubled during the 1950
to 1973 period, increasing from 33 Quadrillion Btu (Quads) in 1950 to 74
Quads in 1973 (Figure 2-4).[5] After the 1973 oil price shock, energy
consumption fluctuated, then rose to a peak level of 79 Quads in 1979
before returning in the mid-1980's to about the same level as in 1973.
From the 1970's to the present, the transportation, and residential and
commercial sectors have accounted for most of the growth in consumption.
In 1989, the U.S. consumed a total of 81.2 Quads of energy, a 1
percent increase from the 1988 level (Figure 2-4). Of the total
consumption, the transportation sector accounted for 22.23 Quads.[5]
2-3
-------
Figure 2-la
Proven Crude Reserves by Region, 1989
(World Total = 957 Billion Barrels)
64.75%
I North America
D Central and South America
§ Western Europe
S3 Eastern Europe and U.S.SJR.
D Middle East
El Africa
0Q Far East and Oceania
Figure 2-lb
Proven Crude Reserves by Country, 1989
(World Total = 957 Billion Barrels)
26.75%
10.45%
8.15%
8.05%
10.14%
I Saudi Arabia
D Iraq
S United Arab Emirates
§ Kuwait
HI Iran
5 U.S.S.R.
H Venezuela
SS Mexico
£3 Other
6.07%
4.60% 9.10%
7.22%
1.88%
2-4
-------
Figure 2-2a
Proven Natural Gas Reserves by Region, 1989
(World Total = 696 Billion Barrels Oil Equivalent)
30.94%
I North America
~ Central and South America
S Western Europe
B Eastern Europe and U.S.S.R.
H Middle East
5 Africa
Q] Far East and Oceania
Figure 2-2b
Proven Natural Gas Reserves by Country, 1989
(World Total = 696 Billion Barrels Oil Equivalent)
2-5
¦ U.S.S.R.
D Mexico
H Iran
S Indonesia
HU United Arab Emirates
B Iraq
HJ United States
S Canada
S3 Qatar
3 Algeria
S3 Saudi Arabia
B Venezuela
[Q Other
8.58%
4.20%
5.09%
38.20%
7.13%
5.86%
-------
Figure 2-3a
Proven Coal Reserves by Region, 1989
(World Total = 4041 Billion Barrels Oil Equivalent)
34.83%
I North America
O Central & South America
S Western Europe
iH Eastern Europe & U.S.S.R.
5 Africa
® Far East & Oceania
Figure 2-3b
Proven Coal Reserves by Country, 1989
(World Total = 4041 Billion Barrels Oil Equivalent)
4.617c
7.65%
6.28%
8.64%
7.07%
28.56%
10.70%
26.50%
H United States
~ U.S.S.R.
H China
D Australia
EH Germany
B South Africa
EH Poland
Other
2-6
-------
Figure 2-4
Consumption of Energy by End-Use Sector, Selected Years
50 60 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
The primary sources of energy used in the United States
are petroleum, natural gas, coal, hydropower, and nuclear power, all of
which are nonrenewable energy sources. Other sources which are used to
a much lesser extent for electricity generation include wood, waste,
geothermal, wind, photovoltaic, and solar thermal energy. Figure 2-5
shows historic energy consumption levels by source.
Petroleum remains by far the largest single source of energy used in
this country. Petroleum currently supplies about 42 percent of the energy
consumed in the United States, coal supplies about 24 percent, natural gas
supplies about 23 percent, nuclear power supplies about 7 percent,
hydroelectric power supplies about 3 percent and other sources (electricity
generated from wood, waste, geothermal, and wind) supply less than 1
percent.[1] See Figure 2-6.
2-7
-------
Figure 2-5
Consumption of Energy by Source, Selected Years
55 60 65 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
Figure 2-6
Consumption of Energy by Source, 1989 (Quads)
¦ Coal
~ Petroleum
El! Natural Gas
E3 Other
0 Hydroelectric
5 Nuclear
2-8
-------
Petroleum products meet approximately 97 percent of the
transportation -sector's energy needs, and in 1989, transportation energy
use accounted for approximately 65 percent of all the petroleum used in
the United States.[10] Considering the U.S. produces only half of all the
petroleum it consumes, the transportation sector alone consumes more
petroleum than is produced in this country. In the future, transportation
may likely account for an even larger share of the U.S. petroleum
consumption as coal, natural gas and electricity are more easily substituted
for oil in other sectors of the economy.
Consumption of petroleum products increased during the 1949 to
1973 period, at an average annual rate of 4.7 percent, reaching 17 MMBPD
in 1973, but decreased in 1974 by 3.8 percent to .16 MMBPD due to
increases in the price of crude oil, and the petroleum supply disruptions of
1973 and 1974.[5] Demand recovered in the late 1970's reaching 19
MMBPD in 1978, but declined to 15 MMBPD in 1983. After 1983, low oil
prices, continued economic growth, and adverse weather conditions
contributed to increased petroleum products consumption which reached a
level of 17 MMBPD in 1988.[5] See Figure 2-7.
Motor gasoline accounts for a large share of all petroleum products
supplied. From 1949 through 1988, its share was between 38 percent and
43 percent of supply. During the early 1980's, gasoline consumption
stabilized at about 6.6 MMBPD, but rose again to 7.3 MMBPD in 1988
Although the fuel efficiency of the fleet continued to increase through
1987, tending to depress demand, other factors contributed to more than
offset the increased efficiency such as a decline in motor gasoline prices
after 1982, increased highway travel, and after 1987, legislation which
allows travel at higher speeds (at which vehicles are less efficient) 15] See
Figure 2-7.
2-9
-------
20
18
16
14
12
10
8
6
4
2
0
Figure 2-7
Petroleum Products Supplied, 1973 to 1989
73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Years (1900s)
In summary, U.S. petroleum consumption in all sectors, including
transportation, has increased in the recent past and will continue to rise in
the foreseeable future.[13] This is a concern as the U.S. continues to import
greater portions of an increasing demand for petroleum products from
politically unstable countries. These concerns will be discussed in more
detail in the text below, and in Appendix 5.
C. Domestic Production of Energy Sources
Historically, three fossil fuels: petroleum, natural gas, and coal, have ,
accounted for the bulk of domestic energy production (Figure 2-8).
Because this report focuses on the fuels used in the transportation sector,
petroleum production will be discussed in the most detail.
2-10
-------
The production of petroleum from U.S. wells trended upward from
1949 through 1970, when it peaked at 9.6 MMBPD. During the next
several years, output declined, falling to 8.1 MMBPD in 1976. Production
during the 1950's and 1960's was marked by excessive capacity which
exceeded demand to such an extent that mechanisms such as production
prorationing and import ceilings were implemented in order to protect
domestic production. Petroleum demand increased by the 1970's when
production neared 100 percent of capacity. After this time, the average
productivity of wells began to decline, and oil production leveled off.[5]
See Figure 2-9.
The United States oil production industry is composed of two broad
groups: the major integrated companies and the independent producers.
In exploring for oil, the majors often search for larger oil and gas deposits,
which are usually found in difficult environments, such as offshore in
Alaska, while independents generally drill onshore in the lower 48
States.[10] Independents drill the vast majority of all U.S. wells; in 1988-
89, they were responsible for drilling 74 percent of all the oil and gas
wells, and 92 percent of all the new-field wildcat wells. But, by 1988, due
to falling oil prices and the lack of the willingness to risk the investment,
production in the Lower 48 States suffered the effects of a decreasing
number of new well completions, and it is expected drilling activity may
fall off further.
The United States is the world's second largest oil producer, only
after the Soviet Union. Since 1985, however, domestic oil production has
steadily declined, due to a number of factors including a drop in drilling
activity, the predominance of old fields that are suffering a natural drop in
productivity, a sharp decline in oil prices, abandonment of high-cost, low-
volume wells, and impediments to production in environmentally sensitive
areas.[10] Increases in Alaskan production at the end of the 1970's and
through 1988 counteracted declines in Lower-48 production.
Nevertheless, by 1988 daily domestic production had declined to 8.1
MMBPD, down from 9.6 MMBPD produced in the peak year of 1970. The
Energy Information Administration (EIA) predicts that by the year 2010,
domestic production will have declined to a level of 6.0-7.5 MMBPD
(including natural gas liquids). Clearly, the U.S. will become increasingly
dependent on imported oil in the near future.
2-11
-------
Figure 2-8
Domestic Energy Production by Source for Selected Years
70 -r
50 60 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
Figure 2-9
U.S. Consumption and Production of Crude Oil, Selected Years
D Total Petroleum Consumption
Total Crude Oil Production
50 60 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
2-12
-------
D. Domestic Imports vs. Exports
Starting in 1958 and continuing through today, the United States has
been a net importer of energy, with net imports reaching a level of 14.2
Quads in 1989 or 17 percent of total U.S. energy consumption.[5]
Petroleum accounts for the majority. Figure 2-10 illustrates the history of
U.S. oil supply. During the 25 years prior to 1973, oil imports grew
quickly, as demand for cheap foreign oil eroded quotas on petroleum
imports, and in 1973 net imports of petroleum reached a total of 6.3
MMBPD. Imports remained fairly steady through 1975, as a result of the
Arab oil embargo of 1973-74, coupled with increases in the price of crude
oil, which suppressed petroleum demand. After 1975, petroleum imports
increased until reaching a peak level of 8.5 MMBPD in 1979. After 1979,
oil imports decreased until 1986. In 1986, world production drove prices
down, which lessened domestic production, but increased demand,
resulting in an increase in oil imports to the 1988 level of 7.1 MMBPD.
While domestic production of oil has fallen in the last several years,
the U.S. consumption of oil has continued to rise, thus resulting in an
increasing level of imports. Figure 2-11 shows the levels of U.S. petroleum
demand which comes from all countries that export oil to the U.S., and
those from OPEC countries. Oil imports reached a peak level of 48 percent
of total U.S. oil consumption in 1977, and then fluctuated slightly before
reaching 32 percent in 1985. Since 1985, import levels have increased to
current levels of roughly 50 percent. Dependence on OPEC net imports
rose from 12 percent of total consumption in 1985 to 21 percent in 1988.
Costs for net petroleum imports were approximately $34 billion in 1988,
approximately $53 in 1989.1
Given that currently about 50 percent of our oil is imported at an
annual cost on the order of $50 billion, and that oil imports are projected
to increase from these levels in the future, the U.S. is faced with a very
sobering outlook. The cost of oil imports and their impact on the U.S. trade
balance is discussed in more detail in Appendix 5. Figure 2-12 shows
historic oil imports costs.
Natural gas imports fluctuated slightly between 1973 and 1979
when they reached a peak level of 1.24 Quads. After 1980, imports
continued to fluctuate until they reached a level of 1.22 Quads in 1988.
Currently, the tranportation sector consumes about 65 percent of crude oil used in
this country, or 8 MMBPD.
2-13
-------
Figure 2-10
U.S. Petroleum Supplies for Selected Years
49 50 55 60 65 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900s)
Figure 2-11
Total U.S. Petroleum Consumption, 1973-1989
Domestic, OPEC, and Non-OPEC Production
73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900)
2-14
-------
that the U.S. exports reached a peak level of 2.94 Quads in 1981. The
levels fluctuated through 1988 when they reached an export level of 2.5
Quads.
E. Domestic Energy Price
Historically, prices of coal and natural gas have been much less
volatile than those of oil. Oil markets were influenced throughout much of
the 1970's and 1980's by the pricing policies of OPEC; in contrast to the
coal market which is generally more competitive. Natural gas is subject to
State and Federal regulation, which dampened the response to natural gas
prices relative to oil throughout the 1970's. However, declines in crude oil
prices in 1986 and 1988 were severe enough to trigger declines in the
prices of other fossil fuels, especially natural gas. Between 1985 and 1988,
crude oil prices fell 52 percent, natural gas prices fell 38 percent, and coal
prices fell 20 percent. Figure 2-13 shows energy price by source for the
recent past (cost figures for bituminous, lignite, and anthracite coal could
not be obtained for the year 1989).
One important consideration in the context of alternative fuel use
relates to the effect that changes in demand for products such as oil would
have on price. A more detailed discussion of the relationship between
price and consumption is presented in Appendix 5.
F. Effects of Energy Price on Alternative Fuel Use
Much can be learned from historical trends about the behavior in the
marketplace resulting from changes in the price of energy. Price shocks in
the 70's and early 80's precipitated conservation measures by consumers,
and fuel economy legislation by Congress. In addition, growth in the U.S.
economy has been strongly influenced by world energy prices. A
pertinent question that can be addressed by examining historical trends
relates to the degree to which consumers would be apt to switch to
alternative transportation fuels absent market intervention. In the past,
higher fuel costs have not precipitated major switches to alternative
transportation fuels. As can be seen in Figure 2-14, throughout the 70's,
the average real fuel cost per mile to operate a vehicle was in excess of
70/mile. Even at these prices, consumers did not make a transition from
gasoline to alternative transportation fuels.
2-15
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Figure 2-12
Total U.S. Import Bill, 1973-1989
B t
73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89
Year (1900's)
u
s
D
0
1
I
a
r
3
P
e
r
M
M
B
t
u
10.00
-r
9.00
--
8.00
-¦
7.00
--
6.00
--
5.00
--
4.00
--
3.00
--
2.00
--
1.00
¦
0.00
73
Figure 2-13
Energy Price by Source, 1973-1989
Crude Oil -a- Natural Gas - ~ - Coal
73 74 75 76 77 78
81 82 83 84 85 86 87 88 89
-------
Figure 2-14
Average Real Fuel Cost Per Mile
12 -r
10 -•
9
7 -•
5 -¦
\
—I 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ^
70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87
Year (1900's)
Throughout the later half of the 1980s, real fuel costs have averaged
less than 50/mile. Even if fuel costs doubled from these levels, it is
uncertain that a significant move to alternative fuels would result. As
Figure 2-14 suggests, a moderate fuel price increase is unlikely to cause a
switch to alternative fuels (assuming the perceived real cost of alternative
fuels has not decreased at the same rate as the real cost of conventional
fuels in this same time frame.) If a move is to be made, additional market
based incentives will likely be required.
II. Energy Forecasts: Economics and Supply
This section will discuss energy forecasts including consumption,
production, and price. Energy forecasts are important to the context of this
report because they are necessary in order to analyze the environmental
and economic impacts of each scenario of alternative fuel use.
2-17
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Each year, The Energy Information Administration (EIA) of DOE
publishes the Annual Energy Outlook, which forecasts energy prices,
supply, and consumption through the year 2010. Three forecasts are
included: a base case, a low world oil price case, and a high world oil price
case. The information presented in this section relies heavily on the
forecasts by EIA. Different energy sources including petroleum, natural
gas, coal, and renewables are examined. It is important to note that EIA's
price forecasts do not assume the widespread use of alternative fuels, as
would be the case with the scenarios presented in this report. (This issue
is explored further in Appendix 5.) The EIA analysis employs several
assumptions which influence the energy forecasts they make.[13] These
are discussed in Appendix 1. EIA's price projections for major energy
sources are outlined in Table 2-15.
Table 2-15
Energy Price Projections for Major Energy Sources
Energy Source
World Oil Price
(1989$/MMBtu)
Domestic Natural Gas
Wellhead (1989$/MMBtu) 1.73
Domestic Coal Minemouth
(1989 $/MMBtu) 1.05
Projections (Low/Base/Hiph Oil Priced
2010
4.47/6.36/8.17
4.46/5.47/5.35
1.31/1.31/1.30
1988 2000
2.63 3.41/4.79/5.84
2.94/3.14/3.02
1.16/1.13/1.12
*EIA projects energy prices under situations of low, base, or high oil prices. Since
the prices of natural gas and coal are influenced by oil prices, three prices are
projected for each energy source.[13]
A. Petroleum and Petroleum Markets Forecasts
EIA projects oil prices (the U.S. refiner acquisition cost of imported
oil) ranging from $27.80-33.90/barrel (1989$) in 2000 and $36.90-
47.40/barrel (1989$) in 2010 depending on the economic conditions at the
time. In the recent past, low prices have caused moderate increases in
2-18
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demand especially in the U.S. and in the lesser developed countries. In the
long term, improvements in the financial picture for oil and gas producers
will result due to rapidly increasing oil and gas prices during the mid to
late 1990's. This will continue despite the slow down in domestic
production.
For the next 20 years, demand growth in the U.S. is projected to be
dominated by transportation fuels including motor gasoline, jet fuel, and
diesel fuel. Due to the limitations on the domestic resource base, this
translates into increased petroleum imports mainly in the form of crude
oil. With no market intervention, crude oil imports will be slightly offset
by increased use of alcohol fuels and natural gas liquids. However, during
the forecast period, net petroleum imports of crude oil and refined
products are projected to increase from 7.2 MMBPD in 1989 to between
10.4 and 14.9 MMBPD in 2010 depending upon world oil prices and the
domestic economic outlook; the highest historical import level to date was
in 1977, at 8.6 MMBPD. The forecast for 2010 reflects an import
dependence (net imports divided by total petroleum demand) ranging
from 54 to 67 percent.
According to EI A, U.S. oil production will fall by as much as 2 MMBPD
over the forecast period, from 9.7 MMBPD in 1989 to between 7.3 and 8.6
MMBPD in 2010, and demand increases by the same amount. With the fall
in oil prices in 1986, many domestic wells ceased to be profitable, resulting
in a continuing decline in domestic production of 3.2 percent per year from
1985 to 1988. Domestic oil production will continue to decline over the
forecast period even though oil prices are projected to rise with both a low
and high oil price scenario. Natural gas liquids and nonpetroleum sources
will meet some of this demand, but crude oil imports will need to rise
between 60 (with high oil prices) and 130 percent (with low oil prices) to
meet this increased demand and decreased domestic production. Import
levels will be met with both OPEC and non-OPEC crude oil. In 1989, the
U.S. imported an average of 3.9 MMBPD from non-OPEC sources and an
average of 4.1 MMBPD from OPEC sources. Although non-OPEC production
has continued to increase recently, the rate of increase is slowing, and is
expected to begin declining sometime in the next decade. EIA predicts that
by the late 1990's, after production from non-OPEC sources are in decline,
the market share of OPEC will increase.
One possible way to offset this would be to increase domestic
production. However, unless new sources of domestic crude oil are found
and drilled, domestic production is expected to continue to decline in the
future; by 1.7 percent (high oil price) or 3.1 percent (low oil price)
2-19
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throughout the forecast period. Alaskan oil production, which currently
accounts for almost 25 percent of total domestic crude oil production, has
passed its peak levels, and is in the decline phase. Although recent United
States Geological Survey (USGS) studies have shown that considerable (34
percent of undiscovered recoverable oil) resources lie in Alaska, it is
uncertain whether these fields will be developed during this forecasting
period (through 2010). USGS also estimates that approximately 38 percent
of the U.S. undiscovered recoverable reserves lie in the outer continental
shelf. If developed, production from these sources may slightly slow the
decline in lower-48 production, but reserve additions are still not expected
to keep up with demand for production. Environmental concerns are, an
important factor in the decision to explore and drill for crude oil in new
areas. The oil spill in Alaska's Prince William Sound reinforced
environmental concern, and as a result, a conservative approach will likely
be taken toward developing oil resources in Alaska and the Outer
Continental Shelf.
Another possible way to lessen OPEC imports is to increase imports
from non-OPEC sources. However, at this time this is not an option because
non-OPEC production will shortly be in decline. Also, other countries
import from non-OPEC sources, so there is little idle reserve capacity which
could be imported by the U.S.
By 1995, gasoline demand is projected to reach 7.5 MMBPD. Beyond
1995, fuel demand will continue to increase (even though vehicle sales are
projected to remain flat), due to a prolonged increase in total vehicle miles
traveled (VMT) by light duty vehicles. Slightly slower gasoline demand
growth rates of 0.4 percent and 0.7 percent for 1990-1995 and 1995-
2000, respectively, are expected due to a base case 2.0 miles per gallon
(mpg) increase in fleet fuel economy between 1990-2000, even though
VMT per vehicle continues to grow each year (low case and high case
assume a 1.8 percent annual increase).2 By the year 2000, gasoline
demand is expected to exceed 7.5 MMBPD. Assuming vehicle sales remain
constant from 2000 through 2010, total gasoline demand would reach 8.3
MMBPD in 2010.
Future motor gasoline demand is also influenced by environmental
concerns, which have led to antipollution measures such as lead phase-
down, vapor pressure reduction, or the use of oxygenates such as ethanol,
2Data Rources, Inc., in an analysis for EPA, projected an increase of 3.3 mpg in fleet
fuel economy. For such an increase, gasoline demand would be lower; a demand of
7.95 MMBPD was projected for 2010.
2-20
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methanol, MTBE, or ETBE. The use of oxygenates is expected to grow as
efforts to maintain high octane levels, reduce carbon monoxide and other
emissions, and lower the aromatic content of gasoline intensify. This will
likely displace some of the projected growth in non-oxygenated gasoline
consumption. Accommodating these changes in motor gasoline will likely
entail investment in downstream processing by refiners over the next 20
years, and will affect the price of gasoline. EIA's fuel price projections are
listed in Table 2-16. In 1989, motor gasoline (including tax) cost
$1.06/gallon; without considering the above mentioned changes in
refineries, EIA predicts that motor gasoline will cost $1.24-1,73/gallon
(1989$), depending on the oil price, in 2010.[ 13]3
Table 2-16
Transportation Consumption and Price of Energy bv Fuel
Projections (Low/Base/High Oil Price)
Consumption (O Btu1
Distillate
Jet Fuel
Motor Gasoline
Residual Fuel
Other
Total
1988
3.53
2.98
13.78
0.80
0.92
22.02
5.11/14.40/14.00
0.88/0.82/0.78
1.06/1.10/1.11
25.47/24.30/23.57
4.66/4.44/4.28
3.76/3.55/3.40
2£M
28.99/26.92/25.46
17.01/15.61/14.69
5.46/5.15/4.90
4.37/4.05/3.80
1.06/0.99/0.93
1.09/1.12/1.14
2010
Retail Prices d989$/Million Btu)
Distillate
Jet Fuel
Motor Gasoline
Residual Fuel
6.84 7.87/8.76/9.41 9.22/10.56/1 1.77
3.96 5.18/6.36/7.31 6.71/8.39/9.97
8.03 9.03/10.47/1 1.23 9.95/12.04/13.83
2.10 3.19/4.34/5.28 4.23/5.84/7 60
Reference [13]
3 EIA motor gasoline price projections in $/MMBtu were converted to $/gallon using
gasoline's higher heating value, per DOE/EIA convention.[6]
2-21
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B. Natural Gas Market Forecasts
Currently, natural gas is used in the residential, commercial,
industrial, electric utilities, lease and plant fuel, and pipeline fuel end use
sectors. In 1989, domestic natural gas consumption was approximately 19
billion cubic feet, and a study by the Energy Information Administration
predicts an increase in the consumption of natural gas in the future
creating an increase in demand for this energy resource.[13] Consumption
is expected to reach between 20.28 and 20.42 tcf by 1995 and between
21.87 and 22.32 tcf by 2010, depending on the scenario.
In the future, the electric utility sector is expected to be the fastest
growing sector for natural gas. In 1989, it accounted for 15 percent of
total gas use, and is projected to account for 26 percent by 2010. The
industrial sector is currently and likely will remain the largest gas
consumer in the U.S. In 1989, it accounted for 36 percent of the total gas
use.
Currently, domestic natural gas production provides the largest
source of natural gas supply in the U S. By the year 2010, natural gas
supply is expected to increase 2 percent. By this time, domestic gas
production is projected to account for approximately 24 percent of total
domestic energy production, or approximately 20.4 Quads (20 tcf). As
domestic consumption of natural gas increases, however, the U.S. will be
forced to look to imported natural gas to meet incremental demand.
The future price of natural gas will be dependent on future oil prices,
the demand for natural gas within producer countries, and the developing
demand for natural gas exports by pipeline or liquefied natural gas (LNG)
Because oil and gas compete in certain sectors of the energy market,
natural gas prices should rise as future oil prices rise. Although the U S
currently imports small quantities of LNG from remote locations such as
Algeria, the price of remote LNG is currently higher than domestic natural
gas prices. As U.S. consumption increases and domestic natural gas prices
rise, however, LNG will become more competitive in the U.S. market and is
likely to exert downward pressure on domestic natural gas prices.[2] Thus,
projecting future domestic natural gas prices without evaluating the
prospective LNG trade developments can lead to inflated estimates.
Recently, LNG imports from Algeria resumed in 1988 after two years
of contractual difficulties when no LNG was imported, and imports of
Algerian LNG are expected to increase in the future. In addition, Nigeria
has entered an agreement with Shell to have Nigerian gas marketed in the
2-22
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U.S. in the near future, and Norwegian representatives are currently
negotiating with U.S. firms who are potential purchasers of LNG. In the
year 2000, LNG imports are projected to be between 0.3 tcf to 0.6 tcf.
Over the forecast period, natural gas imports are projected to double,
coming primarily from Canada. Existing pipelines can accommodate
approximately 1.8 tcf/year, but due to seasonal demand swings and
logistics problems, actual flow is restricted to approximately 1.4 tcf/year.
Plans which are under way to expand trade would raise the capacity by
1.2 tcf/year when allowing for seasonal and logistical constraints.
Table 2-17 shows natural gas price projections through the year
2010. EIA's economic forecasts show domestic natural gas prices
increasing sharply in the near future projecting wellhead price of $3.03-
3.11 per thousand cubic feet (Mcf) for 2000. Without considering LNG
trade, EIA projects wellhead prices of $4.59-5.63/Mcf in 2010. Prior to the
year 2000, however, EIA does not consider the potential for increased LNG
trade in their domestic natural gas price projections. This makes it
probable that EIA's price projections for 1990 to 2000 are slightly higher
than would be the case with a steady rise in LNG trade, starting earlier
than 2000. When the possibility of increased LNG imports is considered,
the projected domestic natural gas wellhead price may be slightly lower
than predicted.
Table 2-17
Natural Gas Prices - 1986 to 2010
(1989$s per thousand cubic feet)
Low/Base/High
Oil Price Case for
1995-2010
Year
Wellhead Price
Commercial Price
Industrial Price
1986
1.94
5.08
3.23
1987
1.67
4.77
2.94
1988
1.69
4.63
2.95
1989
1.69
4.74
2.97
1990
1.75
4.90
3.06
1995
2.14/2.25/2.20
5.15/5.33/5.36
3.36/3.47/3.49
2000
3.03/3.23/3.1 1
5.96/6.32/6.35
4.23/4.48/4.45
2005
3.83/4.36/4.18
6.76/7.45/7.42
5.03/5.61/5.53
2010
4.59/5.63/5.51
7.52/8.71/8.75
5.80/6.83/6.86
Reference
[13]
2-23
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Because- of the vast amounts of natural gas reserves available
worldwide, it is reasonable to expect that when domestic natural gas prices
reach the level which allow LNG to compete, U.S. gas prices could remain
roughly constant over a significant period of time. Assuming that is the
case, the wellhead price of domestic natural gas could remain at the year
2000 price levels through 2010.
C. Coal Market Forecasts
In the 1980's, coal became the largest source of U.S. energy
production, and this trend is expected to continue in the future. In 1988,
the annual production was 950 million short tons. It is projected that
annual production will exceed 1 billion short tons in 1995, and will reach
between 1.4-1.7 billion short tons in 2010 depending on oil price. In 1988
coal production accounted for approximately 30 percent of total U.S.
energy production, and is expected to reach 40 percent by 2010
(depending on oil price and other economic factors).
Coal is expected to meet more of the projected increase in domestic
energy consumption over the forecast period than any other domestic
energy source. This is due mostly to the expected increase in electric
utility consumption, whose coal consumption should reach 90 percent by
2010. Economic reforms in Europe and elsewhere may increase electricity
consumption resulting in world coal trade. This could lead to a doubling of
exports by 2010, reaching between 161-292 million short tons depending
on the economic situation at the time. Regardless, U.S. recoverable coal
reserves are sufficient to meet even this increased demand for several
hundred years.
Real minemouth coal prices are expected to decrease through the
19 90's due to excess production capacity as shown in Table 2-18
Thereafter, prices are expected to' rise at an average annual rate of 1
percent to 2010, reaching between $28.66-28.33/short ton ($1989)
depending on the price of oil. In 1989, the price of coal was $22.85/short
ton.
2-24
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Table 2-18
Coal Prices. 1986-2010 ($1989 per ton')
Year
1986*
1987
1988
1989
1990
1995**
2000
2005
2010
Bituminous Coal and Lignite (F.O.B. Mines)
(Low/Base/Hiph Oil Price Casel
23.70
23.00
23.02
22.85
22.76
23.86/23.44/23.31
25.23/24.67/24.51
26.96/26.60/26.40
28.66/28.55/28.33
Reference [13]
~Years 1986-1990. Source: "Annual Energy Review: 1988," Energy Informauon
Administration, Department of Energy, May, 1989
**Years 1995-2010. Source- "Annual Energy Outlook. 1990," Energy Informauon
Administration, Department of Energy, January 1990.
The coal market forecasts by EIA assume current laws and
regulations concerning the use of coal as an energy source. Stricter acid
rain controls and heightened global warming concerns could affect the U S
coal industry, which may change coal market forecasts. Appendix 4 will
address the use of coal as a feedstock to produce various alternative
transportation fuels.
D. Renewable Energy Market Forecasts
Renewable energy sources include hydropower, geothermal, solar
thermal, ocean thermal, photovoltaics, wind, and biofuels. Biofuels include
wood, municipal and agricultural waste, landfill and sewer gas, methanol
derived from biomass), and ethanol. In 1988, renewable energy accounted
for 7 percent of the total energy consumed in the U.S. By 2010, it's market
share is expected to grow to 9 percent. Several forces, including an
increase in the cost of conventional energy, a growing concern for the
environmental problems, and a decrease in the delivered energy cost for
renewable energy technology, will contribute to its increased use.
Renewable energy sources are primarily used for the generation of
electricity; 10 percent of the total electricity generation in 19S9
2-25
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Hydropower is the largest contributor of renewable generation although
the potential for growth is somewhat limited. By 2010 electricity
generation from other renewable sources, such as wood, fuels from crops
and waste, industrial process waste, and landfill gas is expected to grow
significantly. Other uses for renewable energy sources currently include
the use of methanol and ethanol as additives in transportation fuel. Price
and fuel production capabilities of renewable energies are discussed in
more detail in Appendix 4.
2-26
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References
1. "Annual Energy Outlook 1989: Long-Term Projections", Energy
Information Administration, Office of Energy Markets and End Use, U.S.
Department of Energy, July 1989.
2. "Annual Outlook for Oil and Gas 1989," Energy Information
Administration, Office of Oil and Gas, U.S. Department of Energy, June 1989.
3. "Alternatives to Conventional Liquid Fuels in Automobiles," Draft
Report Office of Technology and Assessment, December 21, 1989.
4. "Moving America to Methanol," Charles L.Gray, Jeffrey Alson, The
University of Michigan Press, Ann Arbor, Michigan, 1988.
5. "Annual Energy Review 1988," Energy Information
Administration, Office of Energy Markets and End Use, U.S. Department of
Energy, May 1989.
6. "Monthly Energy Review December 1989," Energy Information
Administration, Office of Energy Markets and End Use, U.S. Department of
Energy, March 1990.
7. "Energy: The Next Twenty Years," The Ford Foundation, Ballinger
Publishing Company, Cambridge, Massachusetts, 1979.
8. "World Energy Supply: Resources, Technologies, Perspectives,"
Manfred Grathwohl, Walter de Gruyter Publishing, New York, New York,
1982.
9. "International Energy Annual 1988," Energy Information
Administration, Office of Energy Markets and End Use, U.S. Department of
Energy, November 1989.
10. "Interim Report: National Energy Strategy, A Compilation of
Public Comments," U.S. Department of Energy, April 1990.
2-27
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11. "Petroleum Supply Annual 1988 Volume 1 and Volume 2,"
Energy Information Administration, Office of Oil and Gas, U.S. Department
of Energy, May 1989.
12. "Energy Update," American Petroleum Institute, November 1989,
Vol. 1, No. 1.
13. "Annual Energy Outlook 1990: Long-Term Projections," Energy
Information Administration, Office of Energy Markets and End Use, U S.
Department of Energy, January 1990.
14. "The Motor Fuel Consumption Model Fourteenth Periodical
Report," Prepared by Energy and Environmental Analysis for Office of
Policy, Planning and Analysis, U.S. Department of Energy, December 1988.
15. "Energy and Macroeconomic Performance," Donald A.Norman.
American Petroleum Institute, December 1989, Discussion Paper #060
16. "Draft MOBILE3 Fuel Consumption Model," Office of Mobile
Source, Environmental Protection Agency, January 12, 1989.
17. "Highway Statistics Summary to 1985," U.S. Department of
Transportation,, Federal Highway Administration, 1985.
18. "Energy Security: A Report to the President," U.S. Department of
Energy, March 1987
19. "Monthly Energy Review June 1990", Energy Information
Administration, Office of Energy Markets and End Use, U.S. Department ot
Energy, May 1990.
2-28
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Appendix 3
Scenarios of Alternative Fuel Use
Table ot Contents
Section Title Page
I. Scenario 1: Maximum Utilization of AMFA Fuel
Economy Credits 3-2
II. Scenario 2: Nine City Program Equivalent 3-8
III. Scenario 3: 1 MMBPD Gasoline Displacement 3-13
IV. Analysis ot Scenarios 3-15
References 3-18
-------
Appendix 3
Scenarios of Alternative Fuel Use
A great deal of activity has taken place recently, particularly in the
last two years, aimed at spurring the broad-scale introduction of
alternative transportation fuels into the marketplace. The Alternative
Motor Fuels Act of 1988 established a system of corporate average fuel
economy (CAFE) credits, effective in the 1993 model year, designed to
stimulate the production of alternative-fueled vehicles by automobile
manufacturers. In June of 1989, President Bush announced his
Administration's proposal for revising the Clean Air Act, which contained
provisions requiring the introduction of clean fueled vehicles in the
nation's nine highest ozone cities. Recently, Congress has amended the
Clean Air Act, introducing concepts for an alternative-fueled fleet vehicle
program as well as a California clean vehicles program. Each of these
programs has precipitated a great deal of debate over the appropriate
mechanisms for promoting alternative fuel use, and over the proper role of
government in setting such mechanisms in place. Rather than focus on
implementation mechanisms in this report, since these can be controversial
and are not essential to estimating the environmental or economic impact
of alternative fuel use, it seemed more expedient to define several possible
scenarios of alternative fuel penetration into the transportation sector, and
to analyze the environmental, economic, and energy supply impacts ot
each. By following this approach, the desirability of an array of
combinations of alternative fuels, feedstocks, and degrees of market
penetration can be evaluated, thus providing an analytical framework tor
evaluating future alternative fuels initiatives.
In this appendix, three distinct scenarios of alternative fuel
utilization are described. Scenario 1 is constructed assuming the sale ot
flexible-fueled alternative-fueled vehicles, beginning in model year 1993.
in quantities sufficient to fully utilize CAFE credits provided under the
Alternative Motor Fuels Act. Scenario 2 is equivalent to the original
Administration Clean Air Act proposal for alternative-fueled vehicles in
the nine highest ozone cities. Driven by environmental concerns ot
improved air quality, this scenario targets the nine cities identified ab
severe ozone non-attainment areas. As such, Scenario 2 proposes a
geographically focused program. Scenario 3 is based on a scenario which
has been analyzed by DOE in the past, the displacement of one million
barrels per day from U.S. petroleum consumption. This scenario is volume
3-1
-------
oriented, as • opposed to environmentally oriented, with reduced oil
consumption as a goal. Since no specific locations for alternative fuel use
are specified, Scenario 3 would likely result in a more geographically
disperse use of alternative fuels than Scenario 2. In each of these
scenarios, a schedule for the sale of alternative-fueled vehicles is defined,
the amount of gasoline displaced from the transportation sector ib
quantified, and the impact of the various assumptions concerning energy
price, VMT growth, and fuel economy are addressed.
I. Scenario 1: Maximum Utilization of AMFA Fuel Economy Credits
The Alternative Motor Fuels Act of 1988 establishes a system of
CAFE credits for automobile manufacturers who choose to produce alcohol
(methanol, ethanol, or other alcohols) powered or natural gas powered
vehicles. Stated simply, the provisions of the Act allow manufactures to
factor an artificially high fuel economy (recognizing the fact that total
petroleum consumption is reduced through the use of these vehicles) into
their CAFE calculations for each alternative-fueled vehicle sold. These
credits, which become available beginning in model year 1993, are not
limited in the case of dedicated alternative-fueled vehicles. However, if
alcohol or natural gas dual energy automobiles (flexible-fueled vehicles or
FFVs) are used, CAFE credits are capped by limiting the maximum increase
in average fuel economy attributable to these automobiles to 1.2 miles per
gallon (mpg) for each CAFE compliance category.1 The Act discontinues
credits for the production of dual energy automobiles in model year 2004,
but allows credits for dedicated alternative-fueled vehicles to extend
indefinitely.2
The degree to which automobile manufactures will actually take
advantage of these credits is, of course, uncertain and difficult to predict.
At one extreme, manufacturers may ignore the CAFE incentives entirely
and produce no additional alternative-fueled vehicles. If this proves to be
the case, the environmental, economic, and energy security effects of the
CAFE credits provided in the Alternative Motor Fuels Act will be nil.
Manufacturers could respond in this manner if, for example, fleet fuel
economy increased above CAFE requirements, eliminating the need for
^The Act also limits dual-fueled vehicle credits to those vehicles which achieve equal or
greater efficiency while operating on an alternative fuel than while operating on gasoline
2The credit is limited to 0.9 mpg for model years 2005 through 2008 if extended by ilic
Secretary of Transportation.
3-2
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CAFE credits, or if manufacturers decide that the value of the credits does
not justify the cost of producing the flexible-fueled vehicles.
At the other extreme, manufacturers may take full advantage of the
credit mechanism and produce FFVs in quantities sufficient to achieve the
maximum 1.2 mpg CAFE increase. (In the near term, it is not likely that
many dedicated alternative-fueled vehicles will be sold due to the lack of a
developed fuel distribution infrastructure.) One possible response by
automakers, particularly domestics, to the availability of CAFE credits
would be to produce dual fuel luxury vehicles, capable of operating on
either gasoline or alternative fuels, and using the credits to ease
compliance with existing CAFE standards, provided the value of the credits
to the manufacturer exceed the incremental cost of producing alternative
fuel compatible luxury vehicle lines.3 Indeed, this is a reasonable scenario,
since the incremental cost of producing dual energy automobiles can be as
little as $300.4
Under this potential scenario, there would be no guarantee that the
FFVs would actually use any alternative fuels, particularly bince
alternative fuels currently lack widespread public availability. If the FFVs
were not operated with alternative fuels the majority of time, the net
result would be an effective relaxation of CAFE requirements by 1 2 mpg
(with corresponding C02 emission increases) for manufacturers choosing to
pursue this route, and little or no increased use of alternative fuels by the
transportation sector.5 Of course, the presence of these vehicles in the
marketplace might stimulate a limited introduction of alternative vehicle
fuels at commercial refueling stations; however, without specific incentives
requiring the use of alternative fuels in these vehicles, any resulting
displacement of gasoline would likely be small, possibly much less than the
increased gasoline consumption resulting from the CAFE "slippage." If,
however, incentives or requirements were used to guarantee the use of
alternative fuels in FFVs, the full environmental, economic, and energy
security benefits of the AMFA credit program could be realized.
3Due to the nature of the CAFE equation (i e, fuel consumption averaging), manufacturers
would obtain a greater benefit (per vehicle) by converting larger, luxury product linos 10
alternative fuel capability than by converting smaller, more fuel-efficient vehicles.
4For alcohol dual energy automobiles. The cost of vehicle modifications is discussed in more
detail in Appendix 4.
5 In the worst case, if all manufacturers sold the maximum number of FFVs allowed for the
duration of the program, and if none of these vehicles operated using alternative lucls,
gasoline consumption could increase about 4 billion gallons per year, resulting in, at most,
an increase of 40 million tons of C02 emitted annually, equivalent to a 2-3 percent increase
in C02 emissions from the transportation sector.
3-3
-------
In between these two extremes, a more "consumer-oriented"
outcome of the legislation would be the introduction of a variety of
alternative-fueled vehicles, including both luxury and economy models, in
response to increased demand for alternative-fueled vehicles by the
public, stemming from a combination of growing environmental concerns
and rising fuel prices. Manufacturers would thus ease the burden of CAFE
compliance under such a scenario, while at the same time providing
vehicles for which a consumer demand exists. Vehicles would likely be
sold primarily in areas where environmental pressures or regional
alternative fuel availability stimulate demand. In order to span the range
of possible responses to the AMFA legislation, this scenario was evaluated
under the assumption that manufacturers (both domestic and foreign)
would sell a mix of alternative-fueled light-duty vehicles (both in high and
low fuel efficiency product lines) in quantities sufficient to earn the full 1.2
mpg credit.6 The degree to which manufacturers will take advantage of
the AMFA CAFE credits requires further study and will be explored in
greater detail in future Reports to Congress. However, by examining the
"maximum credit usage" scenario of this study, much can be learned about
the potential impact of the provisions in the Act.
Thus, in the "Maximum AMFA Credit" scenario (Scenario 1), it was
assumed that flexible-fueled vehicles would be sold in model years 1993
through 2004 in quantities sufficient to achieve the maximum (1.2 mpg)
CAFE credit. Since CAFE incentives for FFVs are discontinued after 2004
(unless extended by the Secretary of Transportation), and since an
alternative fuel distribution system should be sufficiently developed after
12 years of FFV sales, it was further assumed that dedicated alternative-
fueled vehicles would be sold beginning in model year 2005 in quantities
equivalent to 1993-2004 MY flexible-fueled vehicle sales (as a fraction ot
total sales).7 Calculations were based on DOE's light duty vehicle sales
projection, and alternative-fueled vehicle fuel economy characteristics as
described in Appendix 4.[1] Vehicle sales by model year are shown in
6 Under existing requirements, foreign manufacturers do not need the credits to meet C \FE
If CAFE regulations were increased, they may choose to take advantage of the credit If
they do not, then the costs and environmental impacts projected for this scenario v.ouU be
commensurately lower.
7Based on the assumption that the supply of alternative fuels is sufficient. If the supp'\ of
alternative fuels or AFVs is insufficient to meet this level of vehicle sales by 2005 ho
economic and environmental benefits of alternative fuels projected for 2010 a ill he
somewhat less.
3-4
-------
Tables 3-la, 3-1 b, and 3-lc. Depending on the fuel type, alternative-
fueled vehicle sales range from 10 to 12 percent of total LDV sales.8
Table 3 -1 a
Scenano_l. Maximum CAFE Credits - CNG Vehicle Sales
Model Year Vehicle Tvne Units SoldfmillmnO
1993
FFV
1.06
1994
FFV
1 06
1995
FFV
1 10
1996
FFV
1 13
1997
FFV
1 13
1998
FFV
1 14
1999
FFV
1.14
2000
FFV
1 13
2001
FFV
1 13
2002
FFV
1 13
2003
FFV
1 13
2004
FFV
1 13
2005
dedicated
1 13
2006
dedicated
1 13
2007
dedicated
1.13
2008
dedicated
1.13
2009
dedicated
1 13
2010+
dedicated
1 13
The quantity of fuel consumed by these alternative-fueled vehicles
will be a function of their fuel economy characteristics, projections of
future vehicle miles travelled (VMT), and (in the case of flexibly fueled
vehicles) the fraction of operation during which alternative fuels are
actually used. With respect to vehicle fuel economy, DOE predicts an
annual increase in new vehicle fuel economy of approximately 1.5 percent,
based on projected demand for more fuel efficient vehicles.!I] This
assumption presents a logical difficulty under the rationale used in
defining this scenario, however. Absent legislation which would
significantly raise CAFE requirements, if new vehicle fuel economy were
increasing at 1.5 percent annually, there would be no need for
manufacturers to pursue the AMFA CAFE incentives by producing
^The actual number of vehicles required to achieve the maximum credit differs depending
on the type of fuel considered. The AMFA provides marginally greater credits for natural
gas powered than for alcohol powered vehicles (i.e. fewer flexibly fueled CN'C vehicles
would need to be sold than alcohol FFVs to achieve the maximum allowable credit ot 1 2
MPG)
3-5
-------
Table 3-lb
Scenario 1 Maximum CAFE Credits - Ethanol Vehicle Sales
Model Yenr
Vehicle Type
Units Sold (millions)
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010+
FFV
FFV
FFV
FFV
FFV
FFV
FFV
FFV
FFV
FFV
FFV
FFV
dedicated
dedicated
dedicated
dedicated
dedicated
dedicated
.10
11
15
18
18
19
.19
18
.18
.18
18
18
.18
18
.18
18
18
18
Table 3-lc
Scenario 1. Maximum CAFE Credits - Methanol Vehicle Sales
Model Year Vehicle Type Units Sold ("millions)
1993 FFV 122
1994 FFV t .22
1995 FFV 127
1996 FFV 1.30
1997 FFV 1 30
1998 FFV 1.31
1999 FFV 131
2000 FFV 1.30
2001 FFV 1.30
2002 FFV 1 30
2003 FFV 1 30
2004 FFV 1 30
2005 dedicated 1 30
2006 dedicated 130
2007 dedicated 1.30
2008 dedicated 1.30
2009 dedicated 130
2010+ dedicated 130
3-6
-------
alternative-fueled vehicles. Thus, it must either be assumed that CAFE
legislation moves in lockstep with the market (increasing at a rate of 1 5
percent per year), or that CAFE (and new vehicle fuel economy) will
remain at current levels (27.5 mpg).9 The latter approach (27.5 mpg CAFE
using EPA's projected VMT growth) was taken here.10
Total fuel consumption and gasoline displacement are shown in Table
3-2 for the three fuels (CNG, ethanol, and methanol) for which credits are
available. For flexible-fueled vehicles, it was assumed that 50 percent of
operation was fueled by gasoline, 50 percent by alternative fuels (CNG,
E85, or M85). Obviously, dedicated vehicles, which are introduced in
model year 2005, were assumed to be fueled entirely by alternative
fuels.11 As shown, displacement of gasoline reaches at most 2 billion
gallons per year by 2010.
Table 3-2
Scenario 1- Max Credit Scenario
Annual Gasoline Displacement and Alternative Fuel Use
(flat CAFE and 1.5% annual VMT growth)
Gasoline Displaced Alternative Fuels Used:
If If If If If If
Calendar Year QiQ Ethanol Methanol Qsl£ Ethanol Methanol
(billion gallons) (bef) (bil gal) (bil gal)
2000 0.60 0 24 0 30 289 2.52 3 46
2010 1 47 1.96 2 04 673 6 79 9 90
90f course, a host of scenarios regarding future fuel economy and CAFE requirements could
be postulated. However, the present analysis was limited to these two possibilities
Indeed, real energy prices are lower now than they were in 1972. yet CAFE is currently
over 10 mpg higher now than it was then. Thus, it can be argued that CAFE legislation,
rather than market demand for more fuel efficient vehicles, will likely be the more
important factor driving new vehicle fuel economy in the near future (unless, of course,
fuel prices were to increase dramatically).
^Dedicated ethanol and methanol vehicles were assumed to operate on E100 and M100,
respectively.
3-7
-------
Because of the attractive emission characteristics of alternative-
fueled vehicles it is likely that these vehicles would be marketed in large
urban areas, particularly given the recent incorporation of fleet vehicle
provisions and California pilot program provisions into the Clean Air Act.
The likelihood of this happening is further enhanced by the economics of
fuel distribution. Economic considerations dictate that a concentrated use
of alternative-fueled vehicles in an urban area is more likely during the
introductory phase of alternative fuels than in a geographically disperse
one. Under such a scenario, it is quite likely that alternative fuels will be
made available for use and consumed initially primarily in urban areas
(thus maximing any environmental benefits associated with alternative
fuel use), although no requirements insuring use in urban areas actually
exist. In the long term, use of dedicated vehicles (beginning in model year
2005) might be more geographically disperse, with fuel available in most
cities as well as along major transportation corridors.
Since the AMFA credit program alone does not mandate either
vehicle manufacture or alternative fuel use, and does not specify use in
high pollution locations, there is no guarantee that the maximum
environmental and economic benefits of this program will be realized.
Although vehicular VOC and toxic emissions would be reduced with
alternative fuel use, they would not necessarily be targeted in high ozone
areas, where emission reductions are needed most. Alternative fuel pump
prices would most likely be higher than those under a larger volume, more
geographically focused program, because of the higher distribution and
infrastructure costs resulting from the decentralized market. If, however,
legal mechanisms requiring the actual use of alternative fuels in FFVs are
instituted, and if high ozone locations are targeted and specified, this
program could have significant impact on improving the air quality ot
metropolitan locations at costs similar to those under a larger,
geographically focused program. A discussion of the energy supply,
economic, and environmental impacts of this scenario under a number of
fuel-feedstock combinations is presented later in the report.
II. Scenario 2: Nine Citv Program Equivalent
In July 1989 the President submitted to Congress the
Administration's proposals for revising the Clean Air Act. One major
component of this plan was the Clean Alternative Fuels Program. As
designed, this program would replace a portion of the motor vehicle fleet
in the nation's highest ozone cities with new clean fueled vehicles meeting
stringent emission standards, and operating on clean burning fuels such as
3-8
-------
compressed natural gas, electricity, ethanol, liquefied petroleum gas,
methanol, and reformulated gasoline. The original nine city alternative
fuel program provides the basis for the second scenario of alternative fuel
penetration discussed in this report. Throughout the Clean Air Act (CAA)
amendment process. Congress considered similar alternative fuel programs
targeted at the same nine cities, and ultimately adopted an alternative
fuels pilot program for the state of California and a national alternative-
fueled fleet vehicle program. The CAA amendments were adopted in
November, 1990; EPA was completing this report at that time. Since the
purpose of the scenarios considered in this report is to provide some
context for comparison of different types of alternative fuel programs
rather than to provide an analysis of the specific programs adopted in the
CAA amendments, no attempt to update or revise this report based on
Clean Air Act developments was made. (In addition, the number of
vehicles which would be affected by the California and Fleet programs is
only a fraction of the vehicles which would be affected by either Scenarios
1 or 2; the environmental impacts of the CAA amendments programs
would be commensurate but smaller than those of Scenarios I and 2 and
economic impacts would be slightly greater due to reduced economies of
scale.)
The Administration's program called for the introduction of
alternative-fueled vehicles in the nine most serious ozone nonattainment
areas of the country: Los Angeles, Houston, New York City, Milwaukee,
Baltimore, Philadelphia, Greater Connecticut, San Diego, and Chicago. The
proposal called for a phased-in introduction of clean fuel vehicle sales in
these areas totaling:
500,000 vehicles in 1995
750,000 vehicles in 1996
1,000,000 vehicles each year from 1997 through 2004
Convenient fuel availability in these serious ozone areas would be
ensured by requiring that all large stations (i.e., stations that dispense
more than 50,000 gallons per month) provide at least one clean,
alternative fuel.12 To achieve the desired pollution reduction benefits, it
would also be important to ensure that all clean, alternative-fueled
vehicles actually operate on clean fuels while in these ozone nonattainment
areas. The emission reduction goals targeted in the program assumed the
l2This represents approximately 14,000 stations, out of a total of 177,000 nationwide, much
fewer than the 120,000 stations that were required to provide unleaded gasoline when it was
similarly required for environmental reasons in 1975.
3-9
-------
use of dedicated alternative-fueled vehicles in model years 2000 and
beyond. Vehicle sales for Scenario 2 are shown by model year in Table 3-
3.
Since in this scenario the AMFA CAFE credits are not the driving
mechanism by which alternative-fueled vehicles are brought into the
marketplace as they are in Scenario 1, two sets of assumptions pertaining
to new vehicle fuel economy and VMT growth can be made. Assuming
relatively low energy prices and no increase in CAFE requirement from
27.5 mpg, manufacturers might still use CAFE credits generated by clean
fueled vehicle sales and allow the fuel economy of their gasoline vehicles
to "slip." Scenario 2a employs a flat (27.5 mpg) CAFE and a 1.5 percent
annual growth in VMT, based on EPA's MOBILE4 Emissions Model. In
Scenario 2b, it was assumed that new vehicle fuel economy would increase
at a rate of approximately 1.5 percent per year, as predicted by DOE.[ 1 ]
Similarly, DOE's estimate of annual growth in VMT was used in Scenario
2b.[l]
Table 3-3
Scenario 2: Nine City Program - Clean Fueled Vehicle Sales
Model Year Vehicle Type Number of Vehicles Sold
1995 FFV1 500,000
1996 FFV 750,000
1997 FFV 1,000,000
1998 FFV 1,000,000
1999 FFV 1,000.000
2000 dedicated 1,000,000
2001 dedicated 1,000.000
2002 dedicated 1,000,000
2003 dedicated 1,000,000
2004 dedicated 1,000.000
2005 dedicated 1,000,000
2006 dedicated 1,000,000
2007 dedicated 1,000,000
2008 dedicated 1,000,000
2009 dedicated 1,000,000
2010+ dedicated 1,000,000
1 Electric vehicles are assumed to be dedicated beginning in model year 1994, all
others are assumed to have dual fuel capability until model year 2000.
3-10
-------
The amount of gasoline displaced and the amount of alternative fuels
used is dependant (in the case of FFVs) on the fraction of vehicle operation
over which alternative fuels are used. The purpose of the Administration's
Nine-City Alternative Fuel Program was to provide emission reductions of
ozone-forming pollutants in the nine severe non-attainment areas. Thus, it
was to be required that vehicles use low-emitting alternative fuels during
100 percent of their operation within the non-attainment area.13 These
same requirements were adapted to Scenario 2. During operation outside
of the non-attainment area these vehicles would normally be allowed to
burn either clean fuels or gasoline. However, for this analysis, as a
simplification it was assumed that all operation outside of the non-
attainment area would take place on alternative fuels.14 National gasoline
displacement and alternative fuel consumption under Scenarios 2a and 2b
are shown in Table 3-4a and 3-4b. A discussion of the energy supply,
economic, and environmental impacts of this scenario under a number of
potential fuel-feedstock combinations is presented later in the report.
A program such as the Nine Cities Program, which is environmentally
driven and geographically constrained, has certain environmental and
economic advantages relative to a geographically disperse program. Since
vehicle sales would be mandated and the vehicles would be required to
use alternative fuels in the most highly polluted cities, the air quality
benefits of alternative vehicle fuel use would be maximized. By limiting
the locations where vehicle sales and fuel use would be required, this
program enables alternative fuel producers to minimize distribution costs
and refueling infrastructure costs. Service station owners would have a
guaranteed market that would grow with time, helping to reduce the
investment risks of remodelling the station to sell the new fuel. Hence,
many of the uncertainties and logistical problems, which would tend to
inflate the price of alternative fuels, would also be avoided.
^Although ozone is less often a problem during winter months, many alternamc jcIs
would also provide CO benefits, which would be useful under cold conditions Hence nav
prove desirable to extend requirements for alternative fuel use throughout the year borne
technology problems persist with the use of M100 and E100 in cold temperatures, ho«.c\er a
number of engineering solutions are being developed. (CNG has few ambient temperature
problems.) Year-round use of alternative fuels in alternative-fueled vehicles was a^unied
in this analysis.
14If a portion of operation does take place using gasoline, environmental and economic
benefits would be reduced commensurately Overall cost-effectiveness, however, would .ioi
change significantly in most cases, since the incremental cost of producing enough FP. > io
achieve the same environmental benefits that would be realized under 100 . ..m
operation using alternative fuels would be small.
3-11
-------
Table 3-4a
Scenario 2a: Nine Citv Program
(flat CAFE and 1.5% annual VMT growth)
Gasoline Displaced
(billion gallons per year)
Quantity of Alternative Fuel Used
(billion gallons per year)
Calendar
If
If
If
If
If
If
If
If
If
Year
CNG
Electric
Ethanol
LPG
Methanol
CNGl
Electc^
Ethanol
LPG
2000
1.56
2.65
1.21
2.65
1.17
359
34.3
3.1 1
3.83
2010
1.82
5.77
2.56
5.77
2.36
700
74.7
6.99
8.33
If
MethanQl
3.92
Table 3-4b
Year
2000
Scenario 2b; Nine Citv Program
(DOE Fuel Economy and VMT)
Gasoline Displaced
(billion gallons per year)
Calendar I f
CNG
2.96
If If If If
Electric Ethanol LPG Methanol
2.96
2.47
2.96 2.35
Quantity of Alternatvie Fuel Used
(billion gallons per year)
If If If If If
CNG1 Electc2 Ethanol LPG Methanol
386 42.6
3.35
4.27 4.23
201 0
6.1 8
6.18
6.03
6.18 5.99
703
91.1
7.12
8 93 9.4 1
1 CNG use in billion cubic Icci (bef) per year
2 Electricity use in billion kilowjil hours (billion kw-lu) per year
3-12
-------
III. Scenario 3: 1 MMBPD Gasoline Displacement
In contrast to Scenario 2, an environmentally driven and
geographically focused program. Scenario 3 is defined by a desired level of
displacement of petroleum-based fuels from the marketplace, with no
specification of locations for implementation Hence, there is no guarantee
that alternative fuels would be used in locations where their
environmental benefits would be most needed (i.e. severe ozone non-
attainment cities). Like Scenario 1, the environmental impacts of this
program could be diluted if alternative fuel usage is widespread across the
country. In addition, the distribution costs for the fuel could be somewhat
higher, since alternative fuels could be sold anywhere, regardless of the
prexistence of an ideal distribution network. The costs and risks to
individual distributors and service station operators will be higher under
Scenario 3 than if the locations were centralized and fuel usage by a
(reasonably) large fraction of the local population guaranteed. Of course,
an efficient market would tend to optimize fuel distribution costs and use
would likely be somewhat concentrated in centralized areas; however,
uncertainties in this type of program would make overall optimization
difficult.15 Absent the geographical focus of scenario 2, the overall
economic and environmental impacts of such a program would be
considerably less.
The Department of Energy has been actively involved in assessing
the costs and benefits of alternative fuel use in recent years. Several DOE
reports have been published which consider the impacts of displacing one
million barrels per day (MMBPD) of petroleum consumption with
alternative fuels by 2010.[3] This level of alternative fuel penetration is
the basis for the third scenario under consideration in this report.16
In order to achieve this level of gasoline displacement, the sale of a
significant quantity of alternative-fueled vehicles and alternative fuels
15The fact that an individual segment of the transportation sector would tend to optimize us
operations does not necessarily mean that the economics of an alternative fuels program
would be optimized on the whole For instance, due to system logistics, two fuel bupplicrs
may choose to distribute fuel in entirely different locations, and thus minimise their own
costs and investments, but, in so doing, dilute the concentration of alternative fuel use, and
thus require increased service station modifications and costs. Conversely, auio
manufacturers might choose to limit the number of product lines on which alternative fuel
technology is offered, reducing manufacturing costs. This, however, would tend to expand
the geographical area over which alternative-fueled vehicles are sold, thus increasing fuel
distribution costs. Absent a perfectly efficient marketplace, some lack of overall
optimization would likely result.
^The displacement of 1 MMBPD of gasoline was considered in this report
3-13
-------
would be required. The market would ultimately decide where alternative
fuels would be offered and to what extent they would impact the
petroleum fuel sales of a specific location. As a convenience, the schedule
for alternative-fueled vehicle introduction was assumed to be the same
(with proportionately higher vehicle sales) as that employed in Scenario 2.
It was further assumed that (through pricing incentives or some other
mechanism) flexible-fueled vehicles would use low-emitting alternative
fuels during 100 percent of their operation. Flexible-fueled vehicles are
first introduced in the 1995 model year, with dedicated technology
appearing in model year 2000. Because this program is not specific with
regard to location, sales of alternative-fueled vehicles could occur
anywhere, but the market will probably focus sales to some extent on
urban areas.
The number of alternative-fueled vehicles required to displace one
MMBPD of petroleum depends heavily on future trends in vehicle fuel
economy. As new vehicle fuel economy increases, the gasoline
displacement effects associated with substituting an alternative-fueled
vehicle for a gasoline vehicle are reduced ( i.e., the more fuel efficient the
gasoline vehicle, the less impact associated with displacing it from the
fleet). On the other hand, assuming new vehicle fuel economy remains at
27.5 mpg (and is sustained at that level due to CAFE regulations), the
"slippage" in gasoline fuel economy resulting from the AMFA credits would
reduce the gasoline displacement effects of alternative-fueled vehicle sales
even further. As a simplification, DOE's fuel economy and VMT growth
projections (with the corresponding assumption that manufacturers will
not need the AMFA CAFE credits) were employed.
The quantity of gasoline displaced is also a function of the type ot
alternative-fueled vehicle sold and the fraction of operation (in the case ot
FFVs) using alternative fuels. Vehicles operating on M85 and E85 will
displace less gasoline than vehicles operating on neat alternative fuels, due
to the presence of gasoline in the alcohol blend. Vehicle sales necessary
to displace one MMBPD of gasoline are shown for each vehicle type in
Table 3-5. Gasoline displacement and alternative fuel consumption are
presented in Table 3-6.
3-14
-------
Table 3-5
Scenario 3: 1 MMBPD Gasoline Displacement
Clean Fueled Vehicle Sales
Number of Vehicles Sold (million).
Model
Vehicle
If
I f
If
If
If
Year
Tvoe
CNG
Electric
Ethanol
LPG
Methanol
1995
FFV1
1 24
1 24
1.28
1 24
1 28
1996
FFV
1.86
1 86
1 91
1 86
1 92
1997
FFV
2.48
2 48
2.55
2.48
2 56
1998
FFV
2.48
2.48
2 55
2.48
2.56
1999
FFV
2.48
2.48
2.55
2.48
2 56
2000
dedicated
2.48
2.48
2 55
2.48
2.56
2001
dedicated
2.48
2.48
2.55
2.48
2.56
2002
dedicated
2.48
2.48
2.55
2.48
2.56
2003
dedicated
2.48
2.48
2 55
2.48
2 56
2004
dedicated
2.48
2.48
2.55
2.48
2.56
2005
dedicated
2.48
2.48
2 55
2.48
2 56
2006
dedicated
2 48
2.48
2.55
2.48
2 56
2007
dedicated
2.48
2.48
2 55
2.48
2 56
2008
dedicated
2.48
2.48
2.55
2.48
2.56
2009
dedicated
2.48
2.48
2.55
2.48
2.56
2010+
dedicated
2.48
2.48
2.55
2.48
2 56
1 Electric
vehicles are
assumed to be
dedicated
beginning
in model
year 1995, all
others are assumed to have dual fuel capability until model year 2000.
IV. Analysis of Scenarios
The three scenarios considered in this report allow the evaluation of
three significantly different levels of alternative fuel use. In Appendix 4,
the availability of alternative fuels from a number of different energy
feedstocks will be discussed. For each fuel/feedstock combination the
quantity of alternative fuels that can be produced in a given year will be
estimated. Each of the three scenarios described here will be evaluated for
each discrete fuel/feedstock combination which can produce sufficient
quantities of fuel to satisfy projected demand. Of course, for any type of
fuel under consideration, a combination of feedstocks could be used to
produce the required quantity of fuel. The environmental, economic, and
energy supply effects of such a "combination" scenario can easily be
determined by weighting the results of any of the discrete scenarios,
however. As outlined above, the potential fuel/feedstock combinations
and the cost of fuel production are presented in Appendix 4. Appendix 5
3-15
-------
Table 3-6
Scenario 3: I MMBPD Gasoline Displacement
(DOE Fuel Economy and VMT)
Gasoline Displaced Quantity of Alternative Fuel Used
(billion gallons per year) (billion gallons per year)
Calendar
If
If
If
If
If
If
If
If
If
If
Year
CNG
Electric
Ethanol
LPG
Methanol
CNG1
Electc2
Ethanol
LPG
Methanol
2000
7.33
7.33
6.29
7.33
6.03
958
1 06
8.53
10.6
10.8
2010
15.3
15.3
15.3
15.3
15.3
1 740
226
18.1
22.1
24.1
' CNG use in billion cubic feel (bef) per ycjr
2 Elcciricily use in billion kilowju hours (billion kw-lir) per year
3-16
-------
evaluates the energy supply considerations of each scenario. In
Appendices 6 " and 7, the overall economic and environmental effects of
each scenario are presented.
3-17
-------
References
1. "The Motor Fuel Consumption Model, 14th Periodical Report,"
prepared for Martin Mariettta Energy Systems, Inc., by Energy and
Environmental Anlaysis, Inc., December 15, 1988.
2. "Annual Energy Outlook," EIA, January 1990, DOE/EIA-0383(89).
3. "Assessment of the Costs and Benefits of Flexible and Alternative
Fuel use in the U.S. Transportation Sector-Progress Report One: Context
and Analytical Framework," U.S. DOE, January 1988, DOE/PE-0080.
3-18
-------
Appendix 4
Alternative Fuel Availability and Economics
Table of Contents
Section Title Page
I. Availability and Costs of Potential Feedstocks 4-1
A. Coal 4 - 2
B. Biomass 4-4
1. General Biomass 4-5
2. Corn 4-9
C Municipal Waste 4-13
D. Natural Gas 4-16
1. Natural Gas from Conventional Sources 4-16
a. Domestic Natural Gas (Lower-48) 4-16
b. Imported Natural Gas 4-17
c. Alaskan Natural Gas 4-18
d. Vented and Flared Natural Gas 4-19
2. Natural Gas from Nonconventional Sources 4-21
E Liquefied Petroleum Gas 4-2 3
F. Nonbiomass Renewable Energy Feedstocks 4-2 6
1. Plutonium and Uranium 4-2 6
2. Solar Energy 4-2 7
II. Production Costs of Candidate Alternative Fuels 4-2 7
A. Compressed Natural Gas 4-2 9
1. Production Costs 4-3 0
a. Coal 4-30
b. Biomass 4-32
c. Municipal Waste 4-3 2
d. Natural Gas 4-3 4
2. Fuel Distribution/Infrastructure Costs 4-3 5
3. Vehicle Efficiency and Cost 4-3 7
a. Efficiency 4-3 7
b. Vehicle Cost 4-3 7
4. CNG Pump Price 4-3 8
-------
Table of Contents (Cont'd)
Section Title Page
B. Electricity 4-4 1
1. Production Costs 4-4 2
a. Conventional 4-4 2
b. Biomass and Municipal Waste 4-4 3
c. Solar 4-44
d. Nuclear Breeder Reactors 4-4 5
2. Fuel Distribution/Infrastructure Costs 4-46
3. Vehicle Efficiency and Cost 4-47
a. Efficiency 4-47
b. Vehicle Cost 4-4 8
4. Electricity Pump Price 4-4 8
C Ethanol 4-50
1. Production Costs 4-5 0
a. Corn 4-5 1
i. Net Corn Costs 4-5 2
ii. Operating Cost 4-5 8
iii. Capital Costs 4-61
iv. Technological Improvements 4-62
v. Conclusion 4-62
b. Cellulosics 4-64
c. Overall Conclusion 4-6 6
2. Fuel Distribution/Infrastructure Costs 4-67
3. Vehicle Efficiency and Cost 4-7 0
a. Efficiency 4-7 0
b. Vehicle Cost 4-7 0
4. Ethanol Pump Price 4-7 0
D. Liquefied Petroleum Gas 4-7 3
1. Production Costs 4-7 3
2. Fuel Distribution/Infrastructure Costs 4-7 3
3. Vehicle Efficiency and Cost 4-7 4
a. Efficiency 4-7 4
b. Vehicle Cost 4-7 4
4. LPG Pump Price 4-7 4
-------
Table of Contents (Cont'd)
Section Title
E Methanol
1. Production Costs
a. Coal
i. Dedicated Methanol Production
ii. Coproduction of Methanol and Electricity
iii. Technological Advances in Coal Gasification
b. Biomass
c. Municipal Waste
d. Natural Gas
2. Fuel Distribution/Infrastructure Costs
3. Vehicle Efficiency and Cost
a. Efficiency
b. Vehicle Cost
4. Methanol Pump Price
Appendix 4-A
References
Page
4-75
4-76
4-76
4-76
4-79
4-81
4-82
4-85
4-86
4-89
4-9 I
4-9 1
4-92
4-92
4-98
4-100
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Appendix 4
Alternative Fuel Availability and Economics
The potential for an alternative transportation fuel to attain
widespread use depends on a number of factors, including the availability
of the feedstock and the economics of producing the fuel given available
technology. Feedstock costs, including future price projections, must be
known to allow determination of the relative costs of producing each fuel
from each prospective feedstock. Plant construction and financing costs
must also be considered when determining the cost of producing a fuel
from various feedstocks. Finally, distribution, infrastructure, and vehicle
costs must be included to obtain an overall pump price for each fuel.
This appendix addresses the various costs associated with producing
five alternative transportation fuels that re commonly discussed: methanol,
ethanol, compressed natural gas, liquefied petroleum gas, and electricity.
Reformulated gasoline, though it offers certain environmental advantages
relative to conventional gasoline, does not represent an alternative to
petroleum fuels per se, and thus was not considered. In addition, several
alternative fuels such as hydrogen, solar energy, and others which may
play a role in the long term, were not analyzed in this report due to timing
constraints; several of these additional fuels will be looked at in detail in
subsequent versions of this Environmental Study. Section I of this
appendix outlines the availability and costs of potential fuel feedstocks,
including coal, biomass, municipal waste, natural gas, liquefied petroleum
gas, and non-biomass renewable energies. Section II provides discussion of
fuel production technologies and estimates of production and distribution
costs and pump prices for each alternative fuel. Tables summarizing the
pump prices projected in the years 2000 and 2010 for each fuel may be
found in both the Executive Summary and the Report.
I. Availability and Costs of Potential Feedstocks
The geographical availability of a resource and its projected cost
determine whether it will be a reasonable feedstock for alternative fuel
production. The potential use of coal, biomass (including corn), municipal
waste, natural gas, and non-biomass renewable energies as alternative fuel
feedstocks will be addressed in the following subsections.
4-1
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A. Coal-
As discussed in Appendix 2, the U.S. lias recoverable coal reserves
totalling an estimted 291 billion tons.[l] For comparison, coal consumption
in 1989 was only about 900 million tons (equal to about 19 quadrillion
Btu), and the transportation sector used a total of 22.170 quadrillion Btu of
energy from various sources. As can be seen, U.S. coal reserves could
supply domestic transportation energy requirements for several hundred
years at current rates of consumption.
EIA's most recent estimate of coal reserves by rank (bituminous,
subbituminous, anthracite, or lignite) and region is presented in Table 4-
1.[2] This data is based on a demonstrated reserve base (DRB) which does
not account for the accessibility of the reserves. It simply identifies coal in
the ground. As the table shows, the interior of the country has the most
bituminous coal, with an estimated 120 billion short tons. All of the
subbituminious coal is found in the western region, as is most of the lignite.
The Appalachian region has most of the country's anthracite, although this
rank of coal is only a small fraction of the total reserves.
Table 4-1
Coal Reserves By Rank and Region
fmillion short tons)
Region
Bituminous
Appalachian
Interior
Western
Total
96,099.8
120.356.5
24,202.5
240,658.8
Subbituminous
—
...
179,965.5
179,965.5
Lignite
1,083.0
13.989.7
29,674.9
45,113.7
Anthracite
7,186.5
104 1
27.8
7,318.4
Regional Total
104,369.3
134,450.3
233,870.7
473,056.4
Table 4-2 presents the breakdown of the DRB by sulfur content and
rough estimates of the number of oil equivalent barrels (OEB) of fuel to
4-2
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which the coal could be converted.[3] This data illustrates that the DRB is
evenly distributed among classes of sulfur content, with 34 percent
classified as high sulfur, 30 percent as medium, and 33 percent as low.
More than 50 percent of the coal in each type is recoverable. However, the
distribution of each type among regions is uneven, with the majority of low
sulfur coals in the west and the majority of high sulfur coals in the interior
region of the country, which includes the midwest, central west, and gulf
states.
Table 4-2
Breakdown of Demonstrated Reserve Base bv Sulfur Content
Sulfur
Content
Reserves
CBillion ST)
Recoverable
CBillion ST)
OEB*
(Billion^
Distribution
bv Reeion (%)
Low
157
92
186
West
Appalachian
Interior
86
1 4
<1
Medium
147
9 1
184
West
Appalachian
Interior
6
25
1 5
High
164
85
172
West
Appalachian
Interior
7
24
69
""OEI^oil e
quivalent barrels
based on heat
content and
assuming an average
coal-
io-fuel thermal conversion efficiency of 55 percent (based on methane or
methanol).
Estimates of current and future minemouth coal prices and
consumption were presented and discussed in Appendix 2. For the
anlayses performed in this appendix, however, projections of "retail" prices
of coal were needed. For the remainder of this appendix, coal prices quoted
will be EIA's projections of the price of coal delivered to utilities. These
projections are $34.14 per short ton in 2000 and $38.18 per short ton in
2010.[4]
The effect of the acid rain provisions of the Clean Air Act on coal
prices was not included in these estimates. According to ICF Resources,
high sulfur coal production is expected to decline 106-119 million tons as
coal-based utilities' use of high sulfur coal declines.[5,6] Alternative fuel
4-3
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production would provide an obvious market for the displaced high sulfur
coal, because, as will be shown is Section II, these technologies already
include the sulfur recovery units needed to meet the new regulations
Several vehicular alternative fuels can be made from coal. It can be
gasified to a synthesis gas which can then be converted to methane,
alcohols, gasoline, or other intermediates.1 Electricity can be generated
from coal by the conventional coal-fired power plant or by gasification with
combined cycle (steam and gas turbine) power generation. A discussion of
the cost of producing these alternative fuels from coal and the specific
technologies which would be employed is presented for each fuel in Section
II.
B. Biomass
Biomass is defined by most researchers as cellulosic materials of
biological origin (trees, plants, and products made from them). For the
purpose of this report, biomass will be divided into three main categories:
general biomass (wood, agricultural residues, forage crops, processing
wastes, manures, and peat), corn and other grains, and cellulosic materials
used for ethanol production. With the exception of peat, which is
essentially young coal, these feedstocks are renewable, since they are
produced annually. Wood biomass, which is defined to include logging
wastes, excess growth, and annual mortality, is the most readily available
biomass feedstock. Agricultural residues include all the stems, leaves,
stalks, etc., left over from harvesting agricultural products. This feedstock
is the second most plentiful source of biomass for alternative fuel
production. Forage crops are grasses and legumes grown as food for
animals. If biomass is used widely for fuel production, these could be
grown annually as energy crops. Processing wastes are the shells, hulls,
etc., left over from food processing, available daily from the food industry.
Manures are defined to include only the waste of confined animals, such as
cows on dairy farms. Availability of general biomass will be discussed in
Section 1. Section 2 will address corn availability and Section 3 will
address the availability of cellulosic feedstocks specific to ethanol
production.
Researchers disagree on the subject of whether or not municipal
waste qualifies as a biomass feedstock. For the purpose of this report, it is
not included in the definition of biomass. However, municipal waste is
treated as a unique feedstock for alternative fuel production in Section C.
^he production of synthetic petroleum from coal was not evaluated in this report.
4-4
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1. General Biomass
Table 4-3 presents the range of biomass availability predictions
found in the studies reviewed, and the average value reported for each
type.[7-16] The table shows that wood and wood residues are the most
plentiful biomass feedstock, with 360 million tons per year on average
available (about 1,120 thousand OEB per day on an energy basis). Forage
crops and agricultural residues are the other major types of biomass with
large quantities available for alternative fuel production. As the table
shows, there is a wide range in the predictions of biomass availability.
Some of this may be due improvements that have occurred in the various
industries over the 10-15 years since the reports were written, which may
affect current production rates, and hence, future production estimates.
However, there appears to be general agreement that the most widely used
biomass feedstocks will be wood from silvicultural farms or energy crops.
More than half of the projected production is covered by these two types of
biomass.
Table 4-3
Biomass Availability
Million Tons per Year OEB per day
Range of Estimates Average (thousands)*
Total Biomass
300-2.000
866
2,640
By Type:
Wood and Wood Residues**
200-940
360
1.120
Agricultural Residues
53-390
160
500
Forage Crops
0-333
211
660
Manures
9-237
95
300
Processing Wastes
7-44
20
60
Peat
(Reserves, billion tons)***
13-120
...
-- -
* Assuming 15 million Btu per dry ton biomass and a conversion efficiency of 40 percent
** Approximately 142 million short tons of wood and wood products were used for energy
production in 1987.[17]
***This estimate of total peat in the U.S. does not reflect that which is recoverable; actual amount
recoverable is probably less.
Some variation occurs among estimates of biomass availability
because it is difficult to evaluate the secondary effects of using biomass as
a fuel feedstock instead of maintaining its current use. For example, the
numbers for agricultural residue availability vary because researchers
4-5
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disagree about- how many residues must be left in the field to maintain soil
quality. In addition, recovery of crop residues is expensive because it is a
labor-intensive process. Therefore, determining a realistic amount available
for fuel production requires weighing the cost of labor, fertilizers, and lost
field productivity against the amount of fuel that could be produced using
these residues. Similarly, logging wastes and mill residues are often used
on site for energy production (e.g. electricity or steam generation); use of
these wastes for fuel production could add to the burden on other energy
sources (such as coal or natural gas).
The estimate of total peat available in the U.S. covers such a large
range (13-120 billion tons) because the amount of peat recoverable for
energy production is unknown. The potential for peat as a biomass
feedstock is quite low, since it is a very inefficient source of energy. For
example, production of 4,400 barrels of methanol per day (equivalent to
roughly 2,200 barrels of gasoline per day) would require collecting peat
from an area of 23 square miles.[7] The chances that such a large,
untouched area of land exists in the Midwest and South, where peat
reserves are predominantly found, and can be "mined" without severely
disrupting the people or ecology of the area, are slim.
Cellulosic sources for ethanol production include biomass waste from
non-energy producing processes as well as from plants grown specifically
for fuel production. These plants can be grown by conventional farming
and forestry methods or by short rotation intensive culture (SRIC).
Commercial short rotation tree planting is already done in the U.S. for both
raw material and fuel.[27]
With corn (discussed in Section 2), the starch is easily converted to
sugar and then fermented to ethanol. However, cellulosic feedstocks are
not as easily converted. Cellulosic materials contain three parts—the
celluose, hemicellulose, and lignin-and each must be handled differently.
The cellulose and hemicellulose portions require additional processing
before they are able to be fermented (the lignin is processed to a non-
ethanol fuel). For instance, the cellulose is difficult to break down to a 6-
carbon sugar, but once there, is easy to ferment. The hemicellulose can be
easily converted to a 5-carbon sugar, xylose, but this sugar is not easy to
ferment to ethanol.
The advantages of cellulosics over corn are that they are plentiful,
easy to grow, and have higher ethanol yields per acre.[28] According to
DOE, these woody and herbaceous crops "can be genetically improved to
optimize energy conversion qualities and increase yields even on marginal
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land." SRIC woody crops are hardwood trees which grow fast (2-8 years
versus 30-60 conventionally), regenerate from stumps, and even grow on
marginal land. Poplar and sycamore are two heavily studied species.
Herbaceous crops include forage crops, grasses, and legumes. Some of
these can be harvested three times a year.[28 ] The variety of cellulosics
cushions the shock of a bad season for one species or one part of the
country. Cellulosics could be grown in areas outside of the Corn Belt which
may reduce ethanol transportation costs and encourage nationwide use.
The technology for processing cellulosics is still developing. Genetic
improvements, physiological study and large scale production are areas of
study. Currently, yields of 6 dry tons per acre are obtained with woody
crops, with a goal of 10 dry tons per acre. DOE estimates that 150 million
acres will be available by 2010 for growth of energy crops. Other sources
estimate that 10 quads per year of ethanol (one quad is approximately 13
billion gallons of ethanol) are currently obtainable from
lignocellulosics.[29,25] This is about two-thirds of U.S. annual
transportation fuel usage, and does not include dedicated production of
energy crops. Other energy uses compete for these renewable resources,
however, and not all SRIC crops will be used as ethanol feedstocks. It is
estimated that substantial quantities of ethanol from lignocellulosics will
not be available until after 2000 or possibly 2020.[23,30]
Research continues in several areas of cellulosic feedstock production
and conversion, including research to 1) find ways to increase yields from
the total feedstock biomass as well as the yields in each conversion step, 2)
increase ethanol concentration, and 3) decrease catalyst cost. It appears
that large scale ethanol production from cellulosics has the potential to
compete with conventional gasoline at equivalent consumption levels,
indicating that flexible-fueled vehicle and neat alcohol-fueled vehicle use
have the potential to significantly reduce our dependence on petroleum
fuels as well as provide air quality benefits.
Technology exists for converting many biomass feedstocks into useful
energy. Most current uses for biomass in energy production involve
combustion of wood and wood refuse to provide residential heat, industrial
heat and steam, and electricity. About 142 million short tons of wood and
wood products were used for this purpose in 1987.[17] However, declining
natural gas prices have limited the use of wood for this purpose. Current
research centers on conversion of biomass to methanol, ethanol, and natural
gas, as well as the use of biomass for electricity production.
4-7
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The location of the major supplies of each type of biomass vanes and
can have a significant effect on the use of that biomass as a feedstock. The
major concentrations of wood and wood residues are found in the heavily
forested areas of the Northwest, Northeast, and deep South. Most
agricultural residues and potential locations for energy crops are in the
Midwest and Plains states. The fact that these locales tend to be a distance
from the major metropolitan centers may affect the economics of using
biomass as a feedstock.
The feedstock cost of biomass products includes the cost of producing,
collecting, and transporting the product. In addition, for some "green" or
"wet" feedstocks such as forage crops or excess forestry growth, the price
may include the cost of drying the material. (Occasionally, this cost is
included in the conversion plant's capital investment if the design often
incorporates drying and processing equipment.) Because all of these factors
affect the price of biomass, some variability exists among the feedstock cost
estimates cited in the literature. Table 4-4 presents the range of estimates
for the delivered, oven dried feedstock price.[ 12,14]
Table 4-4
BIOMASS FEEDSTOCK COST - DELIVERED
Feedstock Dollars per Million Btu*
Wood and Wood Residues
Logging Residues
2.12-6.24
Lumber Mill Waste
0.66-2.30
Standing
1 39-2.42
Agricultural Residues
General
1.51-6.67
Field Corn Wastes
3.75-5.70
Wheat
1.33-2.61
Manures
Poultry
2.60-3.58
Beef
0.48-0.97
Processing Wastes
Cotton Gin Trash
0.16-0.33
Bagasse (Sugar Cane)
0.33-3.27
Forage Crops
Grass
6.54
^Adapted from References 10,12. A conversion of 15 million Btu per dry ton was
used when costs were reported on a weight instead of an energy basis.
4-8
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In general, wood residues are estimated to cost anywhere from SO.66
to $6.24 per million Btu ($11 to $106 per dry ton); DOE uses a price of
$2.50/MMBtu ($42 per ton).[18] Agricultural residues are predicted to cost
S22-S110 per ton, with wheat residues less costly than corn. Manures and
processing wastes are less expensive feedstocks, but as Table 4-3 shows,
their availability may be limited. Forage crops are the most expensive
biomass feedstock, due to the low energy content per harvested ton
resulting from the high moisture content. No reference to the cost of peat
recovered in large quantities were found.
Future price predictions for many biomass feedstocks are not
available in the literature. The price of some types of biomass are not
likely to increase over current values, because of the limited demand.
However, demand for wood and wood products, the most probable biomass
feedstock because of its great availability, may increase. In addition, the
use of these products for energy production by industries such as the
lumber industry could increase if costs of other energy sources, such as coal
and natural gas, rise. DOE projects that the cost of wood used as an energy
feedstock will decrease (due to improvements in yield) to $2/MMBtu
(about $33.60 per ton) by 2000.[30] In Section II, the biomass conversion
technologies and costs will be discussed for production of methanol,
ethanol, CNG, and electricity.
2. Corn
Approximately 900 million gallons of ethanol were produced in 1989
out of a potential capacity of about one billion gallons. As of mid-1989,
about 95 percent of the ethanol had been made from corn, which when
extended to year-end would represent about 4.4 percent of the total U.S.
corn production.[19,20] The remainder of the ethanol was made from other
grains and/or food processing wastes.[21] This small fraction is primarily
produced in small plants which are profitable due to ideal location or
situation. Corn is expected to be the dominant feedstock, however, for the
next 10-20 years; thus, this section will focus on the future availability of
corn as an ethanol feedstock.
For the volumes of ethanol required by the scenarios of this report,
the corresponding bushels of corn required (assuming 100 percent of the
ethanol is produced from corn) are shown in Table 4-5. This assumes a
yield of 2.54 gallons of ethanol per bushel (bu) of corn, a figure which
represents the 60 percent of the ethanol that is produced in wet mills at a
yield of 2.5 gal/bu and the 40 percent produced in dry mills at a yield of
2.6 gal/bu.
4-9
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To put the amount of corn required into perspective, current
production and use, end stocks, and total acreage should be considered.
Total production of corn harvested for grain since 1983 has ranged from 7-
9 billion bushels, with the exception of drought years 1983 and 1988 when
total production was 4.2 and 4.9 billion bushels, respectively. This includes
an estimated production of 7600 million bushels in 1989.[20] End stocks in
the high yield years of 1985-87 (about 119 bu/acre) were 4000-5000
million bushels. In the drought years of 1983 and 1988 (yields were about
81 and 84 bu/acre), end stocks were 1 and 2 billion bushels. For
immediate post-drought year 1984 (yield 106 bu/acre) end stocks were
over 1600 and for post-drought year 1989 (yield about 116 bu/acre) are
expected to be about 1900 million bushels. Yields are as reported for
(grain) harvested acreage and do not include the small fraction of
abandoned land which would have been harvested if it were
productive.[20,22] This adjustment will have only a minor affect on
availability; it is more fully discussed in Appendix 7 with regard to corn
farming and C02 emissions.
Table 4-5
Corn Requirements Under Increased Ethanol Demand Scenarios
Ethanol
Corn
volume
Required
Year
bil. pal.
billion bu.
Scenario
1
2000
2.96
1.2
2010
6.79
2.7
Scenario
2a
2000
3.11
1.2
2010
6.99
2.8
Scenario
2b
2000
3.35
1.3
2010
7.12
2.8
Scenario
3
2000
8.53
3.4
2010
18.10
7.1
From the above information, it can be seen that the corn required in
the year 2000 for Scenarios 1 and 2 could come from current end stocks,
even in poor yield years. In good years, possibly even the requirements ot
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the year 2010 and the year 2000 requirements of Scenario 3 could be met.
Of course, this" would seriously deplete stocks, and thus, it is unlikely that
all the com required would come from stocks, even if the demand
theoretically could be covered by the end stocks. The year 2010 Scenario 3
requirement of 7.1 billion bushels is almost equivalent to total annual corn
production. This need clearly could not be met without additional corn
acreage, and more likely would be met through the use of other feedstocks.
From 1983-89 total available corn acreage ranged from 82.4-92.4
million acres. However, in this same time frame, planted acreage ranged
from 60.2-83.4 million acres, or 65-95 percent of total acreage. By the
1985 Food Security Act, the Department of Agriculture (DoA) is required to
manage production of agriculture commodities, which includes requiring
reductions in planted acreage if it is determined that total supplies of these
crops (including corn) will be excessive (which would reduce crop market
prices).[19] Lower crop prices increase cost to the government because of
deficiency payments to farmers and other agricultural support programs.
Because of this, not all available acreage is planted every year.
Thus, the potential for increasing the available com supply may exist
through the use of set aside land. Although this land may not be as
productive as planted land, at some point, at least 93-95 percent of it has
been utilized (1984 and 1985), and yields were about 106 and 118
bu/acre, definitely not low yields. An estimate of potential corn
availability through use of set aside land can be obtained by first averaging
the extremes of the total available corn acreage (to get 87 million acres),
then averaging the extremes of the planted acreage (to get 72 million acres)
and taking 90 percent of this value (typically about 10 percent of all
planted acreage is a combination of silage and abandoned land) which
results in about 65 million acres available for harvest. This assumes that
corn acreage planted for silage will not increase with an increased ethanol
program and that all of the set-aside acreage is successfully harvested.
Total corn acreage available for grain harvest is then 87-72+65, or 80
million acres. From 1983-1989 (estimated) corn yields have increased an
average of about 2.2 percent per year. Assuming yields continue to
increase at 2.2 percent, yield in 2000 will be about 146 bu/acre, and in
2010, 181 bu/acre. These yields taken with the available acreage could
result in total harvests of 11680 and 14480 million bushels in 2000 and
2010.
From the total corn available, nonethanol corn use must be
subtracted. Total corn use ranged from 6500-7700 million bushels from
1983-89. This includes corn used for animal feed and residual uses,
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domestic use. (food, industrial, seeds, ethanol), and exports. Feed and
residual use has had an average annual increase of about 1.3 percent over
this time period, although according to Keim, feed use may decline due to
the decline in red meat consumption.[23] Domestic use r*her than ethanol
has been increasing at an average of about 2.6 percent per year. Exports
have increased an average of 3.3 percent per year. However, with an
increased ethanol program, com prices will increase which will tend to
reduce exports. Assuming that feed and residual uses and exports remain
at 1989 levels (4200 and 2150 million bushels) and that nonethanol
domestic use continues to increase at 2.6 percent, total nonethanol demand
for corn will be 7520 and 7750 million bushels in 2000 and 2010.
Subtracting total nonethanol corn use from total corn available results in
4160 and 6730 million bushels available for ethanol production (10.6 and
17.1 billion gallons) which would more than satisfy the corn requirements
of Scenarios I and II, and year 2000 of Scenario 3. Additional ethanol
production to fulfill the required volume of year 2010 of Scenario 3 would
require conversion of other acreage to corn (from crops or other acreage
not currently intended for corn production) and/or the use of other
feedstocks such as cellulosic material. According to DoA (1988), maximum
potential additional ethanol capacity (either by add-ons, revamps, or new
construction) is about 5800 million gallons, and could easily be 1-2 billion
less.[24] Thus, although com is not a limiting factor (except for Scenario
III), for an ethanol program greater than about 4 billion gallons (including
current capacity) the ability to process that corn may be limited.
Several analyses have estimated that a program of increased fuel
ethanol consumption to the 3 billion gallon level could be supplied and
technologically handled by the year 2000. The GAO, for instance, estimated
that 2.2 to 3.3 billion gallons of ethanol could be produced in 1997. This
estimate was determined by a model which considered many interrelated
agriculture and economic factors. Assumptions included slight increases in
domestic and export com demand. Potential total available acreage was not
considered, rather some was left as part of the Acreage Reduction Program.
The GAO did note that the ethanol industry relies on federal incentives to
remain competitive with gasoline, and that construction of the necessary
ethanol plants will be based on economic and other factors, including the
extension of current incentives.[19]
Keim predicted that similar amounts of corn could be made available
in the year 2000, although he did not address the availability of processing
capacity.[21] His assumptions include about a 2 percent per year decline in
exports, 4 percent increase in non-ethanol domestic use, and no change in
feed and residual use. Set aside acreage was included as available for
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planting, and yield was 141 bu/acre, slightly lower than the 146 value used
above (he assuirted a 1.6 percent per year increase in yield). The total corn
available then was about 11300 million bushels. The non-ethanol demand
in 2000 was 7300 million bushels, slightly lower than the 7523 used above.
Based on the above information, the ethanol needs of the scenarios
(with one exception) can theoretically potentially be met. Changes in the
assumed nonethanol uses of corn or in the crop yield increases could
significantly affect the amount of corn available for ethanol. Other
economic and political factors can also affect corn availability. Additionally,
the DoA and others have said that a large scale ethanol program would
raise corn prices so high as to make the cost of ethanol used as fuel
prohibitive compared to other fuels.[25,26] Ethanol production will be
discussed in greater detail in Section II.
C Municipal Waste
Municipal waste, the refuse collected from residential, commercial,
and industrial sources that is usually disposed of in landfills or incinerators,
has promising potential as an alternative fuel feedstock for regional
production of fuels. Although the composition of municipal waste varies
with the source, its highly organic content makes it an attractive fuel
feedstock. However, some concerns exist because of the highly
heterogenous nature of this material. In addition, the highly decentralized
nature of this feedstock raises concerns about large scale conversion of
municipal waste.
When researchers speak of municipal waste as an alternative fuel
feedstock, they are usually referring to municipal solid waste (MSW) as
opposed to municipal liquid waste (MLW). Although MLW does not have
much use as an energy resource, the sewage sludge, or organic solids,
contained in it can be used to produce a small amount of methane. In fact,
this is currently done in some sewage treatment plants to provide internal
heating.[ 14] However, the potential for MLW as an energy feedstock is
very limited. This report will only consider municipal solid waste (MSW).
Projections of how much MSW is generated in the U.S. vary from year
to year, but the general trend is an increase due to the growing population.
In the period from 1978-1980, estimates of MSW generation ranged from
100 to 130 million tons per year.[10,14,15] By 1988, the estimate had
more than doubled to 240 million tons of solid waste produced per year in
the U.S.[31] The Solar Energy Research Institute's (SERI) current estimate
of MSW generation is 160-200 million tons per year.[32] Approximately 52
4-13
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percent of the total composition of MSW is cellulosic.[31 ] At the current
rate of waste generation, about 80-100 million tons of material from MSW
per year could be converted to alternative fuels. With an approximate heat
content of 10 million Btu per ton, this supply could be converted to about
160-220 thousand oil equivalent barrels (OEB) of energy per day, assuming
a conversion efficiency of 40 percent and 330 days of operation.
Future availability of MSW can be estimated based on the growth rate
over the last 10 years. Between 1980 and 1990, annual production of
waste in this country increased 16 percent per year. Applying this rate of
increase to the current rate of production (160-200 million tons per year)
yields estimates of 256 million tons per year by 2000 and 410 million tons
per year by 2010. These rates of waste generation would provide enough
MSW to produce alternative fuels under either fuel penetration Scenario 1
or 2, for both years considered. Of course, this statement is valid only if it
is assumed that all waste generated in this country is used as a feedstock,
and that none of the cellulosic components of the waste, such as paper or
wood, are recycled or reused. Since waste collection is decentralized
throughout the country, these estimates of fuel production capability will
only be realized if municipalities and industry worked together to produce
fuel in locations near major sources of MSW, and if conversion technologies
are developed that make efficient use of the "unrecycleables" as well are
the recycleablve components.
Estimating the cost of MSW as a fuel feedstock is difficult since the
only use for it currently is for generation of electricity or heat as part of a
municipal or industrial waste disposal system. However, when cost
estimates are made for processes which use MSW, the feedstock cost for the
MSW is usually charged as a credit, since use of the waste instead of
disposal is desirable to help ease the strain on landfills. The feedstock
credit equals the value of the "tipping fee" that would have been charged to
the collection company for dumping the load of refuse at the local landfill.
Tipping fees vary regionally and by ownership, private or municipal. A
privately owned landfill on the East coast may charge $25-$120 per ton of
garbage, while a municipally owned landfill in the South may only charge
$10-$ 12 per ton.[33]
Projections of future MSW prices depend greatly on assumptions
made regarding how much tipping fees will increase as landfills become
even more crowded and municipalities search for ways to dispose of their
waste. Past trends indicate that tipping fees have risen about 22 percent
per year over the last 10 years; however, it is doubtful that this trend will
continue. Many issues affect the tipping fee charged for waste, including
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capital and operating costs, political considerations (studies on where to site
the landfill, who will fund the construction, what are alternatives, etc.), and
environmental concerns; it is difficult to determine what effect each of
these issues will have on the tipping fee. In addition, because of the
regional variability of landfill costs, it is difficult to project a national
average fee. The current national average tipping fee is about $28 per ton
of waste.[34] EPA has projected that upcoming landfill regulations will add
an additional $5 per ton to the average tipping fee. Adding this to the
current average yields a net tipping fee of $33 per ton of waste; this value
was used for the economic analyses in this chapter. The average tipping
fee could increase due to new regulations and as landfills continue to
become overcrowded, but these issues need further study before the
effects of these changes can be quantified; future versions of this report
will attempt to address this issue in greater detail.
Because of the heterogeneous nature of MSW and because it contains
a large amount of moisture, the waste must be processed before it is used
as a feedstock. The MSW is separated to remove glass, metals, and other
undesirable components that can cause the formation of slags or inhibit
conversion to the desired fuel. Often these materials can be sold for
recycling, but since the market for these materials is unpredictable, this
potential income is not usually included when determining the price of the
fuel produced. The remaining dried waste is called "fluff refuse-derived
fuel" (fRDF). The fRDF can be further processed into a denser form such as
pellets ("dense RDF" or dRDF), which are a more efficient means to store and
use the energy content of the waste.[31] The current production cost for
fRDF is estimated by DOE to be $2.50 per million Btu, which includes a
feedstock credit (the tipping fee) of about $4.00 per million Btu ($40 per
ton); with further development of the technology the price may drop to
$1.70 per MMBtu.[31,106] The selling price for these pellets is tied to the
price of coal, since coal is the closest competitor to MSW pellets as a
feedstock for fuel production or electricity generation. Infrasystems, a
company which has designed a MSW-to-methanol process, estimates a
competitive market value to be $25 per ton of dRDF, or about $2.50 per
MMBtu.[33]
Based on DOE's estimate of the cost of producing RDF with a tipping
fee of $40 per ton, a cost of $3.50 per MMBtu for RDF was estimated for the
projected future average tipping fee of $33 per ton of waste. This value is
used for the feedstock cost of fuels derived from municipal waste in later
sections of this report. Obviously, for a higher tipping fee, the cost of
producing RDF decreases (and subsequently, the cost of an alternative fuel
produced from the RDF would decrease) since the tipping fee is a credit, not
4-15
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a cost, to the process. For a tipping fee of $50 per ton, RDF is estimated to
cost $1.07 per MMBtu; at $75 per ton, RDF would cost -$2.50 per MMBtu to
produce. The specific technologies for conversion of MSW and the
production costs involved will be discussed for methanol, CNG, and
municipal waste in Section II.
D. Natural Gas
Natural gas is composed primarily of methane (CH4), with a small
fraction consisting of other gases, including higher hydrocarbons; the exact
composition varies with individual gas fields. For the purpose of this
report, natural gas was classified as either conventional or nonconventional.
Conventional sources of natural gas include natural gas which is produced
from gas wells (nonassociated) and that which is produced in association
with oil from oil wells. Nonconventional natural gas sources include natural
gas from oil shale, methane hydrates, m-situ coal gasification, and methane
from landfills. A discussion of both conventional and nonconventional
natural gas sources and feedstock costs ts presented below.[1,35,36]
1. Natural Gas from Conventional Sources
a. Domestic Natural Gas (Lower-48')
In 1989, global conventional natural gas reserves were estimated to
be about 3,900 trillion cubic feet (tcf), while the United States reserves
totalled approximately 168 tcf (equivalent in energy to approximately 33
billion barrels of oil).[37]2 As discussed in Appendix 2, forty percent of
total world reserves are located in OPEC countries. In the U.S., Texas and
Louisiana (including Federal offshore areas) are the largest reserve holding
states, accounting for nearly one half of the Lower-48 total. The largest
reserve holding states are presented in Table 4-6.
Domestic natural gas is currently used in the residential, commercial,
industrial, and electrical sectors, primarily for heating and power
generation. Any alternative fuel made from domestic natural gas feedstock
would have to compete for natural gas with these sectors. Presently,
domestic production of natural gas is about 17.3 tcf/year, and consumption
amounts to roughly 18.7 tcf/year (imports make up the difference). If
domestic natural gas is used as an alternative fuel feedstock, domestic
reserves could be depleted quickly. If, however, significant new
discoveries of gas are made, domestic gas supplies could be used to fuel a
2For comparison, U.S. petrolem reserves are estimated at 27 bilion barrels.
4-16
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significant portion of the U.S. automobile population. DOE's cost estimates
for domestic natural gas, $3.14/MMBtu in 2000 and $5.47/MMBtu in 2010
(as presented in Appendix 2), were used in the economic analysis of natural
gas-based transportation options that follows in Section II.
Table 4-6
Largest Natural Gas Reserve Holding States in the U.S.
State Reserves ftcf)
Texas 45.4
Louisiana 35.7
New Mexico 17.2
Oklahoma 16.5
Wyoming 10.3
Kansas 10.1
b. Imported Natural Gas
The U.S. currently imports significant quantities of natural gas, and is
expected to increase imports in the future. The main source of imports
historically, and in the foreseeable future, is Canada. The majority of these
imports flow via pipeline between the two countries. In 1987, the U.S.
received almost 1 tcf of Canadian gas imports, and in 1988, 1.3 tcf.
Canadian imports are expected to increase to approximately 2 tcf by 2000.
Existing pipeline capacity across the U.S. border would accomodate flows of
approximately 1.7 tcf.
The U.S. is also expected to increase imports of liquefied natural gas
(LNG) in the future. Currently, the U.S. only imports LNG from Algeria. The
high costs of liquefaction and regasification is one prohibitive factor to
increasing imports of LNG. As domestic natural gas prices continue to rise,
however, imported LNG will become increasingly competitive. EIA projects
that in the year 2000, LNG imports will reach 0.3 tcf.[38] Since forecasts
indicate that imports of LNG will be necessary on the margin, it is quite
likely that any substantial increase in use of natural gas in the
transportation sector will be based on foreign natural gas.
The costs of foreign natural gas were taken from a recent analysis
performed by the Department of Energy (costs were escalated to 1989
4-17
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dollars).[39p The costs are categorized according to four different site
classifications, ranging from sites with well developed infrastructure in an
established industrial environment (Site I) to sites with a relatively low
degree of established infrastructure (Site IV). Note that the Site I costs are
equivalent to the cost of domestic gas presented in the previous section,
since most Site I locations are able to transport the gas by pipeline instead
of liquefying the gas for transportation by ship or other means. Projected
future natural gas costs for these site categories are shown in Table 4-7.
Table 4-7
Future Natural Gas Feedstock Costs at Various Locationsf391
Cost of Natural Gas Feedstock (1989S/MMBtu1 Example Country
Category 2000 2010 Location
II 1.67 2.61 (II/III): Saudi
Arabia, Mexico,
Venezuela
III 1.04 1.57 Nigeria, Thailand,
Chile
IV 0.78 1.15 North Slope Alaska,
Offshore Malaysia
c. Alaskan Natural Gas
In Alaska, vast quantities of natural gas are coproduced with Alaskan
oil and are currently reinjected into the oil reservoirs at some cost.
Approximately 2 billion cubic feet (bcf) per day of gas could be drawn from
North Slope reservoirs, equivalent in energy to about 0.4 million barrels of
gasoline per day.[40] The price at which this gas could be supplied as
feedstock for alternative transportation fuel production would be minimal,
since no alternative market for the gas currently exists. Jensen and
Associates, Inc., estimated the cost to be $0.33/MMBtu in 1987, holding at
that level through 2000, and increasing to $0.51-2.33/MMBtu by
3 DOE is currently updating their estimates of natural gas costs for various foreign
locations. In addition, other organizations have performed analyses to project the
cost of foreign natural gas; some of the projections differ from those presented here.
4-18
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L0 10.4[41 ] Costs for Alaskan gas (in last quarter 1987 dollars) of
>0.50/MMBtu in 1989, $0.75/MMBtu in 2000, and $1.10/MMBtu in 2010
yere estimated by DOE (Site IV).[42] Considering that the current cost of
jas reinjection would be displaced, the real costs of the gas might be even
ower.
Enough Alaskan natural gas is projected to be available to supply the
ZNG required under Scenario 1 or Scenario 2; enough methanol could be
nade for the year 2000 under either of these scenarios. Although the
ibundance of low cost natural gas makes the North Slope an attractive fuel
Production site, several difficulties associated with its Artie climate tend to
nake the economics less favorable than other potential plant sites. This is
liscussed in further detail in Section II where fuel production economics
ire considered.
d. Vented and Flared Natural Gas
Another potential source of natural gas for alternative fuel production
s gas which is vented or flared as a byproduct of oil production. Presently,
i vast quantity of associated gas is either vented or flared, resulting in
jnergy waste as well as emissions of carbon dioxide and methane (both of
vhich are greenhouse gases as will be discussed in Appendix 7). As Table
1-8 shows, the quantity of natural gas vented and flared gas currently
otals nearly 3 tcf per year, or 1.4 million barrels per day oil equivalent.! 1]
>ince production of this gas is dependent on oil production, the supply can
>e variable, adding risk to any potential investment. However, in most
:ases it would be possible to supplement vented and flared gas with gas
[rom conventional sources, thus eliminating the risk of supply
nterruptions.
Of course, some of this gas is geographically disperse and would be
lifficult or impractical to collect and market. However, several countries,
ncluding Nigeria, Algeria, and others, currently vent and flare gas in
[uantities sufficient to make collection of the gas economical. ICF
Resources, Inc. recently completed a study of vented and flared gas
The wide range of costs presented for 2010 reflect different assumptions by the
luthor with respect to crude oil price and market development. At a 2010 crude oil
irice of $35.00/bbl (close to the $36.90/bbl presented in Chapter 2), the $2.33/MMBtu
;as price is projected by Jensen. If new markets for the gas do not develop, however,
ir if oil prices do not increase substantially over time, a price nearer to $0 33/MMBtu
hay prevail through 2010 and beyond.
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Table 4-8
Vented and flared Gas Availability
Vented
flared*
Region (ocJ)
Country 1987
NORTH AMERICA
Canada 93
lexicc 75
Jnited States 124
Total 292
CENTRAL ANO SOUTH AMERICA
Argentina 93
3olivia 6
Brazil. 37
Chile. 3
Columbia. is
Equador NA
Trinidad and Tobago L2J
Venezuela. 130
other.. 23
Total 439
WESTERN EUROPE
Denmark MA
France. MA
Germany, West 7
Italy MA
Motherlands MA
Morvay 12
United Kingdom 75
Other II
Total 94
EASTERN EUROPE ANO USSR
Germany . East. MA
Hungary .... HA
Poland. . MA
Romania 28
U.S.S.R 321
Other MA
Total 3*9
Ml DOLE EAST
Bahrain MA
Iran 170
Iraq MA
Kuwait 23
Oman 11
Qatar. .... NA
Saudi Arabia..... 71
United Arab Qnirates. 82
Other 198
Total 554
AFRICA
Algeria ... 222
Cameroon MA
Egypt 18
Libya 28
Nigeria 417
Tunisia.... MA
Other 142
Total 827
FAR EAST ANO OCEANIA
Afghanistan. .... 6
Australia MA
Brunei 11
China MA
India 127
Indonesia 131
Japan 2
Malaysia 26
N&v Zealand MA
Pakistan 30
Thailand NA
Other J
Total 333
WORLD TOTAL 2,889
From Energy Information Administration, International
Energy Annual, 1988.
Assuming a 65 percent natural gas-to-methanol conversion
efficiency.
Less than one-half the unit of measure.
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collection costs, concluding that nearly 0.5-1 tcf of gas could be collected at
a cost of $i;00/MMBtu or less (enough to produce enough natural gas or
methanol to supply demand under Scenarios 1 and 2 presented in
Appendix 3).5 [43] The results of the ICF study are presented in Table 4-9.
2. Natural Gas from Nonconventional Sources
Nonconventional natural gas sources include natural gas from oil
shale, methane hydrates, and in-situ coal gasification (technically, natural
gas derived from biomass, coal, and municipal waste would also be included
under this definition, but in this report are discussed elsewhere). Oil shale
is a fine-grained sedimentary rock which contains an organic material
known as kerogen, which when heated decomposes to yield oil, gas, and
residual carbon. Methane hydrates are solid, ice-like compounds in which,
under certain conditions of temperature and pressure, gas molecules are
entrapped and bound with water molecules in a crystalline structure. In-
situ coal gasification is the recovery of energy in the form of methane from
coal deposits which are not mineable with conventional mining techniques.
Oil shale resources exist in both the eastern and western U.S.[44] In
the western states (primarily Colorado, Utah, and Wyoming), resources are
estimated at between 420-1230 billion barrels oil equivalent in shales up
to a depth of 20,000 feet which contain over 30 gallons of oil per ton. In
the eastern states (primarily Alabama, Indiana, Kentucky, Michigan, Ohio,
West Virginia, and Tennessee), resources are estimated at between 400-
2600 billion barrels oil equivalent. The estimates are dependent on the
grade of shale included and the recovery method used. Estimates of
natural gas from methane hydrates are 6.7 million tcf in the U.S. and 270
million tcf worldwide (estimates are inferred based on theoretical
knowledge about the conditions favorable for hydrate formation and the
confirmed existence of hydrates in a number of locations).
Due to the fairly new interest in the collection of methane from
coalbeds, there are not accurate estimates of the amount of this resource.
One estimate is that approximately 50 trillion cubic feet of coalbed methane
is recoverable with existing technology.
At present, it is not economical to collect nonconventional natural gas
as feedstock for the production of alternative fuels. However, as the price
5While the cost of collection might be lower in some locations, a conservative estimate
of vented and flared gas collection costs of $1.00/MMBtu was used throughout the
analysis.
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Table 4-9
Vented and Flared Gas Collection Costs
Cost
First-
¦Year BCF
20th-
-Year BCF
Country
Cluster
/Mcf
Each Cumulative
Each Cumulative
Iraq
Basra
SO.34
48.1
48.1
21.6
21.6
Nigeria
South
SO.41
285.4
333.5
128.2
149.8
Nigeria
North
SO.47
206.8
540.3
92.9
242.8
Trinidad
All
$0.50
115.0
655.3
51.7
294.4
Iraq
Kirkuk
$0.67
56.0
711.3
25.2
319.6
Algeria
Timmimoun
$0.75
127.4
838.7
37.2
376 .8
India
N. Bombay High
$0.84
35.1
873.7
15.8
392.6
Iraq
Mosul
$0.86
48.0
921.7
21.6
414.2
Algeria
Hassi Messaud
$0.97
11.1
932.9
5.0
419.2
Algeria
Rhourde Area
$0.97
13.0
945.8
5.8
425.0
Algeria
Mazoula
$0.97
12.4
958.2
5.6
430.6
Algeria
SW. In Amenas
$0.97
12.4
970.6
5.6
436.1
Algeria
NW. In Amenas
$0.97
11.7
982.3
5.3
441.4
Algeria
S. In Amenas
$0.97
11.1
993.5
5.0
446.4
Venezuela
West
$1.02
94.7
1088.1
42.5
488.9
Iran
Ramhormoz
$1.17
71.2
1159.3
32.0
520.9
UAE
East
$1.25
43.3
1202.7
19.5
540.4
India
S. Bombay High
$1.40
35.0
1237.7
15.7
556.1
Argentina
All
$1.99
86.2
1416.1
38.7
636. 3
Venezuela
East
$1.99
23.1
1439.2
10.4
646.7
Iran
Kangan
$2.13
30.0
1469.2
13.5
660.1
Indonesia
NW. Sumatra
$2.21
44.7
1513.9
20.1
680.2
Indonesia
SE. Sumatra
$3.16
43.0
1556.9
19.3
699.6
Indonesia
Java
$3.32
38.5
1595.5
17.3
716.9
Libya
All
$4.51
28.4
1623.9
12.8
729.7
Malaysia
Malaya
$4.77
14.2
1638.1
6.4
736.1
Malaysia
Sarawak
$5.84
9.9
1648.0
4.4
740.5
-------
of conventional sources continues to rise, nonconventional sources may
become more- competitive in the future. At present, some of these natural
gas sources are recoverable at prices between $2.90 and $4.85/MMBtu at
the wellhead. It is estimated that nearly 2200 million barrels oil
equivalent of coalbed methane are recoverable at between 52.90 and
$4.85/MMBtu, and about 2600 million barrels oil equivalent natural gas
from oil shale are recoverable at the same price.
When these prices are compared to the conventional natural gas
wellhead prices projected by DOE (as presented in Appendix 2), it appears
that gas from nonconventional sources could be competitive between 2000
and 2010. Given that the environmental impacts of nonconventional gas
use should not be significantly different than those of conventional gas use,
and since the future prices of domestic resources and nonconventional gas
are similar, the heading "domestic natural gas" will be used throughout the
remainder of this report to describe gas from either source.
Alternative transportation fuels which can be derived from natural
gas include CNG, methanol, and electricity. In addition, another alternative
fuel feedstock, LPG, is a byproduct of natural gas production. The
production technologies and economics for conversion of natural gas to
methanol, and CNG will be discussed in Section II.
E Liquefied Petroleum Gases
Liquefied petroleum gas (LPG) is broadly defined as any gas
containing propane, butane, ethane, propylene and/or butylene. The
United States' domestic supply of LPG comes from two sources: wet gases
stripped during the processing of natural gas and byproduct gases removed
from crude oil during refining. About 70 percent of U.S. LPG comes from
natural gas production, while the remaining 30 percent comes from
refineries. [45,46,47]
The average rate of domestic LPG production in 1989 was 1,791
thousand barrels per day.[48] This production rate supplied about 85
percent of the national demand; the remainder was imported. Offshore gas
fields produce LPG at a rate of about 27 barrels of LPG per million cubic
feet (MMcf) gas recovered.[46] Onshore gas fields typically have less
liquefied gas and hence produce LPG at only one-third this rate, 7-10
barrels/MMcf gas.
The American Gas Association estimates U.S. natural gas liquids
reserves to be 8,238 million barrels (including both LPG and natural
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gasoline).[49] " These reserves are located primarily in the southwest: 2,617
million barrels are in Texas and 1,154 million barrels in Utah and
Wyoming. New Mexico is estimated to have 1,023 million barrels and
Louisiana 517 million. The remaining large reserves are located in Federal
land offshore, with an estimated 622 million barrels of natural gas liquids
located there.
LPG is used in several industries in the U.S. As Table 4-10 shows,
residential and commercial heating uses the most with 35.2 percent of the
market, while automotive use accounts for only 2.8 percent of LPG
sales.[50] Currently, LPG fuels over 1 million vehicles in the U.S.[51] Most
of these are fleets of high mileage vehicles like taxis and buses. Another
common use is for forklifts, because the low emissions of LPG engines
enable them to be used indoors. Outside of this country, Japan and Europe
have many vehicles that run on LPG.
Table 4-10
Sales of LPG in 1987*
Industry Percent of Sales
Residential and
Commercial Heating
35.2
Chemical
39.0
Farm
9.0
Industrial
8.0
Automotive
2.8
Other Engine Fuel
1.7
Utility
1.2
Other
3.1
"¦Adapted from [50]
LPG is also used commonly for agricultural purposes and by the
chemical industry. It is used not only to run farm equipment, but also for
applications such as crop drying.[51] About 50 percent of the farms in
America are dependent on LPG. The chemical industry uses inexpensive
LPG in place of ethane for various applications. If prices increased,
however, the industry would probably move back to the use of ethane,
having switched to LPG only because of its low price in recent years. This
change could release more LPG for other, higher value uses.
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Production of LPG constitutes only a small fraction of natural gas
production and petroleum refining, although over 250 oil and natural gas
companies produce LPG. Hence, it is unlikely to displace petroleum
products if used as an alternative fuel. This makes LPG better suited to
small markets where fuel can be purchased in large quantities or use by
fleets.
DOE (EIA) predicts future LPG supplies of 2.03 million barrels per day
in 2000 and 2.28 million barrels per day in 2010.[4] Given EIA's
predictions regarding future consumption by the residential and industrial
sectors, and assuming that other industries maintain consumption rates,
demand for LPG could be 1.97 million barrels per day in 2000 and 2.20
million barrels per day in 2010. Therefore, a maximum of 0.06 million
barrels per day in 2000 and 0.08 million barrels per day in 2010 could be
available for use by the transportation sector.
However, if LPG gains widespread use as a transportation fuel, there
are several potential sources of additional supply to meet the demand
without relying on imports. According to EPA, regulations requiring
reductions in Reid vapor pressure (RVP) of gasoline could contribute an
additional 25.4 million barrels per year of LPG to the national supply after
1992.[52] Note, however, that this is a maximum value that does not
account for the use of butane internally by refiners for production of MTBE
or other octane enhancers, which will most likely reduce the butane
available on the open market from this source. Changes in other industries,
such as switching the chemical industry back to using ethane instead of
naptha, may make up to 39 million barrels available for use as a
transportation fuel.[46] If all of these measures are taken, and all this LPG
is made available as a transportation fuel, up to an additional 0.55 million
barrels of LPG per day, or a maximum total of 0.61 million barrels per day
in 2000 and 0.63 million barrels per day in 2010, could be available for
automotive use.
EIA does not have future resale price predictions for propane.
However, industrial LPG prices are projected to grow at an annual rate of
1.5 percent.[4] Applying this same rate of increase to the 1989 average
propane resale price ($0,246 per gallon) yields future LPG price estimates
of $0.29 per gallon in 2000 and $0.34 per gallon in 2010. LPG prices can be
volatile depending on market demands; in the year from August 1989 to
August 1990 the price rose from $0.22 per gallon to $0.54 per gallon; due
to current international events, the price was $0.91 per gallon as of October
22, 1990.[53, 54] The conversion of LPG to a usable transportation fuel and
the costs involved will be discussed in Section II.
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F. Nonbiomass Renewable Energy Feedstocks
Several non-biomass renewable energy feedstocks are available from
which to produce transportation fuels, primarily electricity. Included
among these feedstocks are plutonium (used by nuclear reactors) and solar
energy.
1. Plutonium (Nuclear Breeder Reactors^
The nuclear reactors which will be discussed in this appendix for
generating electricity, nuclear breeder reactors, require either plutonium
(Pu) or thorium (Th) as a primary fuel. Plutonium does not occur naturally;
it is a byproduct of nuclear reactions in conventional reactors which use the
uranium isotopes U235 and U238. Hence, plutonium is "renewable" in the
sense that it is produced continually by the operation of nuclear reactors
and thus will be available as long as these other reactors continue to
operate. Two alternatives exist for producing plutonium for use by nuclear
breeder reactors. The first is to recover it from conventional reactors,
which generate plutonium naturally, and use this as a fuel to start the
reaction in a breeder reactor. The breeder reactor would then produce
more plutonium which could be used in that or other reactors. The second
alternative is to initially charge a breeder reactor with a mixture of U235
and U238, then reload later with plutonium bred by that reactor.[55]
Growth in the nuclear industry would require further exploration and
recovery of uranium deposits. The least expensive uranium to mine occurs
in deposits near the surface containing 80 to 3100 parts per million (ppm)
U3O8. Mining expenses rise as depth of deposit increases and composition
of uranium in the ore decreases. EIA estimates that the U.S. has 981
million pounds of U3O8 in "reasonably assured resources."[56] Based on
approximate heat content and an electricity conversion efficiency of about
30 percent, this could provide 1.8 billion oil equivalent barrels of energy.
The average cost of this uranium was $19.56 per pound in 1989.[57]
If breeder reactors are used to generate nuclear energy, concerns
regarding the supply of uranium may be unnecessary. Some fast breeder
reactors have already been demonstrated at pilot sclae but not successfully
commercially. Breeder reactors are attractive because they can use U238,
which makes up 99.3 percent of natural uranium. There may already be
enough U238 mined to fuel breeder reactors for several hundred years.[55]
Even if this were not enough, the easily recoverable uranium contained in
near-surface deposits would provide enough fuel for centuries.
4-26
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The costs of generating electricity using nuclear breeder reactors is
discussed in Section II.
2. Solar Energy
1 9
The U.S. receives 5.13 x 10 Btu per year energy from the sun.[581
This energy is equivalent to over 600 times the total U.S. consumption of
energy in 1989. Assuming a 12 percent conversion efficiency for electricity
production, a rate commonly used for solar energy, enough electricity could
be generated in an area of 3,600 square miles (0.1 percent of the U.S. land
area) to completely satisfy annual U.S. electricity demand. To provide
enough energy for the entire national annual energy needs, an area of
about 36,000 square miles would be required.[58] Obviously, there would
be many logistical and technical problems associated with initiating large
scale use of solar energy, including the lack of uniform distribution of
sunlight and the great distribution losses which would be experienced due
to the large distances between the desert areas and major metropolitan
locations. This energy source could prove attractive for localized use,
however.
Electricity generated using solar energy is often mentioned as a
means of producing hydrogen. Sometimes this is presented simply as a
means to store the energy from the sun, since there are not ideal ways to
store the energy or the electricity generated. Usually, however, it is
presented as a reasonable means of producing hydrogen to be used as a
means to convert waste C02 to methanol or for use as an alternative fuel
itself. Electrolysis of water using solar photovoltaic generated electricity
could produce hydrogen at $27-72 per million Btu.[59] Since solar energy
is renewable, this process appears to be attractive in the long term for
hydrogen production, although the costs to produce hydrogen and vehicles
to run on it is clearly prohibitive at this time. Hydrogen's potential as an
alternative fuel will not be addressed in this report. The costs of producing
electricity from solar energy will be discussed further in Section II.
II. Production Costs of Alternative Transportation Fuels
Compressed natural gas (CNG), electricity, ethanol, liquefied
petroleum gas (LPG), and methanol are the major alternative fuels that can
be produced from the previously discussed feedstocks. Some of the
feedstocks can also be used to produce synthetic gasoline and diesel fuel as
4-27
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byproducts, but these "conventional fuels" will not be discussed further
since this report focuses on vehicles operating on fuels other than gasoline.
Although many reports have been written about the technology
involved in these conversion processes, few include detailed estimates of
the construction costs or provide an estimate of the cost of the fuel
produced, and fewer still discuss the environmental impacts either in terms
of changes in air quality resulting from emissions or from changes in land
or water quality which might result from the production of large quantities
of alternative fuels. This lack of information makes an analysis of fuel
production costs difficult, particularly due to the fact that for many of the
technologies discussed no commercial plants currently exist. In spite of
these information gaps, a consistent basis for evaluating production costs
must be developed to allow for equitable price comparisons between each
fuel and each potential feedstock.
For example, many reports have been written about designs for
plants that convert coal to methanol by gasification, as the next section will
discuss. These reports were written over a time period of more than ten
years. Each design was optimized according to the designer's requirements,
so one plant may use 20,000 tons per day of coal feed while another may
use 26,000, and the methanol production rates of the two plants will be
different due to differences in conversion efficiency. In order to compare
these processes, they must be scaled to a common rate of fuel production.
The economics must also be altered to reflect the capacity changes, and
must be escalated to current (1989) dollars. A discussion of the economic
assumptions used for this analysis is presented in Appendix 4-A.
As explained in Appendix 4-A, the fuel production costs presented in
this report are based on the assumption that a relatively secure,
established alternative fuels program designed to minimize investment
risks, resulting in a relatively high volume of alternative fuel use and the
presence of a significant number of alternative-fueled vehicles on the road,
is enacted. Without a strong program, these favorable economics will not
be realized. Under scenarios where, in early years, only flexible fueled (as
opposed to dedicated) vehicles are required, with no guarantees of
alternative fuel availability or use, the investment risks could be higher for
both production and distribution facilities, and hence the production costs
could be higher.6 The scenarios evaluated in this report, however,
particularly Scenarios 2 and 3, with high alternative fuel production
6 Although, under such a program there may be added incentive to price the
alternative fuel competitively.
4-28
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volumes and a significant number of dedicated alternative-fueled vehicles
in the marketplace by the year 2010, would likely realize the favorable
production economics described below.
The cost of supplying alternative fuels is also dependant on the
degree to which the alternative fuel use is geographically focused. For a
geographically unfocused program, the distribution and service station
markup costs would be higher than those in a geographically focused one.
Scenario 3, for instance, with its requirements for the sale of a specific
volume of alternative fuels but no restrictions on location, could result in
the sale of alternative fuels spread across the country. Because there is no
guarantee (beyond market forces) that the locations where the alternative
fuels were demanded would coincide with major metropolitan areas and
existing distribution systems distibution costs could be higher. Service
station markup would be higher because the owners would be taking more
of a risk in providing the alterative fuel without a large, known volume in
demand in that location. In contrast, since Scenario 2 limits the
introduction of alternative fuels geographically, the distribution system will
be optimized and hence distribution costs will be minimized. Service
station owners will be guaranteed that a fixed fraction of the population
will demand the alternative fuel from some supplier, so investment risks
will be similar to that for gasoline and markup will not increase over the
values presented in the following sections. This issue will be discussed in
more detail in the sections below on fuel distribution.
The remainder of this appendix presents production costs for each
alternative fuel. Within each fuel section, the production costs and
technologies are discussed for each potential feedstock. Infrastructure and
distribution costs specific to that fuel are then presented in a separate
section. Finally, vehicle efficiencies and costs are discussed, and an overall
(gasoline equivalent) pump price of the fuel is presented.
A. Compressed Natural Gas
Compressed natural gas (CNG) is produced from methane that is
either obtained from natural reservoirs or produced by various feedstock
conversion processes. The technologies and economics involved will be
discussed for each potential feedstock, including coal, biomass, municipal
waste, and natural gas, in the following sections. The cost of compressing
the methane produced from each technology will be included in the pump
prices for CNG that are presented at the end of the section.
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I. Production Costs
a. Coal
The use of coal for alternative fuel production may be attractive
because it could help maintain demand for all, including high sulfur, coals.
Natural gas is produced from coal by gasification followed by purification to
bring the syngas up to pipeline quality. The composition of the gas varies
depending on the gasification process used. An approximate breakdown is
94 percent CH4 and 6 percent H2, with trace amounts of CO and H2O. The
higher heating value of the gas varies from 970-1030 Btu per standard
cubic foot (scf), depending on actual composition. It must be at least 970
Btu/scf to be pipeline quality. Enough coal is available to meet the
demands of all the proposed alternative fuel market scenarios presented in
Appendix 3.
The gasification process begins with introduction of coal into a gasifier
where, at high temperature and pressure, in the presence of oxygen, the
coal is gasified. The syngas produced must be cleaned of particulates and
the acid gases removed before the gas may be used as a fuel. Acid gas
removal involves one of several commercially available processes in which
all sulfur compounds, such as H2S, and much of the C02 are stripped from
the gas. The acid gas is treated and elemental sulfur removed before the
waste gases are vented.
Since natural gas has a higher heat content than syngas, the methane
content of the syngas is increased by methanation or cryogenic distillation.
Methanation involves conversion of CO and H2 to CH4; cryogenic distillation
involves separation of CO and H2 from a syngas which initially has a high
concentration of CH4. Application of either of these processes depends on
the composition of the raw gas produced by a particular gasifier.
The Great Plains Coal Gasification Project, which is currently operated
by Dakota Gasification Company in Beulah, N.D., uses Lurgi gasifiers and
methanation to produce 145-155 million scf per day of methane for
delivery to the pipeline. This process has been hailed as a technical
success, and will continue to be used as a source of information regarding
various design improvements.
Table 4-11 presents the economics of two processes in which natural
gas is produced by coal gasification.[60,61] These plants were sized to
50,000 OEB per day natural gas production and costs were escalated to
4-30
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1989 dollars (as discussed in Appendix 4-A). As the table shows, the
gasification/methanation process developed by Lurgi is less expensive, with
a plant investment of $2,395 million. The gas produced is estimated to cost
S7.70 per million Btu (iMMBtu). This process was designed to use lignite,
although, for consistency among various fuel production processes
considered in this report, the costs were evaluated assuming the use ot
bituminous coal. If the process were optimized for bituminous coal, these
costs could be lower. The Catalytic Coal Gasification process from Exxon,
which uses cryogenic distillation to produce almost pure CH4 by recycling
the unconverted CO and H2, is estimated to be more costly to build and
operate, with an investment of $2,769 million and fuel price of $11.27 per
MMBtu. This great cost difference is probably due to the fact that, at the
time each of the referenced reports was written, the Lurgi gasifier was well
developed and assumed to be commercial ready, while the Exxon process
was developmental; the two processes could exhibit more similar costs if
the technologies were equally developed
Table 4-11
Production Costs of Methane from Coal
Process
Lurgi
Gasification/
Methanauon ^
Catalytic 16,504 2.769 11 27
Coal
Gasification2
1 Based on a design for lignite; costs could be lower if design were optimized for
bituminous coal.
^These costs are based on a design that was under development at the time the
referenced report was written. It is possible these costs could be lower if the
design were optimized and proven commercially
Coal Plant Fuel
Capacity Investment Price
(TPP) (Smillinnl CS/MMBTLO
17,588 2,395 7.70
Given the projected future coal costs presented in Section I, the price
of natural gas produced by the Lurgi Gasification/Methanation process is
expected to cost $8.45/MMBtu in 2000 and $8.69/MMBtu in 2010. The
natural gas from the Catalytic Coal Gasification process is estimated to cost
$11.52/MMBtu in 2000 and $11.78/MMBtu in 2010.
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Since the Lurgi design appears to be a lower cost system and has
been proven operational at the Great Plains Plant, a price of $7.70/MMBtu
($8.45/MMBtu in 2000 and $8.69/MMBtu in 2010) will be used for natural
gas from coal in the remainder of this report.
b. Biomass
Methane can only be produced from biomass directly by anaerobic
digestion. Although other technologies exist, they yield methane indirectly.
For example, technology exists to gasify biomass much like coal, the syngas
produced is a low to medium Btu (less than 500) gas which is not
compatible with natural gas. The syngas can be upgraded to a high Btu,
methane-rich gas, but this adds significant expense to the operating costs
making the process uneconomical at this time. However, enough biomass is
available to produce CNG under all the scenarios considered in this report
regardless of which technology is used.
The production of natural gas by anaerobic digestion of biomass is
well documented from the research perspective. Wet biomass such as
aquatic plants or, more commonly, manures from confined animals are the
best candidates for this complex biological process which uses bacteria to
decompose the biomass, producing a "biogas" as a byproduct. This process
is slow, since digestion takes about 25 to 30 days. The process is also
inefficient because of feedstock contamination, such as that of manures on
animal feedlots. DOE estimates the current cost of producing methane from
biogas to be $5.00 per million Btu given current technology.[31] Although
the inefficiency of this process would probably make its use for large scale
methane generation unrealistic, if it were used the price of the methane
would rise to $5.14 per MMBtu in 2000 and $5.29 per MMBtu in 2010.
based on the increases in biomass prices projected in Section I.
c. Municipal Waste
There are two methods for producing natural gas from municipal
waste. One is the generation of methane through anaerobic digestion,
which occurs naturally, albeit slowly, in landfills or can be "artificially"
induced in an industrial or laboratory setting using microorganisms. The
second method for producing natural gas from municipal wastes is
gasification. Over 80 facilities to recover methane from landfills exist in the
U.S.; there are no commercial scale MSW gasification plants currently in
operation.[31] About 180-280 cubic feet of gas is produced per ton ot
waste in the landfill per year. Theoretically, it appears that this process
has a life span of 10 years, after which gas production decreases.
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Methane recovery is environmentally beneficial because it helps to
control the dangerous gas produced naturally in landfills and reduces
emissions of an important greenhouse gas. In addition, investment costs
are minimal and easily recovered since the conversion occurs naturally and
only requires depositing the waste in a landfill that has the appropriate
pipes installed to capture the gases as they are formed.[62] Currently,
recovered landfill gases are used either to generate electricity or are flared
and released to the atmosphere; efforts to increase utilization of this gas are
growing. Therefore, most of this resource would likely be available to
supply incremental CNG demands, assuming displacement of the gas
currently used for electricity generation. According to DOE, the cost of
medium-Btu gas generated by a landfill is approximately $3.00 per million
Btu; upgrading this to a high Btu gas by removing the C02 would raise the
price $1.50 to $2.00 per MMBtu, assuming a process such as the Selexol
technology, and absorption/stripping process, was used to remove the
^02-[98,63]
MSW can also be anaerobically digested using bioorganisms in a
conversion plant to form medium-Btu biogas like that made from biomass.
The major costs of this process arise from the high cost of investment in the
reactor and the heat needed to drive the process.[62] This gas must be
upgraded to a higher heat content for use a natural gas. No facilities
currently exist that make use of this process, and no cost estimates are
available.
Gasification of municipal waste requires processing the waste into
refuse derived fuel (RDF) to remove excess moisture, then gasifying the RDF
pellets. As in the case of biogas, use of this gas requires refining the gas to
increase the heating value, a process which adds a considerable expense to
the cost of the methane. No estimates of the costs of producing methane by
gasification of municipal waste are currently available.
Based on DOE's estimate for the cost of landfill generated gas, a
methane cost of $4.50 per MMBtu was used in the analysis of the cost of
producing CNG from MSW in this report. Development of gasification
technology for MSW could yield significantly different costs for methane
produced from this feedstock. Based on the future availabilities presented
in Section I, MSW can supply enough CNG for either Scenarios 1 or 2,
assuming conversion of most of the waste in the country to alternative
fuels. (This may be difficult because of the decentralized collection of the
waste but is possible if municipalities choose to use fuel generation as a
means to handle disposal of much of their waste.)
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d. Natural Gas
Production of gas for CNG vehicles from natural gas involves simply
compressing the gas to the pressure at the service station. For domestic
gas, the "production" cost is merely the wellhead prices presented in
Appendix 2. For foreign gas (including vented and flared gas) the cost of
liquefaction, ocean transport, and regasification must also be included.
These costs were calculated from the feedstock costs of Section I, using
equations taken from a recent report prepared by DOE, and are presented
in Table 4-12 for the years 2000 and 2010.[42] As the table shows,
delivered costs for LNG would be as low as $3.75/MMBtu from Site III
exporters in 2000. Delivered LNG costs from Alaska, identified as a Site IV
category by DOE, would be approximately $4.37/MMBtu in the same year.
These costs increase for the year 2010, due to increases in feedstock and
liquefaction costs. Nigeria, the largest potential source of vented and flared
gas, is classified as Site III by DOE. Using the collection cost of
$1.00/MMBtu presented in Section I and DOE's LNG liquefaction equation, a
delivered cost of vented and flared natural gas of $3.70/MMBtu in 2000
and 2010 was calculated.
Table 4-12
Costs of Foreign Natural Gas (1989 Dollars/MMBtu")
2000 2010
Location Category LI LLI IVC Alaskal LL HI IV
Cost of Feedstock 1.67 1.04 0.78 2.61 1.57 1.15
Liquefaction/Trans/Regas 2.35 2.71 3.59 2.54 2.81 3.66
Delivered Cost 4.02 3.75 4.37 5.15 4.38 4.81
Under the fuel market Scenarios 1 and 2 presented in Appendix 3,
natural gas from any of the sources addressed in Appendix 4 can fulfill
requirements for CNG. For Scenario 3, vented/flared gas can only meet the
demand for 2000, and Alaskan gas cannot meet the requirements at all.
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2. Fuel Distribution/Infrastructure Costs
The natural gas infrastructure system in the U.S. consists of facilities
for the transmission, storage, and distribution of natural gas. Any system
designed for the widespread distribution of CNG as a vehicle fuel would
likely be complex due to the inability of such a system to make use of the
existing gasoline infrastructure. There is some concern about the technical
and economic feasibility of the U.S. building a fast, convenient refueling
system for CNG; an evaluation of this concern was not attempted in
completing this analysis.
Natural gas is transmitted in the U.S. by an extensive network of
interstate pipelines, servicing all states except Alaska, Hawaii, and Vermont
(which imports natural gas from Canada). For this study it was estimated
that there is no need for additional transmission or storage capacity to
deliver the quantities of fuel considered in this report.[64] The current
national transmission system is 25 percent underutilized and the CNG fuel
demand should be well under the national excess capacity. The natural gas
distribution system presently comprises about 1.5 million miles of lower
pressure lines that deliver gas to the end user. In a focused scenario such
as Scenario 2, natural gas use will likely be confined to metropolitan areas,
where existing natural gas distribution systems are extensive and should
be adequate to provide vehicle fuel. The wholesale distribution costs,
including field processing, transmission, and distribution, for this type of
scenario are estimated to be $2.11/MMBtu in 2000 and $2.08/MMBtu in
2010.7 A more geographically dispersed system, as presented in Scenario 3
will require expansion of the existing distribution system. In a recent DOE
report, distribution system expansion costs are estimated at $0.05/MMBtu
($0.01 per gallon gasoline equivalent), assuming distribution to 16,000
service stations, and a 10 percent rate of return on investment.
The service station infrastructure costs and taxes for CNG are
presented in Table 4-13. According to the EPA Special Report on CNG, the
cost to partially convert a gasoline service station to fast-fill CNG refueling
could range from $200,000 to $400,000 per station, based on several
potential annual sales volumes.[65] These gas sales estimates include the
average yearly sales per station estimated by DOE to occur at each of
16,000 light-duty service stations, assuming a 1 million barrel per day
(MMBPD) displacement of petroleum fuel demand by CNG. The amortized
service station conversion cost shown in Table 4-13 is from the middle of
7These numbers were estimated by taking the difference between wellhead and
industrial prices projected by EIA.[51 ]
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this range. The conversion costs include a 10 percent rate of return on
investment. The operating expenses include the cost of energy needed to
run a CNG engine compressor. Maintenance, administrative, and general
expenses are based on the costs of operating the service station. Service
station markup is the same as that for gasoline, adjusted for relative energy
content. Taxes are assumed to be applied at the same rate as gasoline
taxes, on an energy equivalent basis.
With the more geographically disperse distribution of CNG in Scenario
3 compared with Scenario 2, an individual service station's sales would
decrease by approximately 25 percent.[66,67] Since a service station would
incur certain fixed costs (capital and administration), the price per unit of
fuel due to amortized fixed costs would increase somewhat. The increased
pump markup cost for Scenario 3 versus Scenario 2 was estimated to be
approximately $0.056/gallon. [66,69]
Table 4-13
CNG Service Station Infrastructure Costs
Dollars per Gallon
Cost Classification Gasoline Equivalent
Service Station Conversion
Costs 1
0.10
Operating Expenses
0.03
Maintenance, Admin., and
General Expenses
0.06
Service Station Markup2
0.09
Total Infrastructure Costs
0.28
Taxes
0.24
Total Costs
0.52
1 For Scenario 3,this number would increase $0.01/gallon gasoline
equivalent, assuming 5.2 billion cubic feet would displace 1 MMBPD
gasoline and that the current infrastructure reaches 90 percent of the
U.S. population.
^For Scenario 3. this number would increase by $0.056/gallon gasoline
equivalent.
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3. Vehicle Efficiency and Cost
a. Efficiency
Performance and range for CNG-fueled vehicles are important issues.
Surveys of CNG-fueled vehicle operators have indicated that the major
problems reported were fueling inconvenience, power and performance,
and limited range. Assuming the infrastructure can provide convenient,
fast fueling, only performance and range remain as major concerns. The
more competitive CNG-fueled vehicles are with gasoline-fueled vehicles, the
easier the transition to increased use of CNG will be.
Due to CNG's poorer volumetric efficiency, dual-fueled CNG vehicles
have exhibited slower and less fuel efficient performance than gasoline
vehicles. Since CNG is a gaseous fuel, it displaces air in the combustion
chamber, which accounts for the lower volumetric efficiency of engines that
use CNG. The additional weight of CNG tanks (which must be capable of
storing CNG at pressures in excess of 3000 psi, and are therefore much
heavier than conventional fuel tanks) also reduces efficiency, particularly
in a dual fuel vehicle which must support both fuel systems. The added
weight of these tanks plus their fuel capacity must be supported by
additional vehicle structure as well.
The potential for increased efficiency and power for a dedicated CNG
application, however, is great. A dedicated CNG system could take full
advantage of the attractive characteristics of natural gas, such as its high
octane. Increasing the engine's compression ratio, optimizing combustion
chamber design, or a combination of similar approaches could yield far
better performance and efficiency. This optimum system for performance,
fuel economy, and emissions has yet to be determined. For the purpose of
this report, efficiencies (relative to gasoline) of -10 percent for dual fuel
vehicles and +10 percent for future dedicated CNG vehicles were used 8
b. Vehicle Cost
Several factors impact the cost of both dedicated and dual fuel CNG
vehicles, due to significant differences in the type of refueling equipment
required. The use of CNG involves the pressurized storage of natural gas
onboard the vehicle. The heavy gas storage cylinders currently required to
meet U.S. Department of Transportation safety requirements are a
®Driving range is probably shorter than conventional gasoline vehicles. If it were
increased to an equivalent range, the efficiency would likely be lower, resulting in
higher fuel costs and emissions (g/mile) of greenhouse gases.
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significant additional cost, as well as vehicle weight consideration. The cost
of a production CNG vehicle will vary, depending on the type of vehicle,
natural gas storage pressure, and the type of storage tanks used. In mass
production, costs are estimated to be $1,600 more for dual-fuel vehicles
and $900 more for dedicated CNG vehicles over the cost of a conventional
vehicle.[65] Amortized over the full life of the vehicle, this equates to a
cost increase of 2.5 cents per mile for a dual-fueled vehicle and 1.4 cents
per mile for a dedicated vehicle. Some sources suggest that operation and
maintenance costs for CNG vehicles will be lower than for gasoline vehicles.
However, the difference does not appear to be significant. In this report,
CNG vehicle operation and maintenance costs were assumed to be
equivalent to those of gasoline.
4. CNG Pump Price
Tables 4-14 and 4-15 show the overall, efficiency corrected gasoline
equivalent pump price for CNG in the years 2000 and 2010, respectively.
CNG could be produced from domestic natural gas at a price of $1.33 per
gallon (gasoline equivalent) for a dual-fueled vehicle (DFV) and $1.09 per
gallon for a dedicated vehicle in the year 2000 (or from foreign or vented
and flared natural gas for slightly more).9 CNG produced from Alaskan
natural gas or MSW would be somewhat more expensive, although
discussion of any fuel made from MSW should be caveated by the fact that
this feedstock has little potential for large volume fuel production due to its
limited availability and highly heterogeneous nature.
By 2010, increases in domestic gas price caused by limited reserves
should make foreign gas resources more competitive in the U.S. market.
CNG produced from foreign gas could be priced as low as $1.15 per gallon
gasoline equivalent for dedicated vehicles. CNG produced from MSW would
be competitive with CNG derived from natural sources of methane and
could be more attractive if tipping fees rise. However, the same concerns
regarding availability and composition of this feedstock discussed in the
previous paragraph apply here. CNG produced from coal or biomass is not
competitive with CNG from other feedstocks but could have limited regional
applications (the cost for CNG from coal could be somewhat lower than
projected if technologies are optimized for the use of bituminous coals, as is
discussed above).
9Not including the increased costs for CNG vehicles.
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Tabic 4-14
CNG Pump Price Comparisons
(Year 20QQ)
(Projected Gasoline Prices, $/gallon)
Source of Feedstock
Natural Gas
Coal
Biomass1
MSW2
Domestic
Imported
V/F 3
Alaskan
Production Cost ($/MMBtu)
8 45
5 14
4.50
3 14
3.75
3 70
4.37
Distribution Costs4
2.1 1
2.1 1
2.11
2.1 1
2.1 1
2.1 1
2.1 1
Serv. Station Price
10.56
7.25
6.61
5 25
5.86
5 81
6.48
Gasoline Equivalent Cost
1.36
0.94
0.86
0 68
0 75
0 75
0 84
Service Station Markup & Expenses5
0.28
0.28
0 28
0 28
0 28
0 28
0 28
Taxes6
0.24
0.24
0.24
0.24
0.24
0.24
0.24
Total Pump Price
($/gallon gasoline eqv)
1.88
1 46
1.38
1 21
1 27
1 27
1.36
Vehicle Efficiency Factor
(DFV/dedicated)7
1 1 1 / Q 1
Efficiency Corrected
Price ($/gallon gasoline equivalent)
2.09/1 71
1.62/1 32
1.53/1 26
1 33/1.09
1.41/1 16
1 41/1 16
1 51/1 2
'Based on production of biogas, an inefficient process ihai makes large scale production unlikely
2 Based on cost of producing landfill gas. Costs for CNG produced via gasification could be lower, the economics of this
technology are undetermined.
3v/F=vented and flared
"A geographically disperse program would require an additional SO 05/MMBlu (SO 01/gallon gasoline equivalent)
5 For a geographically disperse program, litis number would increase $0 056/gallon gasoline equivalent
f> I'liis docs nol include llie highway fuel lax increases resulting from the budget deficit reductions ol 1490
1 I > I V-IJual I in. I i.d vehicle, dedicated-vehicle operating only on CNG
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Table 4-15
CNG Pump Price Comparisons
(Year 3Q1Q)
(Projected Gasoline Prices, $/gallon)
Source of Feedstock
Natural Gas
Coq)
Biomass1
MSW2
Domestic
Imported
V/F3
Alaskan
Production Cost
((/Million Biu)
8.69
5 29
4.50
5 47
4.38
3.70
4 81
Distribution Costs4
2 08
2.08
2.08
2.08
2.08
2 08
2.08
Serv. Station Price
10.77
7.37
6.58
7.55
6.496
5 78
6.89
Gasoline Equivalent Cost
1.39
0.95
0.86
0 97
0.83
0 75
0 89
Service Station Markup5
0.28
0.28
0.28
0 28
0.28
0 28
0.28
Taxes6
0.24
0.24
0.24
0.24
0.24
0.24
0.24
Total Pump Price
1.91
1.47
1.38
1.49
1.365
1.27
1 41
($/gallon gasoline eqv)
Vehicle Efficiency Factor
(DFV/dedicaied)7 -1.117.91
Efficiency Corrected
Price ($/gallon gasoline equivalent) 2.12/1.74 1.63/1.34 1.53/1.26 1.66/1.36 1.50/1 23 1 40/1.15 157/1.28
1 Based on production of biogas, an inefficient process (hat makes large scale production unlikely
2 Based on cost of producing landfill gas. Costs for CNG produced via gasification could be lower; the economics of this
technology are undetermined
3v/F=ventcd and flared
4 A. geographically disperse program would require an additional SO 05/MMBtu (SO 01/gallon gasoline equivalent)
^For a geographically disperse program, this number would increase SO 056/gallon gasoline equivalent
6This dues not include the highway fuel lax increases resulting from the budget deficit reductions of 1990
^DFV=Uual-fueled vehicle, dedicatcd = vehiclc operating only oil CNG
4-40
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B. Electricity
Electricity is often considered to be a promising alternative fuel
because electric cars produce essentially no emissions. However, when
exploring the environmental attractiveness of electricity as a vehicle fuel,
consideration must also be given to the environmental impacts of electricity
generation (as will be explored in Appendix 7). Conventional means of
generating electricity include the use of coal, natural gas, petroleum
products, and hydroelectric power. Table 4-16 presents the breakdown of
electricity generation by source in 1989.[48] As the table shows, coal
accounts for the majority of electricity produced in this country, with 55
percent of power generated from coal. Future predictions by EIA show
essentially the same breakdown by feedstock, with slight gains for coal and
natural gas usage and a slight decline in the use of nuclear power expected
through the year 2010.[4]
Table 4-16
1989 Electricity Generation by Fuel
Fuel Million kwh Percent of Total
Coal
1,551,852
55
Petroleum
158,241
6
Natural Gas
264,957
9
Nuclear
529,355
1 9
Hydroelectric
265.061
_9
Total
2,780,775
98*
""Other sources (such as wood used industrially, solar energy, and
wind) provided the remaining 2 percent of electricity generated.
All fossil fuels used for generating electricity contribute greenhouse
gases as well as regulated pollutants to the atmosphere. New feedstocks for
electricity generation, particularly those that are renewable, are attractive
alternatives. Nuclear and solar energy are feedstocks for electricity
production which could substantially reduce global warming impacts.
Research into the conversion of municipal waste and biomass into
electricity also appears promising. In addition, new technologies for
"conventional" electricity generation have been developed to minimize the
4-41
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emissions from fossil fuel based utilities. The costs of electricity derived
from both conventional power plants and from renewable resources are
considered in the following sections.
1. Production Costs
a. Conventional Feedstocks
The average price of electricity in 1989 was $0.0644/kwh; industrial
users paid an average of $0.0472/kwh. The average price to end users is
predicted to be $0.0662/kwh in 2000 and $0.0701/kwh in 2010. Because
coal yields such a large portion of the electricity generated in this country,
new legislation on acid rain and its resulting effect on the use of high sulfur
coals is expected to be reflected in the price of electricity in the future. ICF
Resources predicts that the national average electric rates will increase
between 1.5 and 2.8 percent over 1989 rates.[5,6] States which rely on
high sulfur coal, such as West Virginia, Ohio, Kentucky, and Indiana, are
expected to have rate increases as high as 11 percent over current rates.
Given these expected increases, this report will use electric rates 1.5
percent higher than those predicted by EIA, that is, $0.0672 per kwh in
2000 and $0.0711 per kwh in 2010.
A potential use for high sulfur coal is to produce electricity using
gasified coal to drive gas turbines. Although gasification plants are more
capital intensive than conventional coal-fired plants, they have several
benefits over traditional plants. The gasification process requires
incorporation of sulfur removal equipment as part of the design,
eliminating the need for costly scrubbers and providing a byproduct that
may be sold to help offset operating costs. In the light of the new acid rain
legislation, these plants may be attractive for future capacity additions. In
addition, gasification plants usually are cogeneration plants, where heat
recovery is used to generate additional electricity through steam turbines,
making the process energy efficient.
Capital costs for production of electricity by gasification of coal would
be similar to those for production of methane from coal, but lower since
methanation equipment is unnecessary. The Cool Water Gasification Plant
in California gasified coal and produced electricity using combined-cycle
power generation equipment (gas turbines and steam turbines). The plant
was a technical success and the electricity was sold by Southern California
Edison to its customers. The five year demonstration period ended this
year (1990) and the plant was shut down while plans are finalized for
4-42
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Southern California Edison to sell the plant; it will be restarted by the new
owner when the sale is complete.
b. Biomass and Municipal Waste
Electricity can be generated from biomass or municipal waste by
burning the feedstock in a manner similar 10 a coal-fired power plant or by
gasifying the feed and using the gas in a gas turbine. Additional electricity
may be generated if a heat recovery system using a steam turbine is
included in the design.
No facilities currently exist for gasification of biomass or MSW to
generate electricity. However, the same technologies used for conversion of
biomass or MSW to methane can be alternately designed for power
generation. After the feedstock is processed and gasified, the gas may be
sent to gas turbines to generate electricity. A pilot plant to gasify 200 tons
per day of MSW for electricity generation was built and operated by Union
Carbide in South Charleston, West Virginia, in the early 1980's.[69] The
plant used a "PUROX" gasifier developed by Union Carbide. The plant ran
successfully, but attempts to market the technology to municipalities were
unsuccessful. Hence, Union Carbide is no longer pursuing gasification of
municipal waste and the plant is no longer operating.
Since the gasification of municipal waste for electricity generation has
been proven as a feasible technology, it is reasonable to estimate what the
cost of electricity using MSW (in the form of the refuse derived fuel (RDF)
discussed in Section I) would be in the future. Substituting the RDF cost of
$3.50 per MMBtu for the coal feedstock portion of EIA's projected costs for
future electricity generation (presented above), it is possible to estimate
costs of $0,075 per kwh in 2000 and $0,079 per kwh in 2010 for electricity
produced by the gasification of municipal waste. (If tipping fees increase,
as discussed in Section I, the cost of RDF, and hence, the cost of electricity,
would decrease, and could become competitive with the cost of producing
electricity from conventional feedstocks.) Although these projections are
approximate costs and do not account for optimization of the process to use
municipal waste instead of coal, they do provide a basis for comparison
with other feedstocks. Future versions of this Environmental Study will
contain a more rigorous analysis of the cost of generating electricity by the
gasification of municipal waste.
Conceptually, there is no difference between a biomass-to-electricity
or a MSW-to-electricity plant; both need cellulose for gasification and both
are technologically feasible. Unfortunately, no designs currently exist for a
4-43
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biomass-to-electricity gasification plant, hence a current cost of producing
electricity in this manner is unavailable. An analysis of the technology and
costs of producing electricity from biomass will be included in EPA's next
Report to Congress required by the Alternative Motor Fuels Act.
c. Solar Energy
The use of sunlight to supply energy needs is not a new concept.
Although not common, solar heated homes are found in various locations
throughout the country. Solar-produced electricity, however, makes up less
than 1 percent of the electricity generated in the U.S.; about 2.5 million kwh
were produced in 1989.[4] There are two major types of solar power
generators, thermal and photovoltaic. Thermal solar generators collect
solar energy using heat collectors and transfer the heat to water to
generate steam and subsequently electricity. Photovoltaic solar generators
absorb sunlight using certain materials which can turn absorbed energy
directly into electricity through creation of a voltage gradient, the
"photovoltaic effect."
Thermal solar generators are designed to produce between 1 and 10
MW. The efficiency of this process is about 24 percent, with a solar
collection efficiency of about 60 percent and a steam generator efficiency
around 41 percent. Such plants were projected in 1982 to cost 40-60
percent more than fossil-fueled power plants. The environmental
drawbacks of this design are minimal. In fact, in Italy grass is grown
underneath thermodynamic solar collection mirrors.
One problem with thermal solar power plants is that they require
direct sunshine to maintain cost effective operation. Only sunny climates
allow achievement of reasonable costs per kwh. In addition, for locations
away from the equator, high altitudes are best for high efficiency
operations. Thus, the optimal locations where this process could be
implemented are limited.
The need for electricity in remote regions for industrial or
agricultural use can be met by thermal solar power systems. Since the
power used for these purposes could be interruptible, small systems
designed to produce 10 kW to 10 MW would be ideal. In China, a solar
power station generating 10-20 kW electricity and pumping water was
designed for use in rural areas.[71] The system was tested and operation
appeared to be satisfactory. Since these applications for small scale
electricity production are viable, these concepts could be applied to
4-44
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generation of electricity for automobiles. This could be particularly useful
for fleets or agricultural and industrial vehicles.
According to the Solar Energy Industries Association, the cost to an
independent producer to produce electricity using a new solar thermal
generation facility is estimated to be $0.08-0.12 per kwh.[72] Larger scale
plants are being developed which could produce electricity at a lower cost.
Unlike thermodynamic solar power plants, photovoltaic solar power
plants do not require cooling and do not have sunshine or high altitude
requirements for efficient operation. One advantage of this type of solar
generator is that the collectors are lightweight and may be mounted on top
of existing structures. For example, the total residential, industrial, and
commercial roof area in the U.S., about 10,000 square kilometers, would
provide enough electricity to power the whole country, assuming an
efficiency as low as 10 percent.[73]
Estimates of the cost of photovoltaic plants appear to vary widely. A
1982 estimate for a plant with a 12 percent conversion efficiency was
$10,000/kW, making this design prohibitively expensive.[58] Estimates
from another source, however, were comparable to 1978 estimates for
nuclear power plants, with plant costs of $700-900/kW for a photovoltaic
plant operating 12 hours a day or 4,400 hours a year.[73] Electricity
generated by such a plant was estimated to cost as little as $0,032 per kwh
(about $0.05 in 1989 dollars). However, the Solar Energy Industries
Association estimates the current electricity cost to the producer from a
photovoltaic plant to be $0.20-0.40 per kwh.[72]
Given the relative costs of the two types of solar processes, generation
of electricity using solar power will most likely be accomplished with
thermal solar generators. Therefore, the price of solar produced electricity
used in the report will be $0.08 per kwh. Since feedstock costs for solar
energy will not increase in the future, it is reasonable to assume that the
price of electricity generated using solar plants will remain relatively
constant (barring major technological advances) at about $0.10 per kwh.
the midpoint of current price estimates.
d. Nuclear Breeder Reactors
When considering nuclear energy as a potential source of electricity
for use as a vehicle fuel, nuclear breeder reactors are an attractive option
over conventional reactors. Conventional reactors, which use uranium,
operate by a chain reaction of splitting atoms until all possible fuel is used
4-45
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up and the reaction ends. Breeder reactors, on the other hand, use a
mixture of plutonium and uranium as fuel. As the reaction proceeds, more
fuel is generated because the uranium atoms are converted into plutonium,
a species which continues to react without forming chain stopping species.
These reactors are very efficient, although they require separation of the
plutonium from the other species and the continuous input of uranium.
In spite of their efficiency, very little research has been done into
nuclear breeder reactors since the late 1970's. Although they have been
used successfully in Europe, particularly France, the technology is rather
undeveloped for large scale implementation in the U.S. The costs of
electricity generated by breeder reactors are very uncertain at this time.
Hence, this technology will not be discussed further in this report.
2. Fuel Distribution/Infrastructure Costs
The future average retail price for electricity from conventional
sources was projected by EIA, as was presented in Section l.[4] For
electricity from biomass and municipal waste, the average retail price must
be estimated from production costs and the typical retail price mark-up,
taking into account the energy lost during transmission (14 percent).! 105]
Since recharging electric vehicle (EV) batteries requires a relatively long
time (6-8 hours), it is most likely that this will occur either in the home or
in a fleet's garage overnight.[74] Hence, residential retail price could be
used to determine the production price. However, since recharging would
be done at night, the cost of electricity would be expected to be lower than
it " would be in the peak (daytime) hours. Since there is insufficient
information available regarding the production price of electricity tor
automobiles, the average retail price (residential, commercial, industrial), as
projected by EIA or calculated from production costs, is used in this
analysis. Since electricity is available throughout the U.S., and since the
majority of refueling would likely take place at night, the existing electrical
distribution system is believed to be sufficient to fuel electric vehicles.[64]
No additional costs are assumed in the transmission of electricity for
geographically dispersed scenarios like Scenario 3.
In addition to the cost of the electricity itself, road user taxes and
additional costs for recharging equipment would be incurred by the
consumer. As will be discussed in the following section, electric vehicles
are much more efficient on a mile per gallon basis than conventional fueled
vehicles. This raises the question of whether it is more appropriate to levy
taxes for electric vehicles on a per mile travelled basis, or on an energy
equivalent basis. Precedent has set taxes for fuels such as methanol
4-46
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equivalent to gasoline on an energy equivalent basis; for consistency in this
report taxes for electric vehicles will also be levied on an energy basis.
Thus, road user taxes for EVs would cost an additional 0.706 cents/kWh.
DOE estimates that the recharging equipment, on the average (for both
household and fleet vehicles) would cost 0.012 cents/kWh when amortized
over the life of the vehicle.[74] These additional costs are shown in Tables
4-16 and 4-17, presented with Section 4.
3. Vehicle Efficiency and Cost
a. Efficiency
Poor performance, limited range and high cost have been significant
limitations in the production or wide-spread use of electric vehicles (EVs).
Average efficiencies of 0.471 kwh/mi, or approximately 70 miles per gallon
gasoline equivalent, have been reported, including transmission, battery,
and charger efficiency (the "total energy load").[75] This efficiency,
however, is estimated only for vehicles with a relatively short driving
range, on the order of 70-90 miles between recharging. As electric vehicle
range is increased to levels similar to current gasoline vehicles, overall
energy efficiency decreases substantially, increasing operating costs and
greenhouse gas emissions substantially (as discussed in Appendix 7).
Electric vehicle efficiency is linked primarily to battery and charger
efficiencies. Transmission, battery and charging efficiencies reported in the
literature average 65 percent, combined.[75] Electric vehicles are also
heavier than conventional vehicles, primarily due to the batteries, further
reducing performance.
The recent development of a prototype EV has demonstrated
significantly improved efficiency and performance for EVs.[76] However,
many of the fuel efficiency improvements employed on this vehicle, such as
the use of light weight materials to compensate for battery weight and the
use of light weight, high power electronics, could also be used in gasoline
vehicles. Therefore a direct comparison with current gasoline vehicles is
not appropriate. Other improvements, such as the use of a high power,
dual-motor drive to eliminate the weight and power losses associated with
mechanical differentials and multispeed transmissions are specific to the
electric vehicle. The prototype vehicle provides a range of about 120 miles,
which is shorter than conventional vehicles; this could be extended up to as
much as 250 miles, depending on the type of battery used. The vehicle's
efficiency is equivalent to over 200 miles per gallon gasoline equivalent
(not including the inefficiencies at the power generation plant, of course).
4-47
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Future developments in electric motor and battery technology could further
improve EV performance and efficiency.
b. Vehicle Costs
One of the biggest obstacles to EV marketing is the price differential
between EV and equivalent gasoline vehicles. Current electric vehicles are
extremely costly, primarily due to the cost of the battery. Current
technology uses a nickel-iron (Ni-Fe) battery. According to the Interagency
Commission on Alternative Fuels, an electric passenger car is expected to
cost $750 less than a conventional vehicle, but the batteries are projected
to cost $6,240, for a net vehicle price increase of $5,490.10[74] (Of course, a
driving range greater than 70-90 miles would require additional batteries,
raising the price of the vehicle substantially.) It is expected, however, that
as production volume increases this price differential will be reduced. It
has been predicted that, under mass production, EVs could become cost
competitive with conventional vehicles.[77] However, for this report, the
full differential price of $5,490, will be assumed. Amortized over the life
of the vehicle, this equals 8.6#/mile. Maintenance costs for EVs have been
projected to be about 50 percent of those for conventional vehicles, or
about 3.40/mile.
4. Electricity Pump Price
The estimated pump prices for electricity in the years 2000 and 2010
are shown in Tables 4-17 and 4-18. Conventional means of generating
electricity (coal, natural gas, and other feedstocks currently used) will
likely produce electricity at the lowest cost in the future. Using DOE'b
projected electric costs and factoring in the costs ¦ of recharging, gasoline
equivalent, efficiency corrected prices of $1.12 per gallon in 2000 and
$1.18 per gallon in 2010 were estimated for electricity produced from
conventional (coal, gas) resources.11-12 At current tipping fees, municipal
waste-based electricity appears to be somewhat more costly than
electricity generated by conventional means, but could be more attractive if
10Lead(Pb)-acid batteries, an alternative, would be less costly at installation (52,609)
but have a life of only about one-third that of Ni-Fe batteries; the use of Pb-acid
batteries would require a greater total investment (about $7,300) over the life of the
vehicle than required for the use of Ni-Fe batteries.[69]
11 Not including increased vehicle costs and assuming a range of 70-90 miles between
refuelings.
12If the range were increased to be equivalent to that of a conventional vehicle, the
rate of energy consumption, and hence, the gasoline equivalent price, could increase
by as much as 50 percent or more, as indicated in the table.
4-48
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higher disposal costs for the waste are realized in the future. However, the
use of electricity generated from municipal waste for use as a vehicular
fuel would have only limited regional application because of the highly
decentralized nature of this feedstock. Solar energy is currently price
prohibitive and would likely have only limited application in the near
future.
Table 4-17
Electricity Pump Price Comparisons
fYear 2000^
Fgcctsiffrt
Conventional Solar MSW'*
Producers Price (c/kwli) 6 70 10 0 7 5
Avg. Retail Price 9 50 13.3 10.4
Rcchargcr Costs 0.01
Taxes QJZJ
Total Price (C/kwh) 10.22 14 02 112
Gasoline Equiv. Rano (kwh/gal) "56,65
Total Price cS/gal gas equiv ) 3 74 5 14 4 10
Efficiency Correction Factor1" 0 30 - 0 50
Efficiency Corrected
Price (S/gallon gas. equiv ) l 12-1.87 l.54-2.57 l 23-2.05
'This faaor includes recharging and vehicle efficiencies. The lower factor assumes a vehicle
range of 70-90 miles between refueling. Costs could be significantly higher at driving ranges
equivalent to current gasoline vehicles, as represented by ihe higher correction factor
**Esumaccd assuming refuse derived fuel used in place of coal. Becauic of special
considerations for MSW handling and combustion, these costs could be higher. Also, due to
us limited availability. MSW may be unable lo meet the demand for electricity under a lar»e
volume alternative fuels program
4-49
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Table 4-18
Electricity Pump Price Comparisons
(Year 2010)
Feedstock
Convcntio n al Solar VIS W * *
Producers Price (c/kwh) 7 11 10.0 7 9
Avg. Retail Price 9 99 13.3 10 9
Recharger Costs 0 01
Taxes 0 71
Total Price (e/kwh) 10 71 14 02 116
Gasoline Equiv Ratio (kwh/gal) 36 65
Total Price (S/gal gas cquiv ) 3 92 5 14 4 25
Efficiency Correction Factor* 0 30 - 0 50
Efficiency Corrected
Price iS/gal gas equiv) 1 18-196 154-2 57 128-2 12
*Tlus factor includes recharging and vehicle clficicncicb The lower factor assumes a vehicle
range of 70-90 rrnlcs between rcfucltng Costs could be significantly higher at driving ranges
equivalent to current gasoline vehicles, as represented by the higher correction factor
""Estimated assuming refuse derived lucl u^cd in place of coal. Because of special
considerations for MSW handling and combustion, these costs could be higher. Also, due to
us limited availability, MSW may be unable to meet the demand lor electricity under a large
volume alternative fuels program
C Ethanol
As noted in the biomass feedstock information of Section I, ethanol
can be produced from com or cellulosic materials. The production,
distribution, and infrastructure costs and vehicle efficiency will be
presented in the following sections.
1. Production Costs
Some of the factors affecting the final production cost of ethanol
include (but are not limited to): I) the market prices of the feedstock and
byproducts, 2) the type of feedstock processing utilized, 3) facility size and
4-50
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location, 4) energy supply, and 5) cost management. This section examines
the cost of ethanol production from both the traditional feedstock, corn, and
future cellulosic feedstocks.
a. Corn
Of the noncellulosic feedstocks, corn is used as the feedstock in about
95 percent of the total capacity of operating ethanol plants.[78] Six studies
which looked at the cost of ethanol production from corn under different
scenarios were used in this analysis and are described briefly below. (Note:
"DM" = dry mill process, "WM" = wet mill process)
DoA (1988) surveyed six large (> 30 MMgal), three midsize (10-30
MMgal), and two small (<10 MMgal) ethanol producers for cost
information.[24]
Kelly completed a somewhat detailed analysis of four plants, one WM
high fructose corn syrup (HFCS) add-on of 80 MMgal and three
grassroots plants--70 MMgal WM, 60 MMgal DM, and 10 MMgal
DM.[79]
API performed an analysis of 50-60 MMgal/yr DM and WM plants,
varying only corn and byproduct cost between a surplus summer and
a drought summer.[80]
DoA (1986) showed economies of scale in DM plants ranging from 10
to 120 MMgal. While energy costs were assumed the same for all
sizes, unidentified direct and indirect costs and capital charges varied
with plant size.[26]
Keim did a detailed analysis of a 120 MMgal/yr revamped wetmill
plant, a 20 MMgal new dry mill plant, and a 10 MMgal add-on wet
mill plant.[23]
Amoco analyzed a small and a large DM plant and one WM plant, and
showed that utility and chemical costs do not vary with plant size.
Fixed costs and capital charges were larger for smaller plants.[81]
For this analysis, cost estimates from these studies were separated by
plant size, large (greater than 30 MMgal/yr) or small (less than 30
MMgal/yr), and by process, dry mill or wet mill. The costs, excluding
feedstock and byproduct credits, were then escalated to 1989 dollars, using
the economic parameters that are discussed in Appendix 4-A. (All costs
4-51
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discussed henceforth in this section will be in 1989 dollars.) The DoA
(1988) reference was a survey of currently operating plants. The averaged
operating costs of the plants were added to the investment costs
determined by the DoA for various plant configurations to better compare
to the other references. Cost details for each plant in the reference are
shown by plant size in Tables 4-19 and 4-20. The range of final production
costs, using manufacturing costs in 1989 dollars and original feedstock
costs, and regardless of plant size, configuration or process, was $0.87-
2.42/gal. This analysis will attempt to explain the differences among the
analyses, and, using the information on costs, etc., in these studies,
determine a cost estimate for a large, efficient ethanol plant. As will be
discussed, it is likely that future ethanol plants will have to be large and
efficient in order to profitably meet an increased ethanol demand. As per
the referenced studies, expenses were grouped as feedstock costs, operating
costs (including fixed and variable expenses), and capital charges, and
reported as dollars per gallon of ethanol ($/gal).
It should be noted that ethanol producers regard information on
production costs, including energy use, processing, and capital expenses, as
proprietary, even though the process and equipment required for
producing ethanol are well known. For illustration, in the DoA studies,
ethanol producers gave information to a third party and, while the data
was verified by follow-up site visits and telephone calls, no individual data
was presented, even on an anonymous basis.[24,82] However, because the
process and equipment are known, reasonable estimates can be made for
energy requirements and overall costs.
i. Net Corn Costs
All studies used a "net corn" cost (NCC): corn cost minus byproduct
value, divided by the ethanol yield. This is the most important variable
cost factor.[82] Com prices ranged from $1.59 to $3.16 per bushel (bu)
during the 1981 to 1988 period, with an average of about $2.50/bu. Some
of the referenced analyses used the corn cost at the time the analysis was
prepared while others used an average value. For standardization, corn
costs of $2.50/bu and $3.00/bu were used in this analysis. Even though
current corn prices are lower than this, it is expected that an increased
ethanol demand would increase corn prices.[26] Additionally, Department
of Agriculture target prices for corn, which affect income deficiency
payments to farmers, have been at or near these levels.[78]
Corn can be processed to ethanol by either a wet mill (WM) or dry
mill (DM) process. About 60-65 percent of operating ethanol plants use
4-52
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Tafck 4-19
luge Elh—10I Ptanu (> 30 MMmI/vt>
Rdnan
Data Yew
DoA(19W)
1987
API
1988
Amoco Kcnn
1983 19*7
Kelly
1987
Kelly
1987
Kelly
1987
DoA
Tool Opeming
-diy mil (DM)
-wet anO (WM)
(VM>)
> 30
Muc
(LSI
30-60
New
OJO
OJO
30 120 80 70
Now Revamp-WM HFCS-WM New-DM
0J4
0J2
60
Now-DM
033
60
New-DM
048
120
New-DM
043
0.18
030
036
hvooaenl
(*(•l/yr)
Add-00
Revamp
New-DM
New-WM
1.10-1.65
IS2-Z30
120-2.75
2:20-2.73
2j63
3jQ2
1.65
1-87
248
248
Ciftil Cbaige
AJd-on
Revamp
New-DM
New-WM
0.21-0-32
032-0l42
0.42-0.53
O42-0J3
0.48
0J3
043
OJO
043
048
Oj63
OJl
0 43
Oj65
Total (exel feed)
(Wgal)
Add-on
Revamp
Ncw-DM
New-WM
0 72-0 83
0.87-093
093-1 04
093-1.04
0.98
IjM
057
|JQ2
063
0.66
058
099
0.86
091
Frcrtimck Coeti (unwliuaetti
Cemcaat-DM
-WM
2,73
2 73
2-50
2-30
lJtO
235
233
2-30
1-50
1M
BPCC-DM
-WM
(percent)
31
64
44
39
43
33
33
67
60
65
61OH YicU-DM
-WM
(Gal/bui
2J3
2J3
2-33
2-30
2-60
2-50
2.30
2-50
2.43
2-50
Net Cora Cosi-DM
-WM
0.33
039
0.33
041
038
063
063
033
0.24
033
Manufamumg + Net Com Con (S/g&l)
Add-on
Revamp
Ncw-DM
New-WM
1.31
143
1.52
1 43
0J7
099
087
136
162 149
I 13
-------
Table 4-20
Small Ethanol Plants (< 30 MMgal/vr)
Reference
Data Year
DoA(1988) Amoco Keim Kelly DoA(1986)
1987 1985 1987 1987 1985
Capacity (MMgal/yr) < 30
Plant Type Misc
10 20 10 10
New-DM New DM New-DM New-DM
Manufacturing Costs (indexed to 1989 S)
0.54
Total Operating ($/gal)
-dry mill (DM)
-wet mill (WM)
Investment (S/gal/yT)
Add-on
Revamp
New-DM
New-WM
Capital Charge ($/gal)
Add-on
Revamp
New-DM
New-WM
Total (excl feed) ($/gal)
Add-on
Revamp
New-DM
New-WM
Feedstock Costs (unadjusted)
Corn Cost-DM ($/bu)
-WM
BPCC-DM (percent)
-WM
EtOH Yield-DM (Gal/bu)
-WM
Net Com Cost-DM ($/gal)
-WM
Manufacturing + Net Com Cost (S/eaH
Add-on
Revamp
New-DM
New-WM
1.11
4 65
0.76
1.87
2.50
44
2.55
0.55
2.42
0.43
47
0.51
3.30 3.30
0.86 0.86
1.29 1.37
2.75 1.40
45
2.60 2.50
0.56 0 31
1.85 168
0.71
0.80
1.51
2.35
33
2.50
0 63
2.14
DoA(1986) Keim
1985 1987
20 10
New-DM Add-on WM
0.56
0.66
1.22
2.35
33
2.50
0 63
1.85
0.33
1 10
0 29
0.62
2.40
60
2.50
0.38
1 00
-------
wet mill processing.[79,23] The two processes produce different
byproducts: the wet mill process yields corn gluten feed (CGF), corn gluten
meal (CGM), corn oil and carbon dioxide; the dry mill process yields
distiller's dried grains plus solubles (DDGS) and carbon dioxide. The market
values of CGF, CGM, and DDGS and corn oil are used in determining net
feedstock costs. The CGF, CGM, and DDGS compete as animal feeds, with
each other and with soybean meal. The market values of these animal
feeds are based on their protein content. That is, the price per pound of
protein is approximately the same, but more pounds of a feed with a lower
protein content are required for a given application. Shipping costs may
also increase the total price of one feed over another.[82] In the referenced
studies, the Jiyproduct value as a percent of corn gost (BPCC) ranged from
33-51 percent for DM processing and 59-67 percent for WM processing.
The BPCC in recent years has inversely followed the cost of corn, decreasing
as corn cost increased, or vice versa. The 1981-1988 BPCC versus corn cost
for DM and WM byproducts (including corn oil) are shown in Figure 4-1. In
Figure 4-2, the linear regression lines of BPCC versus corn cost are shown.
The regression equations are as follows:
DM: BPCC = 92.48 - 17.37*(corn cost) r = 0.81
WM: BPCC = 103.45 - 19.00*(corn cost) r = 0.88
Wet mill processes have a lower net corn cost than dry mill processes
because the market value of corn oil is included. Based on the 1981-1988
data, without the added corn oil value, the WM BPCC would be less than or
equal to the DM BPCC and the NCC from both processes would be about the
same.[24,82] The net corn cost (NCC) can be estimated by the following
equations:
NCC = (corn cost) - BPCC*(corn cost)
DM: NCC = 0.0752*corn cost + 0.1737*(corn cost)**2
WM: NCC = -0.0345*corn cost + 0.19*(corn cost)**2
Minor variations in the values used for byproduct yields (e.g., lbs
DDGS/bu corn) have little affect on net feedstock cost. The above
relationships of BPCC to corn cost are subject to change should market
factors affecting the byproducts change. For instance, with an increased
ethanol demand, and thus increased production, com exports would fall due
to the higher price of corn.[26] In an unrestricted export market,
byproduct feed exports would increase because their price will drop
relative to com.[26] Net corn costs may then increase or decrease,
depending on the changes in com cost and byproduct value. However, the
European Community, which is the largest export market for the gluten
4-55
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100
80
60
40
A
El
M
20
S
980 1981 1982 1983 "1984 T985 " 1986 1987" 1988"
Year
H DM
Raw Data from Reference [8j
A WM
X Corn Cost {$/bu, right axis)
-------
100
- A
1.5
2.5
Corn Cost ($/bu)
M DM A WM DMcalc WMcalc
Raw Data from Reference (8]
-------
feeds, has recently considered taxing these byproducts. This would reduce
exports and decrease the value of the byproducts, resulting in an increase
in net corn cost and the cost of ethanol production.[24]
Ethanol yield (gallon per bushel of corn) also varied slightly in the
references. Typically, the yield from a dry mill plant is 2.6 gal/bu and
from a wet mill plant 2.5 gal/bu, because in the WM process some starch is
removed with the byproducts, and less converted to ethanol.[23] Some
analyses used an average value of 2.55 and some use slightly lower values
of 2.50 and 2.45, respectively, for dry and wet mill. These variations do
not affect net feedstock cost significantly. While future technological
advances may eliminate the slight difference in yield for the WM and DM
processes, for standardization in this analysis, ethanol yield was set at 2.6
and 2.5 gal/bu for the DM and WM processes, respectively.
Corn costs used in the referenced studies for DM plants ranged from
$1.40-2.75/bu, and BPCC from 33-51 percent. Using standardized corn cost,
BPCC, and ethanol yield, the net feedstock cost for DM plants is $0.49 and
$0.69/gal at $2.50 and $3.00/bu, respectively. This assumes BPCCs of 49
and 40 percent, respectively. The original range was $0.31-$0.63/gal, as
shown in Tables 4-19 and 4-20. For WM plants, the referenced studies
used corn costs ranging from $1.50-$2.75/bu and BPCC of 59-67 percent.
Using standardized corn cost, BPCC, and ethanol yield, the net feedstock cost
is $0.44 and $0.64/gal at $2.50 and $3.00/bu, respectively. This includes a
BPCC of 56 and 46.5 percent, respectively. The original range was $0.22-
$0.41/gal. The NCC of $0.64/gal at $3.00/bu is outside the original range of
the referenced studies because of the high corn cost and low BPCC used
compared to those of the referenced studies.
ii. Operating Cost
Operating costs as shown in Tables 4-19 and 4-20 include the cost of
fuel (for steam and electricity), chemicals, and payroll. The range of
operating costs for large DM plants was $0.33-$0.54/gal. For large WM
plants, the range was $0.18-$0.52/gal, the lower values representing
studies where cogeneration of electricity was specified. Most wet mill
plants cogenerate their own electricity; this results in significant savings
since purchased electricity can cost 4-5 cents more per kilowatt-hour
(kwhr) than cogenerated electricity.[79,23] The type of fuel used to
produce the steam also affects operating costs. For example, the cost of
steam from a high-sulfur coal is about $1.72 per 1000 lb of steam while it
is $2.44 for natural gas-fired boilers.[23] This variance can change,
however, since coal can vary in cost due to grade and/or shipping costs.[79]
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Some analyses found certain operating costs to be the same for DM
and WM plants while others found definite differences. For instance, API
estimated that processing costs (including chemicals, energy, and labor)
were uniform for both processes at about $0.50 per gallon.[80] On the
other hand, Amoco found chemical costs vary with the process: $0.04 per
gallon for WM, $0.13 for DM.[81] Even in the same plant configuration,
estimates of certain operating costs varied. DoA (1986) found that energy
costs were equal for all plant sizes from 10-120 MMgal/yr, but that
unidentified direct and indirect costs and capital charges did not level off
until a capacity of 40-60 MMgal/yr was reached, as shown in Figure 4-
3.[26]
As shown in Table 4-19, energy costs for large coal-fired plants
ranged from $0.09-$0.24/gal. The DoA survey average was $0.17/gal.[26]
WM plants that used cogeneration of electricity had total energy costs of
about $0.09/gal. Total miscellaneous costs for grassroots plants (including
chemicals but excluding energy) ranged from $0.18-0.45/gal. A revamped
WM plant using cogeneration had miscellaneous costs of $0.09/gal; for a
combined HFCS/ethanol plant, these costs were $0.11/gal.[8023]
For small DM plants, energy costs ranged from $0.09-0.24/gal, as
shown in Table 4-20. The DoA survey average was $0.18/gal. Total
miscellaneous costs (including chemicals but excluding energy) ranged from
$0.27-1.02/gal. The $1.02/gal figure from Amoco's analysis was very high,
as large as many of the estimates of the total cost of producing ethanol.
However, the reason for this high cost was not identified, so it was excluded
from further analysis.[811 Excluding this value, the range was $0.27-
$0.47/gal. Total operating costs were then $0.43-$0.71/gal. The DoA
survey average was $0.54/gal. The lone small WM plant, a 10 MMgal/yr
add-on, had total operating costs much lower than the average,
at$0.33/gal.[23]
Because the published details of each analysis varied, direct
comparison of specific operating costs was not possible. In order to
estimate the operating costs of a large, efficient plant, it was assumed that
cogeneration of electricity was utilized, resulting in a total energy cost of
$0.09/gal. Operating expenses other than energy ranged from $0.09-
$0.45/gal; an average of the range extremes, $0.27/gal, was used. Thus,
total operating cost for a large, efficient plant will be estimated at about
$0.36/gal. Although this is lower than the average operating cost of
$0.54/gal in the DoA survey, it is expected that new plants, whether
additions or grassroots, will be highly efficient, resulting in lower costs.
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Figure 4-3 Ethanol Production Cost Data
Dept of Agriculture (1986) [5]
20
1985 data indexed to 1989$
_i .
40
~ Energy
_ i..
60
80
100
Ethanol Plant Size (MMgal/yr)
O Direct a Indirect x Capital
120
-------
iii. Capital Costs
Capital costs vary by the type of production facility, that is, whether
the plant is built new (grassroots), as a stand alone facility, is added
capacity to an existing plant, or is a revamped idle ethanol or other
industrial plant. Keim compared three plants and found that investment
costs ranged from $1.10 per annual gallon for an add-on to $3.30 for a
small grassroots facility.[23] This range was indicated in most studies. The
DoA (1988) went further and estimated that upgraded or modified plants
may have capital costs of $1.10-1.65 per gallon; revamped idle plants,
$1.92-2.20 per gallon; new, large plants $2.20-2.75; and new, smaller plants
(<40 MMgal) $3.30.[24] DoA (1989) noted that capital charges increase
$0.13/gal if the operating level drops from 100 percent to 75 percent, and
that, while most large plants exceed rated capacity production, most
smaller plants probably could not maintain 75 percent operation over the
life of the plant. It is uncertain if plants with investment costs of $3.30
could be profitable.[82]
Total capital charges (including maintenance, taxes, insurance,
interest, and depreciation) ranged from $0.43-$0.65/gal for large plants,
and $0.66-$0.86/gal for the small DM ($0.29/gal for the small WM add-on).
Most of these used 6 percent of the capital investment for annual
maintenance, administration, insurance and taxes (MAIT) and 20 percent
for interest and depreciation. EPA uses the same percentage for MAIT, but
uses an annual capital recovery rate (CRR) for biomass-based plants of
16.63 percent, as discussed in Appendix 4-A. Applying this factor (plus the
6- percent MAIT) to the DoA breakdown of investment costs results in
capital charge estimates of $0.25-$0.37/gal for an add-on, $0.43-$0.50/gal
for a revamped plant, and $0.50-$0.62/gal for a new plant.
The maximum total capacity that can be added to current ethanol or
nonethanol plants is about 1.25 billion gallons. Abandoned, usable sites
potentially can increase total capacity by 0.75-3.5 billion gallons, but more
practically, will add 1-2 billion. Only the best of the abandoned sites will
have economic advantage over new facilities.[82] New construction could
add 1.75-3.75 billion gallons, but would be limited to geographical areas
where favorable local conditions exist.[24] Thus, the greatest increase in
capacity will likely be add-ons. Where add-ons can be added to an HFCS
facility, the costs can be shared between the two processes, although,
according to Kelly, it is the ethanol production (and the efficiency of the
WM process) which lowers the cost of the HFCS process, not vice versa, and
ethanol will cost less to make in a dedicated ethanol plant than in a
combined ethanol/HFCS plant.[79] This may be because utilizing the
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ethanol capacity in the winter when HFCS demand is lower brings in a
higher rate of return than utilizing the HFCS capacity alone.[24]
iv. Technological Improvements
Technological improvements in the corn-to-ethanol industry may
reduce production costs in the future, although the magnitude of such a
reduction is unknown. Research is under way in bioengineering and
genetics areas to increase the starch and sugar content of corn and to
develop bacteria which can ferment sugar to ethanol. In the plant,
improved separation of solubles will reduce the energy required for
distillation and dehydration. The rate at which further technological
advances are made will, of course, depend on the demand for ethanol and
the financial feasibility of producing it from corn.
v. Conclusion
Estimates of the cost of ethanol production from corn are not easily
made because of the diversity of the corn-to-ethanol industry. By
combining data from several studies of the cost of production from plants
of various sizes and configurations, an estimate can be made for the cost of
ethanol production in a large, efficient plant, as shown in Table 4-21. At a
corn cost of $2.50/bu, the total cost of ethanol production ranged from
$ 1.05/gal in a WM add-on facility to $ 1.47/gal in a new DM plant. At
$3.00/bu, these costs are $1.25 and 1.67/gal. In these calculations, plant
location and transportation costs are not considered (distribution costs are
discussed in the next section). A plant near a feed source will have lower
feed transportation costs, but markets for the finished ethanol may not be
as close, which would increase the final cost.
Plant size is also an important factor. The capacity of plants in use
today ranges from 0.5 to 275 MMgal per year.[78] Currently operating
plants include DM plants ranging from 0.5-95 MMgal, WM/HFCS plants
from 40 to 255 MMgal, and two stand alone plants of 6 and 70 MMgal.[79]
DoA (1986) estimated that production costs (excluding feedstock) for a 10
MMgal plant are 45 percent greater than for a 40 MMgal plant, and 16
percent greater for the 40 MMgal plant versus a 100 MMgal plant.[26] Part
of this variance is due to the fact that small and midsize plants can have
operating costs 5-10 cents per gallon greater than large plants; most small
plants do not cogenerate electricity and have higher personnel costs
Currently, large plants are those greater than 40 MMgal; for an expanded
industry, this will need to be 90-100 MMgal.[24] Additionally, some
experts say that to be profitable, plants will have to be about 100
4-62
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Table 4-21 Cost of Production of Ethanol from Cora
in a Large, Efficient Plant
Net Corn Cost ($/gal)
Operating Cost (S/gal)
Capital Cost ($/gal)
Add-on
Revamp
New
Total ($/gal)
Add-on
Revamp
New
Corn Cost Maximum
Potential
$2.50/bu $3.00/bu Capacity
(bil gal)
DM WM DM WM [2]
0.49 0.44 0.69 0.64
0.36 0.36 0.36 0.36
0.25-0.37 0.25-0.37 0.25-0.37 0.25-0.37
0.43-0.50 0.43-0.50 0.43-0.50 0.43-0.50
0.50-0.62 0.50-0.62 0.50-0.62 0.50-0.62
1.10-1.22
1.28-1.35
1.35-1.47
1.05-1.17
1.23-1.30
1.30-1.42
1.30-1.42
1.48-1.55
1.55-1.67
1.25-1.37
1.43-1.50
1.50-1.62
1.2
2.7
1.9
-------
MMgal/yr.[79] • Future cost of ethanol from corn will be determined largely
by feedstock costs, possible technological improvements, and changes in the
cost of doing business (e.g., interest rates, etc.).
b. Cellulosics
Most of the currently available work on the production of ethanol
from cellulosic material has been done through the Solar Energy Research
Institute (SERI).[85,86,25] There are four main approaches for converting
lignocellulose to ethanol: separate hydrolysis and fermentation (SHF),
simultaneous saccharification and fermentation (SSF), direct microbial
conversion (DMC), and acid hydrolysis (AH). The first three are all
enzymatic hydrolysis processes and all relatively new technologies. AH is
an older, more understood process. AH, however, can degrade product
sugars before they are fermented. Enzymatic hydrolysis, on the other
hand, can achieve hydrolysis without destroying the sugars. Thus, AH is
likely only as a near term option. Of the three enzymatic processes,
detailed cost analyses are currently available only for the SHF and SSF
technologies; those analyses are presented here. SSF is currently the least
costly of the two, and costs are expected to decrease further as the
technology develops.
The four major steps in SHF and SSF are pretreatment, enzyme
production, hydrolysis and fermentation.[31 ] SHF involves sequential
enzyme production, hydrolysis, and fermentation. As its name implies, SSF
consolidates the hydrolysis and fermentation into one step. Wright's
estimated overall cost of production for a 25 MMgal/yr plant by SHF, in
1989 dollars, is $2.95 per gallon while the SSF cost was $1.96. The
breakdown of these figures is shown in Table 4-22. According to Wright,
"the high cost of the SHF process is traceable to the inhibition of the
enzymes by the product sugars. Yield and concentration are lower than
desired because the sugars have essentially stopped the reaction before it
could proceed to completion." In SSF, the glucose is fermented to ethanol
as soon as it is produced, preventing inhibition. Because yield is higher,
less feedstock is necessary, hence, feedstock costs are lower. Enzyme
production in SSF is less expensive than in SHF because high loadings are
not necessary to overcome the inhibition. Utilities are also less costly due
to higher yield; the subsequent distillation and waste treatment costs are
low due to high sugar concentration.[84] Capital costs are lower in SSF
because the hydrolysis and fermentation are carried out in the same vessel.
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Table 4-22
Cost of Ethanol Production from Lignocellulose
(cents/gal)
Process* SHF SSF
Feedstock--Wood 82.1 68.4
Operating Costs:
Chemicals 6.4 6.0
Utilities 0.9 0.6
Labor 14.5 8.5
Overhead & Maintenance 68.9 40.6
Total Operating 90.7 5 5.7
Capital 121.9 71.5
Total Cost 294.7 195.6
Raw Data from Reference [84)
* Annual Ethanol Production = 25 MMgal/yr
A sensitivity analysis found that yield is the most important process
parameter affecting the final cost of production. The next most important
factors (all less than half as important as yield) were ethanol concentration,
rate of reaction, enzyme cost, and agitation.[84] Enzymatic hydrolysis costs
will be further reduced by improved enzyme production and product
concentration.[25] Xylose fermentation of wood feedstocks can reduce
ethanol cost by 25 percent; use of herbaceous feedstocks can further reduce
cost. If the lignin is processed to methyl aryl ether, the potential exists to
produce ethanol for less than $ 1.00/gal by taking a credit for byproduct
production and sale.
A DOE White Paper presented cost data for ethanol from cellulosic
biomass assuming use of the advanced technologies previously discussed
(including lignin conversion, although whether the SHF or SSF process was
used is not specified) under several scenarios of funding for research and
development of ethanol from cellulose.[86] The business-as-usual (BAU)
scenario (maintenance of current funding levels for renewable energy
technology development) is presented in Table 4-23. Although there are.
4-65
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of course, uncertainties in these values, the numbers indicate the
magnitude of the expected decrease in the cost of ethanol production
($ 1.32/gal in 1990 to $0.55/gal in 2020) from lignocellulose feedstocks as
the technology develops. Under the Research, Development and
Demonstration (RD&D) Intensification scenario discussed in the White
Paper, which assumed an increase of 250 percent in funding for R,D,&D, it is
estimated that ethanol from biomass will attain the $0.55 per gallon cost as
early as 2000.
Table 4-23
Projected Future Cost of Ethanol from Lignocelluloser861
Ethanol Costs (@75 MMgal/vr)
1990
2000
2010
2Q20
Capital (Million $/yr)
172
129
99
90
O&M (Million $/yr)
47
46
41
27
Feedstock (Million $/yr)
27
22
U
22
Final ($/gal)
1.32
0.99
0.76
0.55
c. Overall Conclusion
Increased ethanol demand due to the use of neat ethanol fuel or high
ethanol-content blends (i.e., greater than 85 percent) will require additional
production capacity. Ethanol production cost using corn as the feedstock
can be as low as $1.05/gal (at $2.50/bu) when the additional capacity is
obtained by increasing the total capacity of current plants. However, the
cost of ethanol from a new plant could be as great as $ 1.47/gal (at
$2.50/bu). Net corn cost (a function of corn cost and byproduct values) is
the most important variable in this type of cost accounting. The current
cost of ethanol produced from cellulosic materials using the most advanced
technology is about $1.96/gal. This price is estimated at a production
capacity of 25 MMgal/yr. Provided that scale-up to larger capacities is
successful, technological advances should yield ethanol costs of less than
$1.00/gal by 2000. It should be noted that EPA's Office of Research and
Development is also considering the many factors associated with ethanol
production from biomass in their "Draft Alternative Fuels Research
Strategy." Such factors include changes in C02 emissions, energy
efficiency, use of marginal land and the associated ecological effects, and
increased acetaldehyde emissions.
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2. Fuel Distribution/Infrastructure Costs
Most domestically produced ethanol from corn is produced in the
central U.S., near the feedstock; almost 60 percent of current operating
production capacity is in the major corn-growing states of Illinois and
Iowa.[79] Currently, ethanol for use in gasohol is shipped by rail or truck,
and most is sold in the Midwest. Shipping by pipeline, however, is the
least expensive method for fuel transport, and would be desirable for an
expanded ethanol program. Shipment of ethanol in pipelines does require
special precautions to prevent fuel contamination and to eliminate water in
the pipeline..[87] While it is expected that this facet of ethanol shipment
can be addressed technologically, the costs to do so are unknown. {Also,
storage tanks at terminals and service stations, if previously used for
gasoline, would have to be cleared of water and scale (ethanol as a solvent
would remove the scale, causing fuel contamination). This currently is
standard practice for marketers of gasohol.)
Ethanol plants in the Midwest are located near pipeline routes which
run from Texas and Oklahoma through the Midwest to the East; none run
out to the West or South, though. Additional pipelines would be required to
connect to those pipelines serving ethanol markets outside the farm states.
[87] Ethanol should be fungible (i.e., able to be drawn from two different
pipelines with no discernable difference) because it is a uniform product.
In a scenario of increased ethanol demand, capacity will be increased
through additions to current plants, revamping of closed ethanol or
industrial plants or construction of new facilities. New facilities will be
constructed only where profitable situations exist; this type of situation
would most likely be near the feedstock source in order to minimize
feedstock shipping costs (to the extent compatible with other factors). It is
expected, though, that most of the increased demand will be handled by
expansion of current plants because of the increased capacity potential and
low cost, as discussed above. Thus, this will keep most of the ethanol
capacity in the Midwest.
As in the EPA's Special Report on Ethanol, it will be assumed that for
a large ethanol program, enough incentive exists for pipeline companies to
make the adjustments necessary for ethanol pipeline shipment.[87 ]
Assuming also that no penalties are charged to ethanol relative to gasoline
for the same transport mode (barge, truck, rail), the base distribution costs
of ethanol will be approximately that of gasoline. Currently, the nationwide
average cost for long range and local distribution of gasoline is $0.06/gal.
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An additional cost will be incurred for ethanol distribution because of
the additional quantity of ethanol required due to its lower energy content
relative to gasoline. However, the ultimate fuel economy (in miles/gal) is
affected not only by energy content, but also by the vehicle efficiency. A
detailed discussion of this effect is presented in the Special Report.[87]
Vehicles optimized for the ethanol fuels are more efficient than non-
optimized vehicles, and less additional ethanol is required than would be
expected based only on energy content. Because optimized dedicated and
flexible-fueled ethanol vehicles have efficiency improvements of 30 and 5
percent, respectively, over conventional vehicles vehicles, the overall fuel
economy for a dedicated vehicle is about 87 percent of the fuel economy of
a gasoline vehicle; the corresponding value for ethanol FFVs is 72 percent.
This corresponds to approximately 17 and 37 percent more ethanol volume
required on a gallon per mile basis. This increased volume would require
more frequent fuel drop-offs (deliveries) from storage tanks to service
station which in turn would entail more tank trucks and drivers (using
optimized routes for delivery only to ethanol stations). This additional cost
was estimated in the Special Report as $0.0013-0.0026/gal, not including
labor or truck operating costs.[87] Increased storage capacity may also be
required, due to the increased volume of ethanol required. Actual changes
in the distribution system depend on the percent of vehicles using the
ethanol fuels and on the percent of service stations carrying these fuels.
In a geographically dispersed alternative fuels program, such as that
considered under Scenario 3, ethanol cannot be distributed via the pipeline
system. The available modes of fuel transport are then truck, barge and/or
rail. The costs associated with these modes will increase the distribution
costs of E100 and E85 considerably.
In order to calculate these increased distribution costs for a dispersed
program, assuming displacement of one million gallons of gasoline per day,
the nation was divided into roughly six groups: West Coast, West Central,
Mississippi/Ohio River area, Great Lakes, and East Coast/East Central. Total
average miles from the Iowa/Illinois area to each region were 2000, 1200,
1000, 300, 300, and 700 miles, respectively. Ethanol was assumed to be
trucked at least 100 miles of the total distance. For the West Coast and
West Central areas, rail transport was assumed; for the Mississippi/Ohio
River area, barge; and for all others, a combination of barge and rail.
Summing costs and dividing by the total volume of Scenario 3 resulted in
distribution costs of approximately $0.18/gal ethanol. Thus for ethanol not
shipped by pipeline, distributions costs may be three times as great as
those reported above.
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Additionally, with the more geographically dispersed distribution of
ethanol in Scenario 3 compared with Scenario 2, an individual service
station's sales would decrease by approximately 25 percent.[66,67] Since a
service station would incur certain fixed costs (capital and administration),
the price per unit of fuel due to amortized fixed costs would increase
somewhat. The increased pump markup cost for Scenario 3 versus Scenario
2 was estimated to be approximately SO.Ol/gallon.[87,69]
However, for a focused program, and for the analysis presented in
this report, the long range and local distribution cost for neat ethanol will
be $0.06/gal plus $0.0013-0.0026/gal for extra trucks, for a total of
$0.0613-0.0626/gal. For E85, the gasoline distribution cost must be
factored in at a 15 percent level, for a final distribution cost of $0.0611-
0.0622/gal. On a dollar per gallon gasoline equivalent basis (including the
energy content of ethanol and vehicle efficiency of optimized vehicles), this
cost will be about $0.0716-0.0731 /gal for E100. For E85, including gasoline
costs at 15 percent and at an efficiency of 1.0, the gasoline equivalent
distribution cost is $0.0806-0.0821 /gal.
Production of ethanol from cellulosic materials also may present
unique transportation situations depending on the location of the feedstock.
Many cellulosic feedstocks can grow on land which is marginal for
conventional agricultural uses and which may also be somewhat
inaccessible, for instance, trees grown in the eastern or western
mountainous states. Assuming the processing plants are located near the
feedstock, the more expensive modes of ethanol transport (i e., non-
pipeline and non-barge modes) may then be required.
Taxes for ethanol and gasoline are assumed to be equivalent on an
energy basis, 16 cents per gallon for E100 and 17 cents per gallon for E85.
This does not reflect expected increases in fleet average energy efficiency
due to the introduction of high-efficiency E100 vehicles, however. As tleet
energy efficiency increases, taxes (on an energy basis) would have to
increase to create a "revenue-neutral" program. Any increased taxes would
likely be allocated to gasoline and ethanol equally on a Btu basis, however.
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3. Vehicle Efficiency and Cost
a. Efficiency
Ethanol's combustion properties, such as higher octane, which allows a
higher compression ratio; wide flammability limits, which permit good
combustion at high air-to-fuel ratios; and a higher power output, which
allows the use of a smaller, more efficient engine, makes it an inherently
more efficient fuel than gasoline. A dedicated vehicle optimized for ethanol
combustion could yield an efficiency benefit of 30 percent over gasoline
vehicles, due to the improved combustion and the fact that a dedicated
vehicle would be optimized for size, weight, and performance. Flexible-
fueled vehicles using current technology could gain 5 percent efficiency
over gasoline vehicles due to ethanol's improved combustion properties.
Use of an optimized vehicle fueled with neat ethanol should allow use
of a smaller, lighter engine which delivers the same power as the gasoline-
fueled engine it replaces. The weight saved in the lighter engine allows a
lighter vehicle structure and suspension as well. The resulting vehicle will
have equivalent power and weigh less than the vehicle it replaces,
therefore yielding better performance.
b. Vehicle Cost
In developing an ethanol vehicle there are several factors leading to
both cost savings and increases. Reductions in emission controls, engine
cooling system, and engine size will result in cost savings. Fuel system
modifications will lead to cost increases. A cold start assist system may be
necessary, further increasing costs. Considering both cost savings and
increases, EPA assumes that there will be no overall cost difference
between dedicated ethanol vehicles and gasoline vehicles. For a flexible
fuel vehicle operating on various fractions of gasoline and ethanol, not all of
the cost savings discussed above are possible. In addition, a fuel sensor is
required in an FFV. EPA has developed a cost estimate of up to $300 extra
for an ethanol FFV produced at high volumes.[87] This equates to a cost of
0.5 cents per mile, amortized over the life of the vehicle. Vehicle
maintenance costs for both dedicated and flexible fuel ethanol vehicles are
expected to be comparable with those for gasoline vehicles.
4. Ethanol Pump Price
Table 4-24 presents the projected gasoline equivalent, efficiency
corrected pump price for E85 in the years 2000 and 2010. As the table
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shows, E85 using ethanol made from corn is expected to cost $2.37 per
gallon gasoline equivalent in 2000, and $2.64 per gallon in the year 2010.
Ethanol from biomass would yield E85 at pump prices of $1.80 per gallon in
2000 and $1.56 per gallon in 2010, if DOE's projections regarding
technological advancements in the conversion of cellulosics to ethanol are
realized.
Table 4-24
E85 Pump Price Comparisons
3QQQ
2010
Com1 Biomass2 Corn1 Biomass2
Production Price
($/gallon E85)
Distribution Costs^
Serv. Station Markup4
Taxes
1.03-1 39
0 98
1 23-1.59
0 81
0 06
0.06-0.08
0.17 -
Total Pump Price ($/gallon)^
Gasoline Equivalent Ratio
Efficiency Correction Factor
1.32-1.70
1.27-1 29 1.52-1.90
1.42
0 98
1.10-1 12
Gasoline Equivalent Price
($/gallon)
2.37
1 80
2.64
1 56
!The prices in 2000 are based on com feedstock costs of $2.50 per bushel, and in 2010
on a cost of $3.00 per bushel, based on the feedstock information presented in
Appendix 4.
2Biomass costs are based on DOE projections as discussed in Section l.b.
3 Under a geographically dispersed program, distribution costs would be $0 18 per
gallon gasoline equivalent.
4 Under a geographically dispersed program, markup would be an additional
$0.01/gallon.
^Total pump prices do not include the current Federal tax credit of $0.60 per gallon
denatured ethanol used (provided the ethanol was produced from a non-fossil fuel
renewable feedstock).
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The projected pump prices for El00 are presented in Table 4-25. As
shown, E100 made from corn is expected to cost $2.04 per gallon gasoline
equivalent in 2000 and $2.27 per gallon gasoline equivalent in 2010. E100
made from biomass could cost $1.49 per gallon in 2000 and $1.22 per
gallon in 2010.
Table 4-25
E100 Pump Price Comparisons
2000 2010
Corn1 Biomass2 Corn1 Biomass2
Production Price ($/gallon) 1.05-1 47 0 99 1 25-1 67 0.76
Distribution Costs^ 0 06
Serv Station Markup** 0 06-0.08
Taxes 0 16
Total Pump Price ($/gallon)5 1 33-1 77 1 27-1 29 1 53-1 97 1.04-1 06
Gasoline Equivalent Ratio 1.5
Efficiency Correction Factor 0.77
Gasoline Equivalent Price
(S/gallon) 2.04 1 49 2.27 1 22
^The prices in 2000 are based on com feedstock costs of $2.50 per bushel, and in 2010
on a cost of $3.00 per bushel, based on the feedstock information presented in
Appendix 4.
2Biomass costs are based on DOE projections as discussed in Section l.b. Under DOE'b
intensified R&D scenario, the production price for ethanol from biomass is projected
to be as low as $0.55 per gallon by 2000.[30] The pump price would be $0.98 per gallon
if this cost were realized.
3Under a geographically dispersed program, distribution costs would be $0 18 per
gallon gasoline equivalent.
4Under a geographically dispersed program, markup would be an additional
$0.01/gallon.
^Total pump prices do not include the current Federal tax credit of $0.60 per gallon
denatured ethanol used (provided the ethanol was produced from a non-fosstl fuel
renewable feedstock).
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D. Liquefied Petroleum Gases
LPG used for automotive engines, called HD-5 propane, has a
minimum requirement of 95 percent propane and a maximum 2.5 percent
butane and higher hydrocarbons.[45] It is produced during the refining of
oil or processing of natural gas. To bring the LPG up to HD-5 specifications
requires removal of water, butane, propylene and other hydrocarbons.
Most refiners do this as part of the refining process, so there are no extra
costs incurred. LPG from natural gas does not contain propylene, so gas
from this source requires even less processing. Because of pipeline carrier
tariff requirements, which state that pipeline LPG must have the
composition of HD-5, about 85 percent of the LPG produced in the U.S. is
automotive grade.[881
1. Production Costs
As discussed in Section I, the U.S. could supply as much as 0.61
million barrels of LPG per day by the year 2000 and 0.63 million barrels
per day by 2010 could be available for use by the transportation sector, if
LPG is made available by changes in other industries and due to RVP
reduction regulations, or enough fuel to satisfy demand under Scenario 2,
as discussed in Appendix 3. However, actual levels will probable be lower,
if refiners use the butane, as was discussed in the LPG feedstock part of
Section I.
According to EI A, the 1989 average refiner sales price for resale of
consumer grade propane was $0,246 per gallon.[48] EIA does not have
future resale price predictions for propane, however, industrial LPG prices
are projected to grow at an annual rate of 1.5 percent.[4] Applying this
same rate of increase to the current propane resale price noted above
yields future LPG price estimates of SO.29 per gallon in 2000 and $0.35 per
gallon in 2010.
2. Fuel Distribution/Infrastructure Costs
Domestic LPG is often located in the regions where gasoline is
produced. Therefore, in this analysis, the long range/local distribution cost
of LPG is assumed to be similar to that of gasoline, at 6 cents per gallon.[41]
Service station mark-up for gasoline is typically 9 cents/gallon, of which 2
cents is attributed to tankage/infrastructure and the remaining 7 cents
covers other operational costs ("overhead").[69] Assuming that LPG tankage
costs are no higher than that of gasoline (2 cents per gallon), and that
overhead costs for gasoline and LPG are equivalent on an energy basis (LPG
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overhead cost, would thus be 5 cents per gallon), the total service station
markup for LPG would be 7 cents per gallon. Road user taxes for LPG and
gasoline are also assumed to be equivalent on an energy basis, so taxes on
LPG would be 17.2 cents per gallon.
3. Vehicle Efficiency and Cost
a. Efficiency
Testing and evaluation of prototype LPG vehicles performed by EPA
indicates that the gasoline equivalent fuel economy of LPG-fueled vehicles,
on an equal performance basis, is roughly 2 to 5 percent lower.[89]
Performance tests show acceleration times up to approximately 4 percent
slower on LPG than with gasoline. The LPG fuel system also increases the
weight of the vehicle, further reducing performance. Flexible fuel vehicles
can be optimized for LPG combustion, and therefore FFV and dedicated
vehicle performance and efficiency is assumed to be similar. An efficiency
adjustment factor of -5 percent relative to gasoline was used for both FFV
and dedicated LPG vehicles in this report.
b. Vehicle Cost
Differential costs for production of LPG vehicles range from $800 for a
dedicated vehicle to $1500 for a flexible fuel vehicle. [46] Amortizing these
costs over the full life of the vehicle, a dedicated LPG vehicle will cost an
additional 1.3 cents per mile, while a flexible fuel vehicle will cost an
additional 2.3 cents per mile over the cost of a conventional vehicle. Both
Ford and Chrysler produce original equipment LPG vehicles; currently,
however, most LPG vehicles are converted from stock vehicles.
Development of optimized LPG vehicles can be expected to reduce vehicle
costs somewhat. Current literature indicates that LPG vehicles could have
reduced operation and maintenance costs compared to gasoline vehicles,
though cost reductions have not been quantified.
4. LPG Pump Price
Table 4-26 presents the projected future pump prices of LPG. LPG is
projected to cost $0.87 per gallon (gasoline equivalent) in 2000 and $0.94
per gallon in 2010 based on DOE projections of future LPG wholesale
costs.13 Although these prices are attractive compared to projected future
gasoline costs, propane prices can be quite volatile and are seasonal;
13Vehicle costs are not included in these numbers.
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therefore LPG prices could be different than those estimated here
especially under a scenario of increased demand. Limited domestic supply
of LPG makes its widespread use as a vehicular fuel somewhat doubtful;
however, limited use of LPG (fleet vehicles, state programs) could continue
to be attractive in the future.
Table 4-26
LPG Pump Price Comparisons
(Projected Gasoline Prices. $/gallon)
2000
2010
Wholesale Price ($/gallon LPG)*
0.29
0.34
Distribution Costs
0.06
0.06
Service Station Markup
0.07
0.07
Taxes
0.17
0.17
Total Price ($/gallon LPG)
0.59
0.64
Gasoline Equivalent Ratio
-1.39
Total Price ($/gal. gasoline equiv.)
0.82
0.89
Vehicle Efficiency Correction Factor
-1.053
Efficiency Corrected Price ($/gallon)
0.87
0.94
~Based on price projections from EIA/DOE.[2] LPG prices are volatile, responding to
market changes and international events. In August 1989 the price was $0.22/gallon,
by August 1990 it had risen to $0.54/gallon. Due to the Iraqi crisis, the price had risen
to $0.91/gallon by October 1990.
E Methanol
Methanol can be produced from coal, biomass, municipal waste, and
natural gas. The technologies and costs for producing methanol from each
of these feedstocks are addressed in the following sections.
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1. Production Costs
a. Coal
Coal can meet the methanol demands of any of the alternative fuel
market scenarios considered in Appendix 3. The most commercially ready
technology for the production of methanol from coal is the gasification of
coal to form a carbon monoxide (CO) rich syngas and the subsequent
reaction of the gas with hydrogen to make methanol. Some of these plants
are designed to produce methanol as the sole product, others coproduce
electricity with methanol. Sections i. and ii. will address the technology and
costs of both dedicated and coproduction methanol plants. Technological
advancements in coal gasification will be discussed in Section lii.
i. Dedicated Methanol Production
In a typical indirect liquefaction coal-to-methanol plant, coal is
ground to small particles, entrained in air or mixed with water to form a
slurry, and then gasified in oxygen.[90] A fraction of the "raw" gas formed
in the gasifier is sent through a CO shift bed where CO is hydrolysed over a
catalyst to form C02 and H2- This shift insures that the proper
stoichiometric mix of CO and H2 (1:2) is present for methanol synthesis
after the two gas stream fractions are reunited. The rest of the raw gas
from the gasifier bypasses the shift unit to allow the H2:CO ratio to be
controlled downstream. After the shift conversion unit, the stream
fractions are recombined and travel through an acid gas removal system
where CO2 and H2S are removed. The sweetened gas then goes to
methanol synthesis and refining, a recycle process in which the volume of
methanol produced is maximized. Some gas is purged and burned in gas-
fired boilers for steam generation and heat recovery before being
exhausted to the atmosphere.
The thermal efficiency of a typical dedicated plant studied is 55-59
percent. The main sources of energy loss are gasification, gas cooling, acid
gas removal, and methanol synthesis. Some energy loss occurs in the acid
gas removal process since refrigeration is required. However, this system,
like the rest of the plant, is designed to be very well integrated to make use
of process heat and minimize losses. For example, the Rectisol acid gas
removal unit at Tennessee Eastman's coal-to-chemicals plant, which uses
Texaco gasifiers, makes use of the Joule-Thompson effect from C02
absorption to provide over 50 percent of their cooling needs.[91] The losses
that occur during methanol synthesis are due to the compression
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requirements of the recycle loop and are lost energy with no prospects for
recovery.[92] • In general, however, current designs of this process are
highly integrated to make as much use of this energy as possible. Some
improvements could be made in the future to further improve the thermal
efficiency of these processes.
An economic comparison of four dedicated coal to methanol processes
is given in Table 4-27.[93,60] The three "proven" and one "advanced"
technologies were already scaled to the same output capacity of 50,000
OEB/day by Pletcher and McGuckin.[93] The delineation between "proven"
and "advanced" technologies was made by the authors based on processes
which were commercially or pilot plant proven at the time. Proven
technologies included gasification systems by Texaco and Koppers-Totzek.
Technologies defined as advanced include processes by Foster Wheeler,
Shell, and BGC Lurgi. All the processes use either Chem Systems, ICI, or
Lurgi methanol synthesis units, which are approximately equivalent in cost
and technical development.
Table 4-27
Production Costs of Methanol from Coal (1989S)
Process
CGasifier/Svn thesis')
Proven Texaco/
Chem Systems
Proven Texaco/
ICI
Proven Koppers-
Totzek/Chem.
Systems
Advanced
Technologies
Coal
Capacity
TPD
21,795
25,658
23,006
20,048-
26.188
Plant
Investment
SMM
2,166
2,402
3,176
2,367-
2.420
Fuel
Price
SZ&al
0.56
0.57
0.80
0.61
0.65
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As Table 4-27 shows, the Texaco gasification/Chem Systems synthesis
design is the least expensive to build and operate, with a capital investment
of $2,166 million and a methanol price of $0.56 per gallon. The most costly
design is the combination of Koppers-Totzek gasification and Chem Systems
synthesis, with a capital cost of $3,176 million and a fuel price of $0.80 per
gallon. The gasifier technology used in this design is more expensive than
the other technologies investigated ($566 million vs. less than $200 million
as quoted in the original report) which explains the higher costs.[93]
Estimates of the fuel prices from these processes in the years 2000
and 2010, based on the projected coal prices from Appendix 2, are
presented in Table 4-28. As shown, methanol price is affected only slightly
by changing feedstock prices.
Table 4-28
Projected Future Methanol Production Cost From Coal
Process 2000 2010
Proven Texaco/ 0.58 0.60
Chem Systems
Proven Texaco/ICI 0.59 0.62
Proven Koppers- 0.82 0.84
Totzek/Chem Systems
Advanced 0.64-0.68 0.66-0.70
Technologies
A recent DOE report by Chem Systems which analyzes methanol
production and transportation costs provides costs and price estimates
which may be used here for comparison with the other studies.[42]
According to this report, a dedicated methanol plant using Texaco
gasification and Chem Systems Methanol Synthesis to produce 5,000 MTPD
(about 1.7 million gallons per day or roughly 40 percent of the 50,000 OEB
per day output of the other designs studied) would cost $1,210.8 million
(1987 dollars). The price of methanol produced would be $0.77 per gallon.
Adjusting to a more consistent coal price (the DOE report assumed a price of
$35 per short ton; the 1989 average coal price which was used in this
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evaluation was SI.445 per MMBtu, which is equivalent to about $30 per
short ton) and scaling the DOE plant to produce 50,000 OEB per day
methanol would bring the methanol price down to $0.59/gallon, in the
same range as the previous figures.
Based on the preceding analysis, which presents technologies for
dedicated coal-to-methanol plants on an equitable economic basis, the price
of $0.56 per gallon was used in this report for methanol from a dedicated
plant. For future price predictions, the prices of $0.58 per gallon in 2000
and $0.60 per gallon in 2010 were used.
ii. Coproduction of Methanol and Electricity
In addition to plants which are dedicated to methanol production,
designs have also been published for coal gasification plants which
coproduce electricity with methanol. In these design studies, the methanol
is produced primarily as a fuel for load leveling during peak power periods.
However, this methanol could also find use as an alternative vehicular fuel,
particularly if the generating capacity of the plant were designed with this
alternate use in mind.
There are two major differences between a dedicated methanol plant
and a cogeneration facility. The first difference is that in a coproduction
plant the syngas created by gasification passes through the methanol
reactor only once (a "once-through" synthesis) before combustion in a gas
turbine and heat recovery in the boilers.[94] In the dedicated plant, the
syngas is recycled through the methanol reactor to maximize production ot
methanol. Since electricity is the main product of a coproduction plant, a
methanol recycle is not needed. The second difference between the plants
is that in a coproduction plant the C02 that is separated from the syngas as
part of the acid gas removal process to improve the H2:CO ratio is used
along with the fuel gases for heat recovery/steam generation instead of
being released directly to the atmosphere. Again, this is done to maximize
electricity production, since the coproduction processes are also designed to
be steam and gas turbine cogeneration facilities.
Some coproduction plant designs published by the Electric Power
Research Institute (EPRI) have one additional difference from a dedicated
plant: no CO shift unit is included.[95] If the primary product of the plant
is methanol, a CO shift and recycle is needed to maximize production, even
if electricity is also produced for export. But if electricity is the main
product, the shift is unnecessary. Although eliminating the shift means
that a nonstoichiometric gas mixture enters methanol synthesis, EPRI
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believes that this design is better than one including a shift because it is
more economical.[94] The use of the shift requires capital expenditure not
only for the catalyst bed but also for low temperature gas cooling and extra
acid gas removal capacity to accommodate the excess CO2 produced, an
increased expense of about 6.4 percent of total capital cost. In addition, the
removal of a greater volume of CO2 increases the energy requirements of
the acid gas removal system from about 3 percent to 9 percent of total
power consumed, thereby increasing the amount of coal used if the same
amount of electricity were to be exported. This additional use of energy
reduces the overall thermal efficiency of a coproduction plant from 46
percent for an unshifted design down to 41 percent for a design
incorporating a shift.[94,95]
The heat losses from a coproduction plant occur in many of the same
places that they occur in the dedicated plant. Although no recycle is used
in methanol synthesis, the combined-cycle power generation process uses
up most of the energy saved. The steam turbine condensers alone
contribute about 25 percent of the total energy lost in the plant. In
addition, the boiler stack gases released after power generation and heat
recovery are responsible for another 17 percent.[94] These losses occur in
spite of the efficient design which makes even better use of process heat
than a dedicated plant by using heat to raise low-level steam used in the
steam turbines of the combined-cycle power plant. If the coproduction
plant incorporates a CO shift, the shift and increased C02 removal can
reduce the overall plant efficiency up to 16 percent, when one considers
the electric and steam power needed for acid gas removal.
EPRI has researched coproduction plants extensively over the last 10-
20 years, partially because of their involvement in the Cool Water
Gasification Plant in California, where electricity was produced by coal
gasification. Several reports by EPRI combine Texaco gasification with ICI
synthesis and a combined-cycle electricity generation system; one of these
reports was analyzed for comparison with dedicated methanol plants.[94]
Using the economic parameters that were applied to dedicated plants, a
coproduction plant using almost 24,000 tons of coal per day to produce
4,522.4 tons per day methanol (14,067.9 OEB/day) and 2025 MW
electricity would require a capital investment of $2,358 million. The
methanol produced by this process, assuming a credit for the electricity
produced of $0.0472 per kwh (1989 average rate), would cost $0.47 per
gallon. Given coal price projections for 2000 and 2010, this methanol
would cost $0.52 and $0.59, respectively.
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According to the previously cited DOE report, a coproduction plant
using a methanol synthesis process known as Liquid Phase Methanol
(LPMeOH) designed by Chem Systems, which does not use a CO shift, would
cost $1,244.3 million in 1987 dollars ($1,369.4 million in 1989 dollars) for
the same coal feed capacity used in their dedicated plant, 8800 STPD.[42]
This design would produce 744.9 MW power and 1,238.8 metric tons per
day (MTPD) methanol. DOE estimated that methanol from this plant would
cost $0,575 per gallon; $0.41 per gallon in 1989 dollars if adjusted for the
same differences in feedstock cost that were discussed in the preceding
section. Given the projected future coal prices, methanol produced by this
plant would cost $0.47 per gallon in 2000 and $0.56 per gallon in 2010.
Coproduction of methanol with electricity will only be a viable option
for alternative fuel production if the electricity can be used to fulfill
capacity needs. If all of the announced or planned construction of coal-
based utilities were coproduction plants, enough methanol could be
produced to fulfill the needs of either Scenario 1 or 2 for the year 2000
(but not 2010). If, however, coal-based utility requirements grow at the
rate EIA projects they actually will (up to 8 times more than planned
capacity can accomodate), and this need were fulfilled by coproduction
plants, more than enough methanol could be produced to satisfy the
demand under any of the Scenarios well past 2010.[4]
For the purpose of comparing methanol prices later in this report, the
price of $0.47 per gallon, the price calculated from EPRI's design, will be
used for methanol that is coproduced with electricity. Due to rising coal
prices, the price of this fuel would rise to $0.52 per gallon in 2000 and
$0.59 per gallon in 2010.
iii. Technological Advances in Coal Gasification
In recent years, few new technologies have been developed in the
area of alternative fuel production due to the low prices of natural gas and
crude oil. However, some progress has been made in the area of coal
gasification for syngas production, with the Cool Water Project in California
producing electricity using Texaco gasifiers and the Great Plains Gasification
Project producing natural gas for sale using Lurgi gasifiers. In addition.
Tennessee-Eastman has a coal-to-chemicals plant that makes methanol as
an intermediate chemical through gasification; much information has been
gained from this process that can be applied to future coal-to-methanol
plants. Further evaluation of these advances will appear in future EPA
Reports to Congress.
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Shell Oil has developed a gasifier that uses a dry feed instead of the
water slurry used by the majority of gasifiers.[961 This process greatly
improves the thermal efficiency of the gasification section of the plant (up
to 80 percent), and, in addition, produces little C02 and maximizes CO
production. Incorporation of this gasifier into other fuel synthesis
processes may result in some cost savings and efficiency improvements.
Texaco, whose gasifier is used at the Cool Water Plant, is exploring
different feedstocks to help reduce production costs and hence the cost of
the electricity they sell. Although the use of municipal waste as a feedstock
will be addressed elsewhere in this report, it is useful to note here that one
idea under study is to gasify a slurry mixture of 75 percent coal and 25
percent sewage sludge, a concept which appears to be an economically and
environmentally sound process.[97] Another idea being explored is the use
of coal fines (coal pieces which are too small to be useful in conventional
burners) for gasification. At present there are few uses for coal fines and
typically they remain stockpiled at the mine site. The cost of coal fines is
anticipated to be $8.00/short ton (ST) or lower, compared with the current
average cost of coal of $23.00/ST.[97] If this technology can be developed,
its application to alternative fuel production could make these fuels
competitive with the current market.
b. Biomass
Methanol can be produced from biomass by indirect liquefaction in
essentially the same manner as it is made from coal. Approximately 100
gallons of methanol can be produced from 1 ton of dry biomass feedstock,
although the conversion rate may vary with the specific feedstock.[7] Table
4-29 shows an estimate of the amount of methanol that can be produced
from the biomass predicted to be available. The amount of methanol that
can be made from peat was taken from estimates presented by Sperling.[7]
The higher number in the range for wood assumes that energy farms are
used to supplement current supply. Current silvicultural methods limit
production rates of woody biomass energy farms to 10,000 tons per day
wood (yielding one million gallons methanol per day, or about 3300 tons
per day). As can be seen, sufficient quantities of methanol could be made
from biomass to satisfy demand under all three scenarios outlined in
Appendix 3.
A recent report by the Solar Energy Research Institute indicates that
methanol could be produced from biomass at a cost of $0.75 per gallon.[98]
If further design improvements are made, a cost of $0.55 per gallon is
targeted for 1995.
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Table 4-29
Estimated Methanol Production From Biomass*
Feedstock
Annual Production (million gal/vearl
Crop Residue
6,930
Forage Crops
9,010-18.020
Wood
3.465-34.650
Peat
TOTAL
0-1-39
19.405-60,990
* Adapted from Reference 5.
A study of the potential tor converting trees or grasses grown in
Hawaii into methanol presents a process for partial oxidation of the
biomass.[99] According to the Hawaii Natural Energy Institute, a plant that
converts 7,716 tons of biomass into 203 million gallons of methanol
annually would require a capital cost of $280 million. Methanol produced
by this process is projected to cost $0.60 per gallon. If hydrogen were
added to the process to improve the carbon conversion rate to 100 percent,
nearly 450 million gallons of methanol could be produced annually for
$1.06 per gallon by a plant requiring a capital investment of $355 million.
One biomass-to-methanol process is expected to be proven
commercially in the near future. This gasification/synthesis process was
designed by Infrasystems to receive up to 350 tons of wood waste daily,
gasify it using an in-house designed gasifier which can accomodate any
biomass, and synthesize the gas formed into 130,000 gallons of
methanol.[70] The methanol yield is increased 20 percent by introducing
landfill gases with the syngas before synthesis. Natural gas is used to start
up the gasifiers and provide electricity, but once the process is operational
the syngas may be used for electricity generation and natural gas usage
will be minimal. The company has received funding and will begin
construction of a plant designed for Baton Rouge, Louisiana which is
expected to cost $40 million.[33] The methanol produced by this process
has an estimated selling price of about $0.40 per gallon.
DOE recently evaluated methanol production from biomass using
"present" and "near-future" technology.[l8] The "present" technology
incorporated a Koppers-Totzek entrained-bed gasifier with a low-pressure
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methanol synthesis process. Wood was the chosen feedstock; a cost of $42
per short ton was assumed. The Koppers-Totzek gasifier operates at
atmospheric pressure and requires the wood chips to be dried to 8 percent
moisture content and reduced in size before gasification with oxygen to
produce a gas suitable for methanol production. A CO shift is required to
obtain the proper stoichiometric mixture of CO and H2. After acid gas
removal, methanol is produced in a catalytic reactor. A coal feed rate of
2000 STPD would produce about 716 tons per day methanol (87 million
gallons per year).
DOE estimated the total capital investment for this plant to be $301.8
million (1987 dollars).[18] The methanol produced was estimated to cost
$1.29 per gallon, based on calculations including a capital recovery rate of
20 percent. Escalating these costs to 1989 dollars using the same economic
bases that were applied to coal technology (and discussed in Appendix 4-
A), yields a capital cost of $332 million and a methanol price of $1.38 per
gallon.
The "near-future" technology evaluated by DOE uses a fluidized-bed
gasifier developed by the Institute of Gas Technology (IGT). This gasifier,
which has been designed for biomass but has not yet been proven
commercially, does not require the CO shift reaction. The wood chips must
be dried to 15 percent moisture and then pressure fed to the gasifier. The
syngas produced passes through a methane reformer where CO and H2 are
produced to maximize the methanol yield. An advanced technology
methanol synthesis process, such as the liquid phase methanol synthesis
(LPMeOH) developed by Chem Systems, is used to convert the syngas to
methanol.
The near future technologies were originally evaluated for two
capacity plants: a 2000 STPD feed producing about 836 tons per day (TPD)
(101.5 million gallons per year) of methanol, and a scaled up plant using
about 10,000 TPD wood to produce approximately 4500 TPD (555.6 million
gallons per year). DOE estimated that the 2000 STPD plant would cost $224
million (1987 dollars) to construct, producing methanol at a price of $0.93
per gallon.f 18] The larger plant would require an investment of $729
million, and would produce methanol for $0.68 per gallon. The price of
methanol produced by these plants is lower than the present technology
design because of cost reductions that are expected due to the ability of the
IGT gasifier to operate on larger, wetter wood chips. Escalating these costs
to 1989 dollars yields a capital cost of $246 million and methanol price of
$1.01 per gallon for the 2000 STPD plant, and $801 million with a methanol
price of $0.72 per gallon for the larger version.
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Although the feedstock cost of $42 per ton was the current price
assumed by DOE, the report also evaluated the effect of lower feedstock
costs on the price of methanol.[18] As feedstock costs were decreased, the
methanol prices dropped significantly. For a wood cost of $32 per ton, the
methanol prices were predicted to be $1.21 per gallon for present
technology, $0.88 per gallon for future technology, and $0.61 per gallon for
the large scale future design (all values in 1987 dollars for comparison with
the report's original prices with wood at $42 per ton).
All of the technologies discussed above estimate methanol production
costs within a reasonably close range of values, hence it appears that this
technology is viable and that DOE's estimates are reasonable. Based on
DOE's analysis and assuming a feedstock cost of $42 per ton, it appears that
the near future technology will be feasible by the time that an active
alternative fuels program is pursued. Therefore, future methanol costs for
a plant using near future technology to produce 4500 TPD methanol may be
estimated using DOE's projected biomass feedstock prices presented in
Section I. Based on this projection, methanol could be produced for $0.67
per gallon in both 2000 and 2010; this cost will be assumed for methanol
produced from biomass for the remainder of the report.
c. Municipal Waste
Methanol can be produced from municipal waste through indirect
liquefaction processes similar to those used for coal and biomass. The MSW
would be preprocessed into a refuse-derived fuel (RDF), which can be
gasified more readily than the raw MSW. About 1,900 pounds of MSW are
required to make 50 gallons of methanol, therefore, even a small methanol
plant, producing 12,500-25,000 gallons of methanol a day (40-80 TPD)
would require waste from a city of at least 100,000 people, based on
estimates of per capita waste generation.[7]
The PUROX gasifier, developed by Union Carbide Corporation, was
shown to be capable of handling up to 200 tons per day MSW; pairing this
with a methanol synthesis process would allow for production of methanol.
A plant incorporating a PUROX gasifier combined with an ICI methanol
synthesis process was proposed to convert a feed of 870 dry tons
preprocessed MSW per year into 25 million gallons of methanol per year (a
thermal efficiency of about 40 percent).[62] The design was estimated to
cost about $72 million (escalated to 1989 dollars); no estimate of the price
of the methanol produced was given. Union Carbide is no longer pursuing
the PUROX gasification technology; however, this information illustrates
that the gasification of MSW to produce methanol is feasible.
4-85
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The biomass-to-methanol process by Infrasystems described in
Section b has also been discussed for MSW conversion. One plant was
designed to receive 160 ton of MSW per day.[70] The process was designed
to accept wood, newspapers, or any other organic waste found in MSW.
Economic information specific to a MSW-to-methanol facility is not yet
available since Infrasystems has not been able to operate their gasifier on
MSW.
Although there are no commercial scale plants in existance at this
time, it is possible to estimate the cost of producing methanol from
municipal waste if several assumptions are made. Since gasification of
MSW has been proven feasible by the PUROX process, it is reasonable to
assume that a gasifier would be used for methanol production from
municipal waste. The gasifier would likely be similar to a biomass gasifier,
but would use RDF as a feedstock; the capital cost for the equipment should
be similar. Once the gas is generated, the methanol synthesis process
would be the same as that of a biomass plant, with similar costs. Given
these assumptions, it is possible to estimate a methanol production cost by
substituting the cost of RDF ($3.50 per MMBtu) for the cost of wood in the
biomass-to-methanol plant discussed in the previous section.
Based on the preceeding assumptions, the cost of producing methanol
from MSW is estimated to be $0.79 per gallon in both the years 2000 and
2010. As was the case for methane and electricity made from MSW, the
methanol cost is a strong function of the tipping fee; higher tipping fees in
the future would yield a lower methanol cost by lowering the feedstock
cost of the RDF. It should be cautioned that this estimate is only a rough
approximation; a more detailed analysis of the cost of producing methanol
from municipal waste will be included in the next Environmental Study.
However, these estimates can be used to compare the relative potential of
the different feedstocks for methanol production.
Given the projected availability of MSW, it would be possible to
supply methanol demand under either fuel production Scenario 1 or 2, if
most of the waste collected in the country were used for fuel production.
Obviously, the decentralized nature of this feedstock makes its widespread
use for fuel production unlikely. However, MSW could be a convenient
feedstock for methanol production in regional applications.
d. Natural Gas
Methanol is produced from natural gas using either steam reforming
or catalytic partial oxidation. Both processes require desulfurization of the
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natural gas before conversion. Steam reforming involves reacting the
methane in th"e gas with steam to produce carbon monoxide and hydrogen.
A high steam-to-carbon ratio is required to maintain catalyst efficiency,
hence the process is energy intensive. The CO and H2 synthesis gas is
reacted to form methanol in an exothermic catalytic process. Although
early designs required high pressure, ICI developed a copper catalyst that
reduced the required pressure to 50-100 atmospheres (atm) from as high
as 300 atm.
Catalytic partial oxidation, a relatively new process developed by
Davy McKee, uses a catalytic fixed-bed reactor to make syngas. Natural gas
is reacted with a minimum of steam and oxygen over a catalyst to produce
a synthesis gas with composition close to stoichiometric for the methanol
synthesis. Less heat is lost in this method of synthesis gas production than
is in reforming, and shift conversion of the synthesis gas is not required.
Therefore, the capital investment required for the plant is reduced
substantially. Since this design is technically and economically better than
steam reforming, it will probably be used for large-scale fuel methanol
production in the future.
Production of methanol from natural gas is an established process;
over 6 billion gallons per year are produced worldwide for use as a
chemical and in MTBE production. The present selling price for chemical
grade methanol is about $0.55 per gallon.[100] However, the production
cost for methanol as a vehicular fuel could be much lower for three reasons.
First, if a substantial demand for methanol fuel were established,
production facilities would be expected to be much larger than present
chemical market facilities. Current chemical methanol demand is only a
fraction of what demand would be under a large scale clean fuels program
such as would be introduced under Scenario 2 or 3. Higher demand would
allow for the construction of large multitrain facilities, which would benefit
significantly from economies of scale. Second, these large production
volumes would likely spur the development of newly emerging
technologies for producing methanol (including catalytic partial oxidation,
fluidized bed, and liquid-phase synthesis). Some of these technologies are
near commercial status and would reduce methanol prices even further via
lower plant capital costs and higher process efficiencies. Third, fuel
methanol would not be required to have the level of purity that chemical
grade methanol does.[93] Since purification requires expensive, energy
intensive distillation columns, energy costs and capital investments would
be lower in a fuel plant that would not require their use.
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Under a. scenario where there is a substantial, consistent demand for
fuel methanol, large scale methanol production facilities (at least 10,000
tons per day) could be built to serve the market. The cost (per ton of
capacity) of such facilities would be somewhat less than current facilities
(less than 2,500 tpd) due to favorable economies of scale. Hence, the
annual capital and operating costs would be lower per gallon of methanol
produced.
Several reports have been released recently that address the costs of
methanol from natural gas, including studies from DOE, EPA, and
OTA.[93,41,101] The EPA Special Report on methanol estimated that it
could be produced from foreign natural gas and delivered to a U.S. port at a
price of 35 cents per gallon. Similarly, DOE estimated that methanol could
be produced in foreign locations and delivered to the U.S. at a cost of 41
cents per gallon. Conclusions of the OTA report were similar. In this
report, costs based on DOE's methanol plant analysis and remote gas prices
as described in Section I above were used to estimate a U.S. port price for
foreign methanol of $0.35 per gallon in 2000, and $0.40 per gallon in 2010.
Methanol prices for plants using domestic natural gas would be
significantly higher, due to the higher natural gas feedstock costs.
Similarly, methanol can also be produced from Alaskan gas and from
gas which is currently vented and flared. Using the gas feedstock costs
presented in Section I, an estimate of the U.S. delivered cost of methanol
based on these feedstocks can also be calculated. The landed cost of
methanol produced from vented and flared gas is estimated at $0.35 per
gallon in both 2000 and 2010, since collection costs of this unused resource
are not expected to rise. Landed prices for methanol made from Alaskan
natural gas are estimated to be $0.53 per gallon and $0.56 per gallon for
the same two years.14
Due to the high production costs, methanol made from domestic gas
will not be considered further in this report. Projected production rates of
foreign natural gas can provide all the methanol needed under any of the
14 Delivered price for methanol produced from Alaskan natural gas includes a 10 cent
per gallon fee for batch shipping through the Trans-Alaska pipeline, based on
estimates provided by ARCO (letter from Kenneth R. Dickerson, ARCO to William G.
Rosenberg, EPA, November 27, 1989). According to a study by Bechtel, Inc., 5 cents
per gallon of methanol would be added to transport methanol via tanker to the Lower-
48 ("California Fuel Methanol Cost Study: Executive Summary, Vol.1," Bechtel, Inc.,
January 1989). The actual cost of batch shipping of methanol could be lower if
significant spare pipeline capacity is available, a possibility which will be addressed
in subsequent versions of this Environmental Study
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scenarios considered. Vented and flared gas can meet the requirements of
Scenarios 1 and 2, and the demand for the year 2000 in Scenario 3.
Alaskan natural gas can only meet the methanol demand for the year 2000
under alternative fuel market Scenarios 1 and 2. The full requirements of
Scenario 3 for both years considered cannot be met by either vented and
flared gas or Alaskan gas alone or in tandem. (Of course, a portion of the
methanol demand could be supplied by gas from either of these sources.)
2. Fuel Distribution/Infrastructure Costs
The difference between the port price of a fuel and its retail price can
be divided into three main components: 1) distribution of the fuel to the
service station, 2) service station markup, and 3) taxes. A number of
studies have presented estimates of these costs; Table 4-30 shows the
distribution and infrastructure costs for M85 and M100, and for gasoline as
a reference, that will be used in this report.
Table 4-30
Estimates of Fuel Price Components
from Port/Refinerv to Retail for Methanol
(cents per gallon)
M100 M85
Long-range and Local Distribution 1 3 3
Service Station Markup^ 5-7 6-8
All Taxes L2 14
Total 20-22 23-25
Total. Gasoline-Equivalent 40-44 40-44
*For Scenario 3, this number would increase $0.02/gallon, as discussed above
^In Scenario 3, an additional $0.01/gallon would be added to this number.
Long-range distribution through the use of pipelines, barges, and
tankers is projected to be significantly less expensive per gallon of fuel for
methanol than for gasoline (3^/gal vs. 60/gai), principally because the most
significant ozone nonattainment cities are located on the coast or near or on
major waterways.[41] Thus, methanol produced in foreign locations could
4-89
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be supplied by ship directly to the city of ultimate consumption. (To the
extent that foreign methanol is compared with gasoline supplied from a
new refinery (built on foreign soil), distribution costs should be nearly
equal on a per gallon basis.) Terminaling costs per gallon are estimated to
be virtually the same on a volumetric basis. Trucking costs may tend to be
slightly lower on a per gallon basis for methanol (higher on a per energy
basis) as truck delivery route lengths will tend to be shorter, since the
routes can be optimized for methanol fuel deliveries. Projected long-range
and local distribution costs for methanol are summarized in Table 4-30.
DOE estimates that current fuel delivery systems can deliver fuel
methanol to approximately 75 percent of the U.S. population.[64] Use of
petroleum pipelines for methanol transmission is not considered due to
contamination concerns. Therefore the use of methanol without geographic
restrictions, as would occur under Scenario 3, will require the development
of additional delivery systems, storage capacity and equipment. Railroad
and truck transportation is assumed for those areas outside of the existing
distribution system. Costs are based on a recent EPA analysis.[411
Distribution expansion costs are expected to be $0.02 per gallon, assuming
distribution to 91,000 service stations, and a 10 percent rate of return on
investment.
The largest area of disagreement among various studies concerns
service station markup, which is highly dependant on the volume of
alternative fuels sold and on particulars of the alternative fuel program.
Like LPG markup, methanol service station costs can be estimated based on
those for gasoline (20/gal for tankage and 70/gal overhead for a total
9tf/gal). The tankage costs for methanol can be assumed the same as for
gasoline.[69] Overhead costs should be the same as gasoline, on an energy
equivalent basis, since the costs of operating the pumps, labor, and
maintenance will be roughly equivalent per unit energy of fuel sold.
Therefore, it seems reasonable to assume that the dealer margin for M100
will be about 5 to 7 cents per gallon, depending on vehicle efficiency (or 6
to 8 cents per gallon for M85, which has a slightly higher energy content).
A more detailed discussion of service station markup can be found in EPA's
Special Report on Methanol.[41]
With the more geographically disperse distribution of methanol in
Scenario 3, a higher number of service stations and higher total methanol
sales would cause an individual service station's sales to decrease by 25
percent from the levels of Scenario 2.[66,67] Capital costs (per unit of fuel)
would thus be somewhat higher under Scenario 3, thus increasing service
station markup by approximately $0.01/gallon gasoline equivalent.[41,68]
4-90
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Taxes for methanol and gasoline are assumed to be equivalent on an
energy basis, X2 cents per gallon for M100 and 14 cents per gallon for M85.
This does not reflect expected increases in fleet average energy efficiency
due to the introduction of high-efficiency M100 vehicles, however. As fleet
energy efficiency increases, taxes (on an energy basis) would have to
increase to create a "revenue-neutral" program. Any increased taxes would
likely be allocated to gasoline and methanol equally on a Btu basis,
however, maintaining the two-to-one ratio used in this analysis.
In summary, EPA estimates the total M100 price increment from port
to customer would be about 20 to 22 cents per gallon and the total M85
price increment would be 23 to 25 cents per gallon. These costs will be
realized under Scenario 1 (FFVs with no required use of alternative fuels),
only if mechanisms requiring the use of fuels in vehicles in a limited
geographical area are established. However, under more stable, high
alternative fuel demand scenarios, such as Scenario 2, these cost could be
realized. For a more geographically dispersed program like Scenario 3,
distribution and markup would be higher, as discussed in the text.
3. Vehicle Efficiency and Cost
a. Efficiency
Methanol has chemical and combustion properties which make it an
inherently more efficient fuel than gasoline. The most important properties
are higher octane, which allows a higher compression ratio; wide
flammability limits, which permit good combustion at high air-to-fuel
ratios; and a higher power output, which allows the use of a smaller, more
efficient engine. A more complete analysis of these relationships is
presented in EPA's Methanol Special Report.[41] These efficiency estimates
take into account synergistic effects that exist when an optimized
methanol-fueled engine and vehicle are considered. The higher
compression ratio possible and the higher post-combustion pressure both
combine to make the engine more powerful for a given engine size. This
benefit could be taken as higher performance in the form of increased
power. However, if the performance target remains constant compared to
gasoline, the engine size can be reduced. This results in even better fuel
efficiency since idle fuel consumption is reduced. A smaller engine can be
lighter and this means a corresponding lighter weight vehicle structure.
However, to provide the methanol vehicle with an equivalent range, its
weight must be increased for added tankage and fuel. The effects of these
weight changes on vehicle efficiency have been considered here.
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EPA has estimated that a dedicated vehicle optimized for methanol
combustion could yield an efficiency benefit of 30 percent over gasoline
fueled vehicles.[41] Flexible-fueled vehicles would likely achieve a 5
percent efficiency gain over gasoline vehicles, when operating on methanol
fuel.
b. Vehicle Cost
A variety of factors unique to dedicated methanol vehicles have an
impact on the cost of the vehicle. The efficiencies discussed earlier would
allow the methanol engine to be smaller than its gasoline equivalent, which
reduces vehicle cost. Because a methanol engine runs cooler than a gasoline
engine, the radiator fan and other engine cooling components could also be
reduced in size, further reducing costs. In addition, dedicated methanol
vehicles would not require the evaporative emission controls in place on
conventional gasoline vehicles. On the other hand, methanol vehicles
require fuel system modification, a more sophisticated fuel injection system
and a larger, modified fuel tank. These modifications would increase the
cost of a methanol vehicle over that of an equivalent gasoline vehicle.
Taking all of these factors into account, EPA has estimated that there is no
net cost difference between dedicated methanol vehicles and future
gasoline vehicles.[41]
Flexible fuel vehicles require all the costly modifications for a
methanol engine, without achieving any of the benefits associated with an
optimized dedicated methanol engine. EPA has estimated that FFV's could
probably achieve a differential cost of $300 in commercial production, or an
amortized cost of about 0.5 cents per mile over the full life of the
vehicle.[41] Maintenance costs for both flexible fuel and dedicated
methanol vehicles are expected to be comparable with those for gasoline or
about 6.80/mile.
4. Methanol Pump Price
Tables 4-31 and 4-32 present the projected methanol pump prices
for M85 in the years 2000 and 2010, respectively, for all feedstocks
considered in this report. For flexible-fueled vehicles, M85 using methanol
produced from foreign natural gas has the lowest efficiency-corrected
pump price, $1.12 per gallon of gasoline equivalent, in 2000. In 2010, M85
from foreign gas is projected to cost $1.23 per gallon gasoline equivalent.
Methanol from vented and flared natural gas would exhibit similarly low
costs. Obviously, methanol could also be produced from domestic natural
gas; however, costs are unattractive when compared to foreign locations
4-92
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where lower cost natural gas is available. M85 produced from the other
feedstocks would likely be priced higher than gasoline.
The future price estimates for M100 are presented in Tables 4-33
and 4-34. These tables show that methanol made from foreign natural gas
will be the least costly, with an efficiency adjusted price of $0.88 per gallon
gasoline equivalent in 2000 and $0.95 per gallon in 2010. (Vented and
flared gas is also expected to cost $0.88 per gallon.) Methanol made from
coal would be somewhat more expensive, with a gasoline equivalent pump
price of $1.23 per gallon in 2000 and $1.26 per gallon in 2010; coal-based
methanol coproduced with electricity would be slightly less expensive.
Methanol produced from biomass or municipal waste would be significantly
more expensive than methanol from the other feedstocks based on current
technological designs. However, if reductions in the feedstock cost of
biomass are made through intensified research efforts, SERI projects a
production cost that would make this methanol competitive with that from
natural gas.[98] In addition, the cost of methanol produced from municipal
waste could be significantly lower if the tipping fee for the MSW rises
above $33 per ton assumed in this analysis.
4-93
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Table 4-31
M85 Pump Price Comparisons, Year 2000
(Projected Gasoline Equivalent $/pallon^
Source of Feedstock
Coal Coal Natural Gas1
£m_2. (CP)2 Biomass3 msw4 Foreign Alaskan V/F
Blended Price ($/gallon)5 0.63 0.58 0.71 0.81 0.44 0.59 0.44
Distribution Costs6 0 03 0.03 0.06 0.06 0.03 0.03 0 03
Serv. Station Markup7 0 06 0 06 0.06 0.06 0 06 0 06 0.06
Taxes9 0.14 0 14 0.14 0 14 0 14 0 14 0 14
Total Pump Price ($/gallon) 0.86 0.81 0.97 1.07 0 67 0.82 0.67
Gasoline Equiv. Ratio — ---1 75
Efficiency Correction Factor 0.952
Efficiency Corrected Price ($/gallon) 1.43 1.35 1.61 1.78 1.12 1.36 1.12
'Domestic natural gas is not considered since, due to the lower construction cosis, most methanol plant designs arc
planned Tor locations overseas.
2 The notation (D) refers to methanol from a dedicated coal lo methanol plant, and (CP) refers to methanol
produced by a methanol/elecmcity coproduction plant.
3 SER1 estimates that methanol could be produced from biomass for as liule as $0 55 per gallon, the cost of M85 would be
significantly lower if this cost were realized.
4 Estimated based on biomass-to-methanol plant. Due lo special handling and disposal problems associated with MSW, these
costs could be higher for a plant designed for MSW.
5 Gasoline at $0.92 per gallon.
6 For a geographically disperse program, this would increase $0 02 per gallon
7 This would increase SO 01 per gjllon for a geographically disperse program
8 0 06=+5% efficiency, markup for +30% elliucncy would be 0 08
^ Not including the recent highway u\ increases
4-94
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Table 4-32
M85 Pump Price Comparisons, Year 2010
(Proiecietl Gasoline Equivalent S/pallon)
Source of Feedstock
Coal Coal Natural Gas 1
LHL2- ££P)2. Biomass3 MSW4. Foreign Alaskan V/F
Blended Price ($/gallon) 5 0.68 0.67 0.74 0.84 0.5 1 0.64 0 46
Distribution Costs6 0 03 0 03 0.06 0 06 0 03 0 03 0 03
Serv. Station Markup7 8 0 06 0.06 0.06 0 06 0 06 0 06 0 06
T axes9 0 14 0 14 0 14 0 1A 0_N 0 14 0 14
Total Pump Price ($/gallon) 0 91 0 90 1.00 1.10 0 74 0 87 0 69
Gasoline Equtv. Ratio - I 75
Efficiency Correction Factor - 0 952
Efficiency Corrected Price ($/gallon) 1 52 1.50 1.66 1.83 1.23 1.45 1.16
1 Domestic natural gas is noi considered since, due to the lower construction costs, most methanol plant designs arc
planned for locations overseas.
2 The notation (D) refers to methanol from a dedicated coal to methanol plant, and (CP) refers lo methanol
produced by a meihanol/elcctricily coproduciion plant.
3 SERI estimates that methanol could be produced from biomass for as little as SO 55 per gallon; the cost of M85 would be significantly
lower if this cost were realized
4 Estimated based on biomass-lo-mcihanol plant Due lo special handling and disposal problems associated with MSW, these
costs could be higher for a plant designed for MSW.
5 Gasoline at $1.11 per gallon
6 For a geographically disperse program, ihis would increase $0 02 per gallon
7 This would increase $0 01 per gallon for a geographically disperse program
8 0 06=+5% efficiency, markup for +30% efficiency would be 0 08
9 Not including the recent highway tax increases
4-95
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Table 4-33
Ml00 Pump Price Comparisons, Year 2000
(Projected Gasoline Equivalent $/pallorO
U.S. Landed Cost ($/gallon)
Distribution Costs5
Serv. Station Markup6 -7
Taxes8
Source of Feedstock
Coal Coal
Natural Gas1
V/F
£D)2 (CP) Biomass3 MSW Foreign Alaskan
0.58 0.52 0.67 0.79 0.35 0 53 0 35
0 03 0 03 0 06 0 06 0 03 0.03 0 03
0 05- 0.05- 0.05- 0.05- 0 05- 0 05- 0 05
0.07 0.07 0.07 0.07 0 07 0 07 0 07
0. 12 0 12 0 12 0.12 0 12 0 12 0 12
Total Pump Price
($/gallon)
Gasoline Equiv. Ratio (dedicated)
Efficiency Correction Factor
0.78-
0 80
0.72-
0.74
0.90-
0.92
1.02-
1.04
0.55-
0 57
2 00
-0 769-
0.73
0 75
0.55
0 57
Efficiency Corrected Price($/gal.) 9
1.23 1.14
1.41
1.60
0.88
1.15
0.88
1 Domestic natural gas is not considered since, due lo the lower construction costs, most methanol plant designs arc
planned for locations overseas.
2 (D)= a dedicated coal to methanol plant, and (CP) =a meihanol/elcctricity coproduction plant
3 SERI that estimates a methanol cost of $0.55 per gallon is possible under an intense research program; the pump
price would then be $1.18 per gallon gasoline equivalent.
4 Estimated based on biomass-to-methanol plant. Due lo special handling and disposal problems associated with MSW, these
costs could be higher for a plant designed for MSW
5 For a geographically disperse program, this would increase $0 02 per gallon
6 0 05=+5% efficiency, markup for +30% efficiency would be 0 07
7 This would increase $0 01 per gallon for a geographically disperse program
H Noi including ihc recent highway lax increases.
\sbuiniiig deiliLUlcd vehicle (t-30% cflmeniy)
4-96
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Table 4-34
M100 Pump Price Comparisons, Year 2010
(Proiected Gasoline Equivalent $/gallon)
Source of Feedstock
Coal Coal Natural Gas1
(D) 2
(CP)
Biomass3
MSW4
Foreign
Alaskan
V/F
U.S. Landed Cost ($/gallon)
0.60
0.59
0.67
0.79
0.40
0.56
0.35
Distribution Costs5
0 03
0.03
0.06
0 06
0.03
0 03
0 03
Serv Station Markup6 -7
0 05-
0 07
0.05-
0.07
0.05-
0.07
0 05-
0 07
0 05-
0 07
0 05-
0.07
0 05
0 07
Taxes8
0 12
0 12
0 12
0 12
0 12
0 12
0 12
Total Pump Price
($/gallon)
0 80-
0 82
0.79-
0 81
0.90-
0.92
1 02-
1 04
0 60-
0 62
0.76-
0 78
0 55-
0.57
Gasoline Equiv. Ratio (dedicated) 2 00
Efficiency Correction Factor - - 0.769
Efficiency Corrected Price ($/gal )9 1.26 1.25 1.41 1.60 0.95 1 20 0.88
1 Domestic natural gas is not considered since, due lo the lower construction costs, most methanol plant designs arc
planned for locations overseas.
2 (D)= a dedicated coal to methanol plant, and (CP) =a methanol/electricity coproduction plant.
3 SER1 that estimates a methanol cost of $0.55 per gallon is possible under an intense research program, the pump
price would then be $1.18 per gallon gasoline equivalent.
4 Estimated based on biomass-to-methanol plant Due lo special handling and disposal problems associated with MSW,
these costs could be higher for a plant designed for MSW.
5 For a geographically disperse program, this would increase $0.02 per gallon
6 0 05=+5% efficiency, markup for +30% efficiency would be 0 07
7 This would increase $0 01 per gallon for a geographically disperse program
8 Not including the recent highway lax increases
^ Assuming dedicated vehicle (+30% elfiuency)
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APPENDIX 4-A
Economic Analysis Methodology
When enough economic information was provided in a report about a
conversion process, and there are no known capacity constraints on the
process, the process was scaled to produce 50,000 oil equivalent barrels
(OEB) daily, as discussed in the text. Capital costs were scaled to 1989
dollars using the Marshall & Swift Equipment Cost Index and an updated
version of the "0.6-power-factor model", which bases the cost of a new
plant on the product of a known cost for the same type of plant, and the
ratio of the plant capacities raised to an exponent R, which varies between
processes.[102,103,104] All costs are escalated to 1989 dollars using the
Producers Price Index (PPI) (some of these values are shown in Table 4A-
1). Fixed operating costs are scaled to the larger capacity by increasing the
cost (in 1989 dollars) by 20 percent, while variable operating costs and
byproduct credits are scaled linearly. Feedstock costs for coal were
calculated by scaling the feed to the larger capacity and using the 1989
average coal price of $1.45 per million Btu.[48] Other feedstock costs were
calculated using current price estimates.
Table 4A-1
Cost Indexes Used in Economic Analysis
Producer's Price Index fPPD
1984
1985
1986
1987
1988
1989
Coal 102.2
102.2
100.8.
97.1
95.4
95.5
Gas Fuels 104.5
98.7
83.2
74.1
71.4
75.3
Electric Power 108.2
111.6
112.6
110.6
111.2
114.8
Industrial Chemical 96.8
96.0
91.5
95.5
106.8
116.5
Marshall & Swift Eauimnent Cost Index CMS)
1984
1 985
1986
1987
1988
1989
Overall Annual 780.4
789.6
797.6
813.6
852.0
896.5
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In order to calculate annual capital costs, an after-tax real return on
investment (ROI) of 10 percent and a plant life of 20 years was assumed.
Although the ROI used as a criterion in corporate spending decisions is
often higher than this, capital investments made in the motor fuel sector
(petroleum refining) typically provide a real after-tax ROI of 10
percent.[41] Under a fuels program such as Scenario 1, where only flexible-
fueled vehicles are provided and no guarantee is made that these vehicles
will operate on alternative fuels, market risks would be higher (although
technical risks would be low, since much of the technology is already
developed and proven, especially for methanol, and would help restrain the
market risks).[101] In this situation, a slightly higher ROI may be required
at alternative fuel production facilities, raising the fuel production costs
somewhat. However, under a stable, secure alternative fuel market, as
would exist with an established alternative fuels program like Scenario 2
that had strong assurances of success, investment in a fuel plant would not
likely be significantly riskier than investment in a gasoline refinery, and a
10 percent ROI would be appropriate. In all economic analysis of this
report, a 10 percent ROI was assumed.
The annual capital charge is calculated based on a capital recovery
rate (CRR) of 16.85 percent for coal feedstock processes (assuming an
instantaneous investment factor (IIF) of 1.17 calculated over a 4 year
construction period), while a CRR of 16.63 percent was used for other
feedstocks (based on a 3 year construction period). Using the annual
capital charge, feedstock costs, taxes, and byproduct credits, the total
annual cost was calculated, and a fuel unit price was determined.
4-99
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106. Personal communication with Don Walters, DOE, May 23, 1990.
4-108
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Appendix 5
Energy Supply Impacts of Alternative Fuel Scenarios
Table of Contents
Section Title Page
I. Energy Supply Impacts 5-1
A U.S. Energy Outlook 5 - 1
B Impact of Alternative Fuel Use 5-2
II Crude Oil Price 5 - 3
III Other Energy Supply Impacts 5-4
References
5-8
-------
Appendix 5
Energy Supply Impacts of Alternative Fuel Scenarios
The increased use of alternative fuels and the resultant displacement
of gasoline from the transportation sector will likely have an impact on the
quantity and origin of fuel imported into the U.S. A significant reduction in
petroleum consumption might further have an impact on petroleum prices,
affecting the price consumers pay for petroleum products. In addition,
some displacement of fuels which compete with petroleum-based fuels in
other sectors (a.g. home heating, electricity generation, etc.) may possibly
occur.
A discussion of the possible energy supply impacts of the alternative
fuel penetration scenarios defined in Appendix 3 is presented below.
First, a general discussion of the advantages and disadvantages of
diversifying U.S. energy supply is presented. Second, the potential impact
of gasoline displacement on the price of crude oil will be explored. Finally,
a discussion of the residual effects of a shift in the type of fuel used in the
transportation sector will be discussed.
I. Energy Supply Impacts
A. U.S. Energy Outlook
As discussed in Appendix 2, U.S. consumption of oil is expected to
increase, and because domestic production continues to decline now and in
the future, this demand will be met by a rise in imports from foreign
sources of oil. Domestic production was approximately 9.95 MMPBD in
1989, and is projected to be between 8.32-9.51 MMBPD in 1995, and
between 7.27-8.58 MMBPD in 2010.[3] EIA projects U.S. net oil imports
increasing from approximately 7.20 MMBPD in 1989 to between 7.76-
10.96 MMBPD in 1995 and between 10.38-14.93 MMBPD in 2010 (close to
two-thirds of total domestic petroleum consumption). The U.S. and other
importing countries as well are turning toward OPEC (specifically Persian
Gulf) suppliers to meet growing import needs.
The projected increase in reliance on relatively few oil suppliers
implies certain risks for the U.S. and other importer countries. If OPEC
continues to dominate the world's energy markets, this could result in
artificially high prices (with possible upward and downward price shocks),
5-1
-------
which may cause difficult economic adjustments. Threats of oil disruptions
become more severe as the U.S. reliance on petroleum and petroleum
products continues to grow.
In the event of a supply disruption, the ability of the U.S. to convert
to alternate sources of energy would be an important concern. While the
U.S. is capable of switching many non-transportation energy users to non-
petroleum sources, it is not currently capable of switching from using
crude oil to some other source of energy in the transportation sector. The
inability to do this may have serious implications for the transportation
sector which relies almost exclusively on petroleum based products for its
source of energy.
B. Impact of Alternative Fuel Use
Several options exist which, if implemented, would marginally,
reduce U.S. dependance on foreign oil. Efforts to increase domestic
production would likely precipitate a short term reduction in the quantity
of oil imported. However, as discussed in Appendix 2, U.S. oil reserves are
somewhat limited, and would likely not provide a long term solution. Of
course, conservation measures could reduce demand for imported oil;
however, beyond modest efficiency improvements, this strategy would
entail significant changes in consumer behavior such as car-pooling or
using public transportation. Absent strong economic incentives, such as
gasoline taxes or user fees, the effectiveness of conservation measures
would likely be limited. One of the most promising options for reducing
dependance on foreign oil is to develop and encourage the u^e of
alternative fuels, particularly in the transportation sector.
The use of alternative fuels would also provide energy supply
benefits to the U.S. by providing an expandable energy source in case of a
supply disruption.1 The mere presence of alternative energy sources for
the transportation sector could serve as a deterrent to crude oil supply
disruptions, since, even if only a fraction of the motor vehicles operate on
alternative fuels, the impact would be less severe than if gasoline was the
only fuel. In addition, increasing the U.S. fuel switching capabilities in the
transportation sector would provide some leverage against oil suppliers,
providing a deterrence against wide swings in the price of oil. If the fuel
were domestically produced this would further enhance our control over
energy supply and price and improve our negative trade balance. If sole
Assuming that the supply of the alternative fuel could be significantly expanded in
the short run.
5-2
-------
domestic supply is not feasible, however, the mere presence of additional
energy suppliers would increase competitive pressures in the fuels market.
II. Crude Oil Price
One major economic benefit of a switch to alternative fuels would be
the effect that a reduction in global crude oil demand could have on world
oil price. Since crude oil is a fungible product, the cost of the last
increment of oil produced (theoretically) sets the market price of all oil
sold. As a result, any reduction in global demand would eliminate the
highest cost marginal producer, thus lowering the price of all oil sold.
Obviously, the effects of such a reduction in oil price would have positive
effects on the U.S. trade balance, and also serve to lower the price of goods
(most notably gasoline) produced from oil.
Predicting the extent to which oil prices might drop in response to a
decreased demand is difficult to do with much accuracy. The extent to
which other markets (such as utilities and home heating) might respond to
depressed oil prices is uncertain; any increased oil consumption in these
other sectors would work to drive the price of oil back up. The response of
OPEC to decreased global demand is also uncertain; production quotas could
be limited further in an effort to drive prices back up. Thus, quantifying
benefits in this area is rather uncertain.
A recent attempt to quantify the savings associated with decreased
oil demand was made in a recent report prepared by DOE.[l] In the report,
it was estimated that a reduction in crude oil consumption of 500,000
barrels per day would result in an oil price reduction of approximately
$1.00 per barrel. While this projection of the relationship between
petroleum demand and price was heavily caveated by DOE, as is
appropriate, it does provide a touchstone with which to evaluate the
potential economic benefits of alternative fuel scenarios which would
displace petroleum consumption.
Tables 5-1 through 5-3 present the potential gasoline displacement
and oil price suppression impacts of each of the scenarios presented in
Appendix 3. As can be seen from the tables, using the relationship
developed by DOE, crude oil prices could drop by as much as $2.21 per
barrel under Scenario 3, the 1 MMBPD gasoline displacement scenario.2 At
2Gasoline displacement and oil displacement are not exactly equivalent on j
volumetric basis. In the tables, it was assumed that 72 38 MPBD of oil would be
5-3
-------
the projected .rate of U.S. imports presented above, this would result in an
annual reduction of $5.8 and $14 billion in the U.S. trade balance in 2000
and 2010.
Table 5-1
Scenario I: Max Credit Scenario
Annual Gasoline Displacement and Alternative Fuel Use
(flat CAFE and 1.5% annual VMT growth)
Calendar Year
2000
2010
Gasoline Displaced
If
CNG
0.60
1.47
If If
5thanol Methanol
(billion gallons)
0 24
1 96
0 30
2 04
Crude Oil Price Reduction.
If If If
CNG Ethanol Methanol
(S per barrel)
0.09
0 21
0.03
0.28
0 04
0.30
III. Other Energy SuddIv Impacts
As alluded to above, it is difficult to predict the manner in which
other energy markets would respond to a shift in the transportation sector
with much certainty. The displacement of oil from the transportation
sector, and the potential price impacts discussed above may result in an
increased usage of oil in other sectors, particularly if limited domestic
resources such as natural gas or LPG are diverted into transportation uses.
The degree to which this would take place, however, is uncertain, and is an
area which requires further study.
Other potential effects of alternative transportation fuel use might
include a marginal reduction in the required capacity of the Strategic
Petroleum Reserve (SPR). The purpose of the SPR is to reduce the risk and
impact of a potential oil supply disruption. Currently the U.S. has
petroleum stocks totaling nearly 600 million barrels, with a goal of
increasing stocks to 750 million barrels by 1991. Based on current supply,
the SPR could compensate for a total cut-off of oil imports for almost 100
days. Assuming that the size of the SPR is proportional to the projected
displaced for every 1 billion gallons per year displacement in gasoline
consumption.[2]
5-4
-------
level of U.S. oil imports (i.e. that the SPR is designed to supply a certain
number of days supply of imported oil), a reduction in oil imports resulting
from alternative fuel use would theoretically justify a slight reduction in
SPR capacity.
Since the SPR is still in development, reducing its capacity could save
some of the cost required for its completion and for additional oil
purchases. It is estimated that the SPR will require an additional $5.1
billion for system completion (not including additional oil purchases).
Under any of the three scenarios evaluated in this report, these completion
costs could be reduced somewhat. No attempt to quantify potential
savings has been made in this edition of the report, however, additional
analysis in this area would be valuable.
5-5
-------
Table 5-2a
Scenano II: Nine City Pioi'.iam
(Hal CAFE and 1.5% annual VMT giowth)
Gasoline Displaced Crude Oil Price Reduction
(billion gallons per year) ($ per barrel)
Calendar If If If If It 11 If If II If
Year CNG Electric Ethanol LPG Methanol CNG Electc Ethanol I.PG Methanol
2000 1.56 2.65 1.21 2.65 1.17 0 23 0.38 0.18 0 38 0 17
2010 1.82 5 77 2.56 5.77 2 36 0 26 0 84 0 37 0 84 0 34
Table 5-2b
Scenario II: Nine City Program
(DOE Fuel Economy and VMT)
Calendar
Year
Gasoline Displaced
(billion gallons per year)
If If If If
CNG Electric Ethanol LPG
If
Methanol
Crude Oil Price Reduction
($ per barrel)
If If If It
CNG Electc Ethanol LPG
11
Methanol
2000
2.96 2.96 2.47 2.96 2.35
0 43
0.43
0.36
0.43
0.34
20 10
6.18
6.18 6 03 6.18 5.99
0 89
0.89
0.87
0 8 9
0.87
5 - 6
-------
Table 5-3
Scenario 111: 1 MMBPD Gasoline Displacement
(DOE Fuel Economy and VMT)
Gasoline Displaced
(billion gallons per year)
Calendar If
Year CNG
If If If If
Electric Ethanol LPG Methanol
Crude Oil Price Reduction
($ per barrel)
If If If
CNG Electc Ethanol
If If
LPG Methanol
2000
7.33 7.33 6.29 7.33
6 03
.06
I 06
0 91
1.06 0 87
2010
15 3 15.3 15.3 15.3 15.3
2.2 1
2.21 2.21
o o
2 2 1
5-7
-------
References
1. "Assessment of Costs and Benefits of Flexible and Alternative Fuel
Use in the U.S. Transportation Sector-Progress Report One: Context and
Analytical Framework," US Department of Energy, DOE/PE-0080. January
1988.
2. "Effect of Incremental Reduction of Gasoline Production on Crude
Oil Purchased," Memorandum from Susan L. Stefanek, Office of Mobile
Source, EPA to Charles L. Gray, Jr., Office of Mobile Sources, EPA.
3. "Annual Energy Outlook 1990: Long Term Projections," Energy
Information Administration, Office of Energy Markets and End Use, U.S.
Department of Energy, January 1990.
4. "Energy Security: A Report to the President," U.S. Department of
Energy, March 1987.
5. "Monthly Energy Review, June 1990," Energy Information
Administration, Office of Energy Markets and End Use, U.S. Department of
Energy, May 1990.
6. "Assessment of Costs and Benefits of Flexible and Alternative Fuel
Use in the U.S. Transportation Sector, Technical Report Three: Methanol
Production and Transportation Costs," Office of Policy, Planning and
Analysis, Office of Policy Integration, Department of Energy, November,
1989.
5-8
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Appendix 6
Economic Impacts of Alternative Fuel Scenarios
Table of Contents
Section Title Page
I. Net Consumer Cost 6-1
II. Vehicle Cost 6-12
III. Energy Price/U.S. Trade Balance Impacts of Reduced
Petroleum Demand 6-13
IV. Effect of an Alcohol Fuels Program of the Federal
Budget 6-15
V. Summary of Economic Impacts of Alternative Fuel
Scenarios 6-20
References
6-22
-------
Appendix 6
Economic Impacts of Alternative Fuel Scenarios
This appendix presents the costs of the alternative fuel market
penetration scenarios described in Appendix 3. The cost of each fuel and
feedstock combination is compared to the cost of the corresponding non-
alternative fuel scenario. The results of this analysis are presented in
Tables 6-1 through 6-4. In these Tables, the total cost, or in some cases,
savings, of the use each fuel/feedstock combination are presented for each
Scenario in the years 2000 and 2010. The total cost of each combination is
estimated from the sum of the net pump cost, the vehicle cost, and the
savings due to reduced consumption of crude oil; each of these individual
costs will be discussed in greater detail below. Additional costs and credits
are also discussed, and the net societal cost is estimated.
I. Net Consumer Cost
The net consumer cost, at the pump, due to alternative fuel use for
the years 2000 and 2010 is shown as Net Pump Cost in Tables 6-1 to 6-4.
This net cost is the difference between the cost of the alternative fuel
scenario (the cost of the reduced volume of gasoline plus the alternative
fuel cost) and the cost of a non-alternative fuel scenario (i.e., 100 percent
gasoline). This cost can also be calculated as the difference between the
cost of the alternative fuel required to fulfill the projected demand and the
cost of the gasoline displaced.
Prices for each of the alternative fuels presented Appendix 4,
including production and distribution costs, service station markup,
infrastructure costs, and taxes, were used with the fuel consumption data
from Appendix 3 to arrive at the net pump costs shown in the Tables. A
negative number in Tables 6-1 to 6-4 indicates a "savings"; at the pump,
the alternative fuel scenario will cost less than the non-alternative fuel
scenario.1 In these tables, no estimates are presented if feedstock
availability is expected to be insufficient for the fuel volumes required. In
general, as the volume of gasoline displaced increases, a greater number of
lrrhe values for LPG presented in Tables 6-2 and 6-3 assumes future feedstock costs projected in
Appendix 4. LPG prices can be volatile; they rose from a price of $0.22 per gallon in August 1989 to
$0.54 per gallon in August 1990, and reached $0.91 per gallon in October 1990 due to the Persian Gulf
crisis.
6-1
-------
Table 6-la
Economic Impacts of Alternative Fuel Scenarios
(Maximum CAFE Credit Scenario)
Year 2()(M)
FUEL
CNG
Domestic
Foreign
Vented/
Alaskan
Municipal
Njtural
Natural
Flared
Natural
Feedstock
Coal
B Ionian
Waste
Gas
Gas
Gas
Gas
Net Cost (S billion)
Net Pump Cost
3.55
2.57
2 38
1 97
2 15
2 14
2 34
Vehicle Cost
2.43
2.43
2 43
2 43
2 43
243
2 43
Crude Cost
-0.45
-0.45
-0.45
-0 4?
-0.45
-0 45
-0.45
Total Cost
5.53
4.55
4.36
3 95
4 13
4 12
4 32
ethanol
METHANOL
Alaskan
Foreign
Vented/
Coal
Coal
Municipal
Natural
Natural
Flared
Feedstock
Com
Biomass
(Dedicated)
(Coproduced)
Biomass
Waste
Gas
Gas
Gas
Net Cost ($ billion)
* **
Net Pump Cost
2.99 to 4 11
2.84 to 2.90
2 30
2.10
2 75
3 20
2 14
1.53
1 53
Vehicle Cost
0.61
061
0.56
0.56
0 56
0.56
0.56
0 56
0.56
Crude Cost
-0.86
-QM
-1.11
-1.11
-111
-1.11
1-11
-1.1 1
111
Total Cost
2.74 to 3.86
2.59 to 2.65
1.75
1.55
2 20
2 65
1.59
0 98
0 98
~Expanded ethanol production would reduce General Tax Fund revenues due to the blender's income tax credit. The Federal budget
would also be impacted by changes in agricultural program outlays. The net effect of expanded ethanol production on the total cost
of using ethanol fuels could be positive or negative No estimation of this effect is included here
**Ethanol pump costs based on reductions in biomass-to-cthanol production costs projected by DOE
-------
Table 6-lb
Economic Impacts of Alternative Fuel Scenarios
(Maximum CAFE Credit Scenano)
Year 2010
FUEL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Total
Coal
8 02
3 04
-2.98
8 08
CNG
Domestic
Municipal Natural
Biomass
5.66
3.04
-3 9*
5.72
Waste
5 II
304
-2.98
5 17
Gas
5.79
304
-2.98
5 85
Foreign
Natural
Gas
5 06
304
-2.98
5 12
Vented/
Flared
Gas
4 56
304
-2 98
4 62
Alaskan
Natural
Gas
5 33
304
5 39
ETHANOL
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Total
Com
**
7.39 to 10.39
0.44
-3.97
3.86 to 6.86
Biomass
~ ***+
4 08 to 4 22
0 44
-3.97
0.73 to 0 87
Coal
(Dedicated)
5 00
0.40
-4.2Q
Coal
(Coproduccd) Biomass
1.20
4 89
0 40
1.09
6 00
0.40
AM
2.20
Municipal
Waste
7 II
0 40
-4.2Q
331
Alaskan Foreign
Natural Natural
Gas Gas
~
3 02
0 40
-4.20
-0.78
Vented/
Flared
Gas
2 50
0 40
-4.20
-1 30
* Insufficient amount of feedstock to meet fuel requirements
"Feedstock (corn) will meet the requirements assuming the right conditions (good weather, good crop) for feedstock development
*** Expanded cthanol production would reduce General Tax Fund revenues due to the blender's income tax credit The Federal budget
would also be impacted by changes in agricultural program outlays. The net el feet of expanded cthanol production on the total cost
of using cthanol fuels could be positive or negative No estimation of this effect is included here
* * * *n111aiu>I pump costs based on reductions in hiouiass-io-cihanol production costs projected by DOE
-------
Table 6-2a
Economic Impacts of Alternative Fuel Scenarios
(Nine City Program, Flat CAFE and I 5% Annual VMT Growth Scenario)
Year 2000
FUEL
CNG
ELECTRICITY
Domestic
Foreign
Vented/
Alaskan
Municipal
Natural
Natural
Flared
Natural
Municipal
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Conventional
Waste
Solar
Net Cost ($ billion)
Net Pump Cost
3.34
2 12
1 88
1 38
1 60
1 58
1 83
0 03
0 37
1 33
Vehicle Cost
1.57
1.57
1.57
1 57
1 57
1 57
1 57
1 82
1 82
1 82
Crude Cpsi
-2.72
-2 72
-2 72
-3 72
-2.72
-2 72
-2 72
-4 54
-4 54
-4 54
Total Cost
2.19
0 97
0 73
0 23
0.45
0 43
0 68
-2 69
-2 35
-1 39
ETHANOL LPG METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
Biomass
LPG
(Dedicated)
(Coproduced)
Biomass
Waste
Gas
Gas
Gas
Net Cost ($ billion)
**~ *»»*
**
Nei Pump Cost
2 50 to 3 89
2.32 to 2 39
-1 21
1 54
1.31
204
2 50
0 66
0 66
1 36
Vehicle Cost
0.31
031
1 33
0.26
0.26
0 26
0 26
0 26
0 26
0 26
Crude Cost
-2.12
-2,1?
-4.53
-2.02
-i.n
-2.02
-2.02
-2r(>?
-2.02
-2.02
Total Cost
0.68 to 2.07
0.51 to 0.58
-4.41
-0.22
-0.45
0.28
0.74
-1.10
-1.10
-0 40
* Insufficient amount of feedstock to meet fuel requirements.
** Fuel cannot meet requirements unless all LPG released due to RVP regulations is made available for automotive use.
*** Expanded ethanol production would reduce General Tax Fund revenues due to the blender's income tax credit The Federal budget
would also be impacted by changes in agricultural program outlays. The net effect of expanded ethanol production on the total cost
of using ethanol fuels could be positive or negative No estimation of this effect is included here
****Ethanol pump costs based on reduciions in bioniass-to-eihanol production costs projected by DOE
-------
Tabic 6-2b
Economic Impacts of Alternative Fuel Scenarios
(Nine City Program,flat CAFE and 1 5% annual VMT growth)
Year 2010
FUEL CNG ELECTRICITY
Domestic
Foreign
Vented/
Alaskan
Municipal
Natural
Natural
Flared
Natural
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Conventional
MSW
Solar
Net Cost ($ billion)
Net Pump Cost
7.90
5.45
4.88
5 58
4 82
4 30
5 10
-0 72
-0 05
1 75
Vehicle Cost
2.10
2.10
2.10
2.10
2.10
2 10
2 10
3 96
396
3 96
Crude Cost
-3.69
-3.69
-3 69
-3 69
-3,69
-3.69
-3 69
-1 1,73
-1 1.73
-11.73
Total
631
3.86
3 29
3.99
3.23
2 71
3 51
-8 49
- 7 82
-6 02
ETHANQL
IPC'
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Total
Com
**
6.81 to 9.89
0.10
=L21
1.70 to 4.78 -1 72 to -1.57
Biomass
**** *****
3 39 to 3 54
0 10
LPG
***
-3.38
1 94
1 1.73
13.17
Coal
(Dedicated)
4 03
0.09
-4.80
-0.68
Coal
(Coproduccd)
3.93
0.09
-4.80
-0.78
Biomass
4 96
0.09
-4.80
Municipal
Waste
5.99
0.09
-4.80
1 25
1.28
Foreign
Natural
Gas
2 17
0 09
-4.80
-2.54
Vented/
Flared
Gas
I 70
0.09
-4.80
Alaskan
Natural
Gas
~
-3.01
* Insufficient amount of feedstock to meet fuel requirement.
** Feedstock (corn) will meet the fuel requirements assuming the right conditions (good weather, good crop) for feedstock development.
*** Fuel cannot meet requirements unless all LPG released due to RVP regulations is made available for automotive use
**** Expanded cihanol production would reduce General Tax Fund revenues due to the blender's income lax credit The Federal budget
would also be impacted by changes in agricultural program outlays. The net effect of expanded ethanol production on the total cost
of Ubing ethanol fuels could be positive or negative No estimation of this effect is included here
~ ~~~~Ethanol pump costs based on reductions in biomass-to-eihanol production costs projccicd by DOE
-------
Tabic 6-3a
Economic Impacts of Alternative Fuel Scenarios
(Nina City Program, DOE Fuel Economy and VMT Scenario)
Year 2000
FUEL
CNG
ELECTRICITY
Feedstock
Nei Cost ($ billion)
Nei Pump Cost
Vehicle Cosi
Crude Cost
Total
Coal
1 91
1.91
-4.74
-0.92
lilOUlass
0 60
1 91
-4.74
Domcsuc
Municipal Natural
Waste Gas
-2 23
0 34
1.91
-4 74
-2 49
-0 20
1.91
-4 74
-3 03
Foreign
Natural
Gas
0 04
1 91
-4 74
-2 79
Vcnictl/
Flared
Gas
0 02
1 91
-4 74
-2 81
Alaskan
Natural
Gas
0 29
1 91
-4 74
-2 54
Conventional
0 47
2 22
-4 74
Municipal
Waste
0 89
2 22
-4 74
-2 05
I 63
Solar
2 09
2 22
-4 74
0 43
ETHANQL
IPO
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cosi
Vehicle Cost
Crude Cost
Com
1.16 to 2 66
0.38
=122
Biomass
«** **+*
0.97 to I 04
0 38
-3.93
Total
-2.39to-0.89 -2.58 to-2 51
LPG
*~
-1 36
1.62
-4.74
-4 48
Coal
(Dedicated)
0 24
0.31
-3.79
-3.24
Coal
(Coproduced)
-0.01
031
-3.79
-3 49
Biomass
0.78
0.31
-3-79
-2.70
Municipal
Waste
I 27
0.31
-3.79
-2.21
Foreign
Natural
Gas
-0 7 1
0.31
-1.19
-4.19
Vented/
Flared
Gas
-0 7 I
0 31
-3.79
-4.19
Alaskan
Natural
Gas
0 04
031
-3.79
-3 44
* Insufficient amount of feedstock to meet fuel requirement.
** Fuel cannot meet requirements unless all LPG released due to RVP regulations is made available for automotive use.
*** Expanded ethunol production would reduce General Tax Fund revenues due to the blender's income lax credit The Federal budget
would also be impacted by changes in agricultural program outlays The net eflect of expanded cthanol production on the total cost
of using cthanol fuels could be positive or negative No estimation of this effect is included here
* * * *1 tli.tnol pump losIs (used on reductions in bioiiiass-to-clhaiiol production costs projected by DOE
-------
Tabic 6-3b
Economic Impacts of Alternative Fuel Scenarios
(Nine Cuy Program; DOE Fuel Economy and VMT Scenario)
Year 2010
FUEL
CNG
H ECTRIC1TY
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Total
Coal
1.36
2.51
•10.36
-6 49
Biomass
-1 10
251
10-36
Domestic
Mu nicipal Natural
-8.95
Waste
-1 67
251
10.36
-9 52
Gas
-0 97
251
-10,36
-8 82
Foreign
Natural
Gas
-1 73
251
-10-36
-9 58
Vented/
Flared
Gas
-2 25
251
-10 36
-10 10
Alaskan
Natural
Gas
-1 45
251
10.36
-9 30
Conventional
0 42
4 73
-10 36
-5 21
MSW
1 24
4 73
-10 36
-4 39
Solar
3 42
4 73
-10 36
-2 21
ETHANQL
LPG
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Total
Com
1.77 to 4.91
0.12
-10-07
-8.18 to-5.04
Biomass LPG
**~ ~«
-171 to -1.57 -3 62
0.12 2 33
-10 07 -12,48
-11 66 to -11 52 -13 77
Coal
(Dedicated)
-1.35
0.10
-9.96
Coal
(Coproduced) Biomass
-I 1.21
-1 44
0.10
-9.96
-11.30
0 40
0.10
-9.96
-9.46
Municipal
Waste
064
0.10
-9.96
Foreign Vented/ Alaskan
Natural Flared Natural
Gas Gas Gas
-9 22
-3 23
0 10
-9.96
-13.09
-3 61
0.10
-9,'->6
-13.47
* Insufficient amount of feedstock to meet fuel requirements.
** Fuel cannot meet requirements unless all LPG released due to RVP regulations is made available for automotive use.
*** Expanded ethanol production would reduce General Tax Fund revenues due to the blender's income tax credit The Federal budget
would also be impacted by changes in agricultural program outlays. The net effect ot expanded ethanol production on the total cost
of using ethanol fuels could be positive or negative No estimation ol this effect is included here
****Ethanol pump costs based on reductions in biomass-to-ethanol production costs projected by DOE
-------
Fable 6-4a
Economic Impacts of Alternative Fuel Scenarios
(1 MMBPD Gasoline Displacement, DOE Fuel Economy and VMT)
Year 2000
FUEL CNG El ECTRIC1TY
Domestic
Foreign
Vented/
Alaskan
Municipal
Natural
Natural
Flared
Natural
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Conventional
MSW
Solar
Net Cost ($ billion)
*
*
*
Net Pump Cost
4.76
1 50
-0 47
0 13
0 08
1 21
5 24
Vehicle Cost
5 76
5 76
5 76
5.76
5 76
6 68
6 68
Crude Cost
-14 06
-14 06
-14 06
-14 06
-14 06
-14 06
-14 06
Total
-3 54
-6 80
-8 77
-8 17
-8 22
-6 17
-2 14
ETHANOL
LPG
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Com
4.14 to 7.94
1.17
-13.11
Total
-4 76 to-3.00
Biomass
i+ ***
2.46 to 2.66
1.17
-12.11
LPG
Coal
(Dedicated)
0 55
0.98
1 1.63
•8 48 to -8 28
10.10
Coal Municipal
(Coproduccd) Biomass Waste
-0.09
0.98
-11 63
-10.74
1.95
0 98
I 1.63
-8 70
Foreign Vented/ Alaskan
Natural Flared Natural
Gas Gas Gas
-1 90
0.98
-1 1.63
-12.55
* Insufficient amount of feedstock to meet fuel requirements.
** Expanded cthanol production would reduce General Tax Fund revenues due to the blender's income lax credit The Federal budget
would also be impacted by changes in agricultural program outlays The net effect ol expanded cthanol production on the total cost
of using cthanol luels could be positive or negative No estimation of this cfleu is included here
***Ethanol pump costs based on reductions in biouiass-to-eihanol production costs projected by DOE
-------
Tabic 6-4b
Economic Impacts of Alternative Fuel Scenarios
(I MMBPD Gasoline Displacement, DOE Fuel Economy and VMT Scenario)
Year 2010
FUEL
CNG
ELECTRICITY
Domestic
Foreign
Vented/
Alaskan
Municipal
Natural
Natural
Flared
Natural
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Conventional
MSW
Solar
Net Cost ($ billion)
+
**
*
*
+
Net Pump Cost
3.37
-2 73
-2 40
-3 59
1 08
8 54
Vehicle Cost
7.55
7 55
7.55
7 55
14 23
14.23
Crude Cost
-30.41
-30.41
-10.4 1
-10.4 1
-10 4 1
-10 41
Toial
-19 49
-25 59
-25 26
-19 27
-15 10
-7 64
ETHANOL
LPO
METHANOL
Feedstock
Net Cost ($ billion)
Net Pump Cost
Vehicle Cost
Crude Cost
Com
*
Total
Biomass
»*•
-4.31 to -3 94
0.38
-30,41
-34.34 to -33.97
LPG
Coal
(Dedicated)
-3 60
0.32
-30.41
-33.69
Coal
(Coproduccd)
-3.80
0.32
-30.41
-33.89
Biomass
0.96
0 32
-30 41
-29.13
Municipal
Waste
Foreign
Natural
Gas
Vented/
Flared
G.is
Alaskan
Natural
Gas
* Insufficient amount of feedstock to meet fuel requirements
** Feedstock (foreign natural gas) will meet requucmcnis only if LNCi imports are included
***lZihani)l pump costs based on inductions in hiom.iss m-ctlianol pioiluuion costs projected hy DOL
-------
alternative fuels yield net pump savings instead of costs for a given
scenario. Specific results of each scenario are discussed more fully below
Under Scenario 1 (maximum utilization of the AMFA fuel economy
credits coupled with the assumption that alternative fuels are used in the
vehicles), the use of methanol results in a net cost when methanol is
produced from any of the feedstocks. This cost ranges from S1.5-S3.2
billion in the year 2000 to $2.5-$7.2 billion in 2010. This net cost is not
due to methanol pump costs per se, since methanol pump prices are
estimated to be competitive or even lower than gasoline pump prices
(depending on the feedstock used to produce the methanol). Rather, this
cost is due to the fact that, under this scenario, CAFE would actually slip by
1.2 mpg; gasoline vehicles would use more gasoline per mile than in the
base case. In effect, total fuel consumption by light duty vehicles is
increased under this scenario, resulting in an increase in net pump costs.
Similar costs are anticipated for the other fuel/feedstock
combinations under Scenario 1. The use of CNG, like methanol, shows a net
cost at the pump for any of the feedstocks; in 2000, the cost ranges from
$2.0-$3.5 billion and in 2010, from $4.6-$8.0 billion. The use of ethanol
produced from corn results in a net cost ranging from $3.0-$4.1 billion in
2000 and $7.4-$10.4 billion in 2010. Ethanol produced from biomass also
shows a net cost at the pump under this scenario; costs of approximately
$2.9 billion for the year 2000 and $4.2 billion for 2010 are estimated. LPG
and electricity were not evaluated in this table, since the AMFA only
provides credits for CNG and alcohol fueled vehicles.
Scenario 2a, the Nine City Program equivalent utilizing a Hat CAFE
and 1.5 percent annual VMT growth, includes the methanol, ethanol and
CNG fuel/feedstock combinations examined above, as well as LPG and
electric vehicles. For methanol, ethanol and CNG, the results are similar to
Scenario 1; all exhibit net costs at the pump. As with Scenario I, this net
pump cost reflects the 1.2 mpg slippage in CAFE which increases the
volume of gasoline used, and hence, lessens the economic benefits of the
(often) less costly alternative fuels. As listed in Tables 6-2a and 6-2b, net
pump costs using methanol under this scenario ranges from S0.7-S2.5
billion in 2000 and $1.7-$6.0 billion in 2010. CNG pump costs are
estimated to range from $1.4-$3.3 billion in 2000 to $4.3-$8.0 billion in
2010. Corn-based ethanol pump costs range from $2.5-$3.9 billion in 2000
and $6.8-$9.9 billion in 2010, while biomass-based ethanol would show a
net cost at the pump ranging from $2.3-$2.4 billion in 2000 to $3.4-$3 5
billion in 2010. The use of LPG would result in a net savings at the pump
between $1.2 billion in 2000 and $3.4 billion in 2010. The use of
6-10
-------
electricity results in a net cost of up to $0.04 billion in 2000 but a savings
of as much as $0.7 billion in 2010 when generated from conventional
feedstocks; electricity generated from municipal waste or solar energy
would result in higher net pump costs.2
In contrast to Scenarios 1 and 2a, where CAFE slippage decreases the
savings which could result from the use of alternative fuels, in Scenarios
2b and 3 it was assumed that no CAFE slippage will occur. Hence, the net
pump costs presented in Tables 6-3 and 6-4 reflect the true net cost to the
consumer of the alternative fuels. As a result, for many of the fuels, a
savings actually results, since the pump price of the alternative fuel
produced from a particular feedstock may be lower than the pump price
for gasoline. Tables 6-3a and 6-3b show that for Scenario 2b (Nine City
program equivalent utilizing DOE fuel economies and VMT projections)
methanol and ethanol use can be a net pump cost or savings, depending on
the feedstock. Methanol coproduced with electricity from coal and
methanol produced from foreign or vented and flared natural gas all show
net savings in both 2000 and 2010, ranging from under $0.1 billion to as
much as $3.6 billion. Methanol produced from biomass and municipal
waste result in a net pump costs for both years, due to the higher pump
prices of these fuels. Ethanol from corn results in a net pump cost of $1.2-
$2.7 billion in 2000 and $1.8-$4.9 billion in 2010, while ethanol from
biomass shows a net cost of about $1.0 billion for 2000 but a net savings of
as much as $1.7 billion by 2010. In 2000, CNG produced from most
feedstocks results in a net pump cost in 2000, while in 2010 the only
feedstock showing a net cost is coal. LPG would result in net pump savings
of $1.4 and $3.6 billion in 2000 and 2010, respectively. In contrast,
electricity use costs between $0.4 and $1.2 billion for the range of years
for conventional feedstocks and even more for the alternative feedstocks.
In Scenario 3, the displacement of one million barrels of gasoline
consumption per day, it is estimated that insufficient quantities of several
feedstocks may limit the use of alternative fuels in a scenario such as this.
These include MSW, Alaskan and vented and flared natural gas, and LPG in
many cases. As Table 6-4a shows, methanol produced from coal or
biomass in 2000 results in a net cost while methanol produced from
vented and flared natural gas shows a net savings; all feedstocks except
biomass would yield a net savings in 2010, as shown in Table 6-4b. Lack
of sufficient com stocks will limit ethanol production in 2010 unless other
feedstocks are utilized; however, biomass-based ethanol could fill the
2As mentioned in Appendix 4, fuel costs and efficiency for electric vehicles is a function of vehicle driving
range. Costs shown here assume a range of 70-90 miles between refuelings; higher driving ranges could
result in significantly higher costs.
6-11
-------
demand and yield a net savings at the pump in the year 2010. CNG from
any feedstock except domestic natural gas in 2000 results in net pump
cost, while in 2010, coal is the only feedstock which still results in a net
cost for CNG use. Electricity produced from any feedstock under this
scenario results in a net cost at the pump for both years considered.
II. Vehicle Costs
As discussed in Appendix 4, additional costs may be incurred for the
production of alternative fuel vehicles. These estimated costs are shown
in Table 6-5. In Tables 6-1 to 6-4, these costs are shown for each scenario,
based on the cumulative vehicle miles traveled by alternative fueled
vehicles.
Table 6-5
Amortized Alternative Fuel Vehicle Costs (cents/mile)
Dedicated
FFV
Methanol
0.0
0.5
Ethanol
0.0
0.5
CNG
1.4
2.5
LPG
1.3
2.3
Electric
8.6
...
An examination of the vehicle costs presented in Tables 6-1 to 6-4
shows that, depending on the fuel, the vehicle costs may contribute either
a relatively small fraction of the total consumer cost (e.g., methanol
vehicles, in most of the scenarios) or a significant fraction of the total cost,
often approaching a fraction equal to or greater than the cost of the fuel
itself (see, for example, the vehicle costs for CNG under most of the
scenarios). As a greater number of dedicated vehicles are used under a
specific scenario, the overall vehicle costs decrease (particularly by the
year 2010 for alcohol-fueled vehicles).
6-12
-------
III. Savings Due to Reductions in Crude Oil Consumption
As discussed in Appendices 2 and 5, U.S reliance on foreign imports,
especially from potentially politically unstable sources, is expected to
continue to increase in the future. Based on DOE's projected energy price
and oil import levels (presented in Appendix 2), the U.S. will pay $185 to
$274 billion/year for imported oil in 2000 and 2010, respectively. The use
of alternative fuels could serve to decrease dependence on foreign oil
imports, lower the price of crude oil (discussed in Appendix 5), and reduce
the energy trade deficit.
Depending on the volume of gasoline displaced, the suppression of
crude oil price could result in substantial societal savings. For example, in
Scenario 3, the one MMBPD gasoline displacement scenario, petroleum
price suppression alone could result in savings of $7 and $15 billion per
year in 2000 and 2010, respectively. Under the same scenario, reductions
in crude oil imports could reduce the national import bill by as much as
$10 billion/year and $24 billion/year in 2000 and 2010, respectively.3
Reductions in crude oil import costs (reduced volume plus reduced
price) as well as in net crude oil costs (reduced consumption plus reduced
price) have the potential to be quite substantial, as shown in Tables 6-6
and 6-7. Table 6-6 shows the savings in imported crude costs. Table 6-7
shows the total crude savings, and is the difference in cost between a non-
alternative and an alternative fuel scenario. The total crude savings are
also used to determine net societal cost, and are presented as credits in
Tables 6-1 to 6-4. When compared to the direct cost of alternative
vehicular fuels, these potential savings are considerable, and in some cases
would more than offset any higher costs associated with alternative fuels.
(This assumes DOE's projected crude oil cost for 2000 and 2010. Obviously,
if future crude costs are higher than those projected, savings associated
with crude oil displacement will be greater. Conversely, if crude costs are
lower than projected, savings will be less.)
3It is possible, of course, that alternative transportation fuel use could lower domestic production, or a
combination of domestic production and imports. Determining which producers would be displaced is
difficult. In this analysis, it was assumed that alternative transportation fuel use would reduce import
levels only.
6-13
-------
Table 6-6
U.S.Savings in Imported Oil Costs ("Sbillion/venr1!
(Attributable to reductions in both volume and price)
Scenario/Year
Methanol Ethanol
CNG
LPG
Electric.
1 2000
2010
0.36
3.33
0.29
3.16
0.76
2.38
2a 2000
2010
1.47
3.81
1.53
4.14
1.97
2.93
3.30
9.28
3.
9,
30
28
2b 2000
2010
2.94
9.62
3.01
9.66
3.70
9.89
3.70
9.89
3.70
9.89
3 2000
2010
7.45
23.97
7.77
23.97
9.03
23.97
9.03
23.97
9.03
23.97
Table 6-7
U.S. Savings on Crude Oil Purchases (Sbillion/vear)
(Attributable to reductions in both volume and price)
enario/Year
Methanol
Ethanol
ONG
LPG
Electric.
1 2000
0.50
0.39
1.06
...
...
2010
4.20
3.97
2.98
2a 2000
2.02
2.12
2.72
4.53
4.54
2010
4.80
5.21
3.96
11.73
1 1.73
2b 2000
4.05
4.18
5.10
5.10
5.10
2010
12.15
12.19
12.48
12.48
12.48
3 2000
10.27
10.73
12.47
12.47
12.47
2010
30.41
30.41
30.41
30.41
30.41
6-14
-------
IV. Effect of an Alcohol Fuels Program on the Federal Budget
Currently, two federal incentives exist for sellers of alcohols and
alcohol fuel blends. One is an exemption of $0.06 per gallon of motor fuel
from the current $0.09 per gallon motor fuel excise tax. This applies to
blends of at least 10 volume percent denatured alcohol (provided the
alcohol is made from renewable resources).4 At 10 percent levels, this is
equivalent to $0.60 per gallon of alcohol. This excise tax exemption
reduces revenues to the Highway Trust Fund which is used to build and
maintain the nation's highways. The other incentive is a blender's income
tax credit of $0.60/gal of denatured alcohol for motor vehicle fuels when
blended with alcohols produced from renewable resources. The intent of
this tax credit is to reduce the cost of alcohol to the blender so that it is
equal or less than the cost of gasoline; the cost of alcohol to a blender is
approximately the sum of the manufacturing and distribution costs of the
ethanol.[1] Because this incentive is an income tax credit, it reduces
revenues to the General Fund as opposed to the Highway Trust Fund.
Only one of these two credits may be utilized by a seller of alcohol
fuels (i.e., only one $0.60 credit per gallon of alcohol). The excise tax
exemption is currently the most utilized credit because of the quicker
return, i.e., rebate of the $0.06/gal tax is as often as excise taxes are paid.
Because income taxes are paid less frequently, the effect of the blender's
credit is delayed, which can adversely affect the cash flow of the seller.
However, in a scenario of near neat or neat alcohol fuel use, the blender's
credit would still be worth $0.60 per gallon of alcohol, but the excise tax
exemption (if continued for high alcohol content fuels) would only be
worth $0.06 per gallon of alcohol for neat fuels and $0.07 per gallon of
alcohol for fuels with compositions of 85 percent alcohol, 15 percent
gasoline.[2] Thus the blender's credit would be more valuable in the
scenarios considered here, and is the only credit considered further.
In the pump price estimates of Appendix 4 and the net economic
impacts of this appendix, a non-subsidized production cost for ethanol and
methanol from renewable feedstocks was assumed. Hence, the highway
trust fund costs which would be imposed under the existing credit
program are not included in this report. If the credits were extended,
ethanol costs (and methanol from biomass) would be $0.60 per gallon
lower than shown in the tables of Appendix 4. These costs would impact
the Federal budget through reductions in General Tax Fund revenues due
4Derived from feedstocks other than coal, oil, natural gas, or peat.
6-15
-------
to the alcohol blender's credit and through changes in agricultural program
outlays. The net effect on the Federal budget may be positive or negative.
Assuming that the blender's credit continues at $0.60 per gallon ot'
alcohol through the year 2010, the cost to the General Fund can be
determined based on the volumes required in the scenarios of this report
as shown in Table 6-8 and as part of the net savings calculation in Tables
6-1 to 6-4. Many states also provide such credits or exemptions from
taxes for ethanol production and use, which of course would affect state
budgets. The impact of state subsidies on state budgets is difficult to
generalize because of the diversity of the credits and fuel requirements.
Table 6-8
General Fund Costs of the Blender's S0.60 per gallon
Income Tax Credit for Ethanol Fuels*
Scenario/Year
Volume EtOH
billion gal/vr
Blender's
Credit
Shi 11 ion/v r.
Scenario 1
2000—F*
2010--D
2 96
6 79
1 776
4 074
Scenario 2a
2000--D
2010--D
3 11
3 99
1 866
4 194
Scenario 2b
2000—D
2010--D
3.11
5.86
I 866
3 516
Scenario 3
2000—D
2010--D
9.64
18.2Q
5.784
10-920
~Note that in the ethanol production costs presented
in the report and in Appendix 4, no tax credit was
assumed for the production of ethanol from corn.
~~F = flexible-fueled vehicle, D = dedicated ethanol vehicle
The net cost to the government of increasing the use of ethanol
produced from corn must also consider the impact of increased ethanol
production on agricultural support programs. There are many types ot
agricultural support programs, such as the Commodity Loan Program.
6-16
-------
Farmer-Owned Reserve Program and the Acreage Control Program, all of
which will be impacted by an increased ethanol program. Generally it is
expected that increased ethanol production will increase corn prices. This
will tend to increase farm income which reduces deficiency payments and
other costs associated with agricultural support programs. Determining the
net effect on agricultural programs, however, is not a simple calculation.
An increased ethanol production will affect the agricultural practices
concerning crop and livestock raising, and their markets, and eventually,
the associated government programs. Additionally, agricultural support
programs are set for only five year intervals, and are subject to many
economic and political considerations. Thus long term determinations of
the effect of an increased ethanol program on agricultural outlays contain
much uncertainty.
Two estimates of the net effect of the blender's credit and
agricultural program cost changes due to increased ethanol demand are
presented here. These studies have final ethanol volumes of
approximately the same magnitude (2-3 billion gallons) as the year 2000
values of Scenarios 1 and 2. No studies were found which estimated the
cost for the larger volumes necessary for the scenarios in 2010. As stated
earlier, the agricultural programs in place in that time frame can not be
anticipated at this time. This report will not attempt to independently
analyze or estimate the cost of agricultural programs due to increased
ethanol production, but will simply present the results of these two
analyses which have attempted to determine the net government cost of
an increased ethanol program.
Although the blender's credit calculation is fairly straightforward,
these two analyses have used complex agricultural econometric models to
determine agricultural program effects. Also, these analyses referred to
the exemption from the motor fuels excise tax (rather than a blender's
credit) because they were concerned with low ethanol content blends. As
stated previously, in a scenario of near neat or neat ethanol fuel use, the
blender's credit would be more valuable.
The first study is a 1988 Department of Agriculture estimate of the
savings in agricultural program outlays and the cost of the ethanol subsidy
(excise tax exemption) for a program which starts at about 800 million
gallons in 1987 and grows nonlinearly to 2.7 billion gallons in 1995.[3] It
was assumed that the 1990 farm bill will be similar to the 1985 Food
Security Act which defined agricultural support programs from 1986-
1990. While the Food Security Act provided for constant target prices for
1986-7 and declining prices for 1988-90, this analysis assumed a non-
6-17
-------
declining target price of $2.75/bu starting in 1990. Additional
assumptions included a market price of $2.36/bu in 1995, and a baseline
of 800 million gallons per year. Table 6-9 shows the DoA yearly estimates
of agricultural outlay savings and subsidy costs. The analysis shows that
the difference between agricultural savings and the cost of the subsidy,
over the baseline, would save about 4 billion dollars over the 1987-95
time frame. However, starting in 1995, agricultural program savings begin
to decline, and in 1997 are zero. The ethanol subsidies from 1995 on
result in a net cost to the government, and by 1999 the 4 billion dollars
previously saved is exhausted.
Table 6-9
Estimates of Agricultural Program Savings and Ethanol Fuel Subsidy Costs
for an Increased Ethanol Demand ("from DoA 1988 131)
Additional
Ag Program
Subsidy
Net
Volume*
Savings
Cost*
Savings
Year
billion eal.
Sbillion
Sbillion
Sbillion
1987
0.1
0.157
0.076
0.081
1988
0.3
0.438
0.171
0.267
1987
0.4
0.653
0.255
0.398
1990
0.6
0.819
0.356
0.463
1991
0.8
1.076
0.467
0.609
1992
1.0
1.383
0.590
0.793
1993
1.2
1.548
0.714
0.834
1994
1.6
1.719
0.952
0.767
1995
1.9
0.990
1.130
-0.140
1996
1.9
0.494
1.130
-0.636
1997
1.9
0.0
1.130
-1.130
1998
1.9
0.0
1.130
-1.130
1999
1.9
0.0
1.130
-1.130
2000
1.9
0.0
1.130
-1.130
*Over a base of 0.8 billion gallons.
The second study is a 1990 GAO estimate for two scenarios of ethanol
expansion over a baseline production of about 890 million gallons.[4] The
two scenarios increase linearly from 890 million gallons in 1989 to 2.2 and
6-18
-------
3.3 billion gallons in 1997. Like the DoA analysis, this study assumed farm
program continuations similar to the 1985 Food Security Act provisions.
Unlike the DoA study, target prices were assumed to decline from 1990-
1995 and remain constant thereafter. Market prices were assumed to
decline as well, from $2.55/bu in 1989 to $2.14/bu in 1997. As stated in
the analysis, changes in the income taxes of farmers, ethanol producers
and the petroleum industry were a few of the associated aspects not
included in the analysis. The final results, shown in Table 6-10, were an
annual average net savings of 0.488 and 0.608 billion dollars over the
1990-1997 time period for the low and high volume scenarios,
respectively, or 3.904 and 4.865 billion dollars in cumulative savings.
While the annual average and cumulative values show a net reduction in
the cost of government programs, yearly differences between the
agricultural program savings and the ethanol subsidy varied from a
negative budget impact of 0.924 billion to a positive impact of 2.7 billion
dollars under the high ethanol volume scenario.
Estimates of Agricultural Program Savings and Ethanol Fuel Subsidy Costs
For an Increased Ethanol Demand f4ll»2
Table 6-10
Final Volume. 1997. billion gallons
2.2
3 3
Agricultural Outlay Reductions
Annual Average ($billion)
Cumulative (Sbillion)
0.93
7.44
1.421
11.371
Ethanol Subsidy ($0.60/gallon)
Annual Average (Sbillion)
Cumulative ($billion)
-0.442 -0.813
-3.536 -6 506
Net Government Savings
Annual Average ($billion)
Cumulative (Sbillion)
0.488
3.904
0.608
4.865
lOver a base of 0.890 billion gallons.
28 year period, 1990-1997.
6-19
-------
Table 6-11 shows the difference in the net government affects
between the DoA and GAO studies for the time period 1990-1997. It
would appear that over this time frame an increased ethanol program
would have a net positive effect on the Federal budget (i.e., reduced net
outlays) which increased with the size of the ethanol program. However,
while the DoA analysis estimated positive net savings until 1994 and
negative savings from then on, the GAO determined that the yearly net
cost could vary positively or negatively. Thus even similar results can be
deceiving. Estimates of the net cost to the government of agricultural
program effects and ethanol fuel subsidies are affected by many factors
such as the size of ethanol expansion estimated, the years of coverage and
the agriculture programs considered, and the future markets and programs
expected. Because of these variables, it is difficult to explore all federal
budget/consumer impacts that may result and conclude a single effect.
Table 6-11
Comparison of DoA and GAO Ethanol Program Federal Budget Impacts 13.41
DoA GAO
Final Volume (billion gallons) 1.9 2.2 3.3
Agricultural Outlay Savings
(cumulative, Sbillion) 8.029 7.440 11.371
Ethanol Subsidy Cost
(cumulative, Sbillion) -6.469 -3.536 -6.506
Net Government Savings
(cumulative, Sbillion) 1.560 3.904 4.865
V. Summary of Economic Impacts of Alternative Fuel Scenarios
The total cost numbers in Tables 6-1 through 6-4 summarize the net
cost (if negative, then the net savings) of each alternative fuel scenario.
Included in these values are the net pump price, the additional alternative
fuel vehicle cost and crude savings.
6-20
-------
Overall, methanol, CNG, and LPG can all result in substantial net
savings for alternative fuel programs, depending on the size of the
program and the type of feedstock used to produce the fuel. However, for
a large or long term alternative fuels program, there may not be enough of
these feedstocks and fuels for the estimated demand. Ethanol can be a net
cost or savings; savings in agricultural program outlays were not included
in this determination, and their inclusion could reduce the cost or increase
the savings. Fuel scenarios utilizing biomass feedstocks tend to be
somewhat more costly and result in less savings than when the fuels are
produced from other feedstocks. Other fuel/feedstock combinations may
yield savings or costs compared to non-alternative fuel scenarios
depending on the assumptions of the scenarios and the time frame
considered.
6-21
-------
References
1. "The Economics of Gasoline Ethanol Blends," R.C. Anderson, et al,
American Petroleum Institute, Research Study #045, November 1988.
2. "Analysis of the Economic and Environmental Effects of Ethanol as an
Automotive Fuel," Special Report, U.S. EPA, Office of Mobile Sources, April
1990.
3. "Ethanol, Economic and Policy Tradeoffs," USDA, ERS, Agricultural
Economic Report No. 585, April 1988.
4. "Alcohol Fuels, Impacts From Increased Use of Ethanol Blended
Fuels," Report to the Chairman, Subcommittee on Energy and Power,
Committee on Energy and Commerce, House of Representatives, U.S. GAO,
July 1990.
5. "Annual Energy Outlook 1990: Long-Term Projections," Energy
Information Administration, Office of Energy Markets and End Use, U.S.
Department of Energy, January 1990.
6-22
-------
Appendix 7
Environmental Impacts of Alternative Fuel Use
Table of Contents
Section Title Page
I. Regulated Pollutant and Air Toxic Impacts 7-1
A. Vehicular Emissions 7-2
1. Regulated Emissions 7-2
a. Introduction 7-2
b. Fuels 7-6
i. Compressed Natural Gas 7-6
ii. Electricity 7-6
lii. Ethanol 7-7
iv. Liquefied Petroleum Gas 7-7
v. Methanol 7-8
2. Air Toxics Emissions 7-9
a. Introduction 7-9
b. Description of Air Toxics 7-10
i. Benzene 7-11
ii. Formaldehyde 7-12
iii. 1,3-Butadiene 7-13
iv. Acetaldehyde 7-13
v. Gasoline Vapors 7-13
vi. Polycyclic Organic Matter 7-14
c. Fuel-Specific Air Toxic Benefits 7-14
i. Compressed Natural Gas 7-16
ii. Electricity 7-17
iii. Ethanol 7-17
iv. Liquefied Petroleum Gas 7-17
v. Methanol 7-18
3. Conclusions 7-18
B. Stationary Source Emissions 7-19
-------
Table of Contents, cont'd
Section Title Page
II. Global Warming Impacts 7-21
A. Overview 7-21
1. Transportation Perspective 7-21
2. Relative Global Warming Potentials
of Greenhouse Gases 7-22
B. Greenhouse Gas Emissions from Transportation
Fuel Use 7-24
1. Gasoline Vehicles 7-25
2. CNG Vehicles 7-27
3. Electric Vehicles 7-28
4. Ethanol Vehicles 7-28
5. LPG Vehicles 7-29
6. Methanol Vehicles 7-29
C Options for Mitigating Greenhouse Gas Increases
Resulting from Alternative Fuel Use 7-30
1. Options for CO2 Control 7-32
2. Economics of CO2 Control Options 7-35
3. Global Warming Benefits 7-36
III. Other Environmental Impacts 7-38
A. Compressed Natural Gas 7-39
1. Refueling 7-39
2. Vehicle Operation and Crashes 7-40
3. Risk of Fire 7-41
4. Maintenance 7-41
B. Electricity 7-42
1. Battery Disposal 7-42
2. Health and Safety 7-42
3. Increased Electricity Generation 7-42
C Ethanol 7-42
1. Spill Issues 7-42
2. Leak Issues 7-44
3. Other Environmental Concerns 7-45
-------
Table of Contents, cont'd
: Section Title Page
D. Liquefied Petroleum Gas 7-45
E Methanol 7-46
Environmental Impacts of Alternative Fuel Use Scenarios 7-47
A. Scenario 1: Maximum Utilization of AMFA Fuel
Economy Credits 7-47
B. Scenario 2: Nine City Program Equivalent 7-50
C Scenario 3: 1 MMBPD Gasoline Displacement 7-56
D. Summary 7-59
ences 7-61
idix 7-A - Greenhouse Gas Emissions from
Transportation Fuel Use 7-A-l
iidix 7-B - Options and Economics for CO: Control 7-B-l
-------
Appendix 7
Environmental Impacts of Alternative Fuel Use
lis appendix presents the environmental impacts of the alternative
iietration scenarios described previously. For each penetration
; and for each alternative fuel/feedstock combination considered,
y effects on emissions of regulated pollutants (VOC, NOx, CO, S02,
¦ tbxics, and greenhouse gases (C02, CH4, etc.) are quantified. In
, other important environmental concerns related to alternative
. such as potential groundwater contamination and spill issues, are
d.
le appendix is divided into four major sections. The first section
Ith regulated emissions and air toxics, and includes a discussion of
r and stationary source emissions for conventional and alternative
tation fuels. The second major section explores the global
impacts of the transportation sector and presents greenhouse gas
factors for different vehicular fuel/feedstock combinations. The
Iction discusses other environmental effects (groundwater, spills,
alternative fuel use. Finally, in the fourth section, the potential
jiental effects of each of the alternative fuel penetration scenarios
i in Appendix 3 are summarized and discussed.
igulated Pollutant and Air Toxic Impacts
bst of the alternative vehicle fuels considered in this report have
jattractive environmental characteristics. All of the fuels are
i to result in lower in-use vehicular emissions of ozone forming
bons (VOC's) than current gasoline vehicles.1 In addition, many of
5 considered (alcohols in particular) would be able to operate under
ibustion conditions, thus reducing CO emissions. Many of the toxic
Is associated with gasoline use would be reduced as well, such as
and 1,3-butadiene, although the potential for increases in other
llutants, such as aldehydes, does exist in some cases.
e Clean Air Act Amendments had not been finalised when this analysis was
, comparisons of emissions relative to reformulated gasoline could not be
uture versions of this Environmental Study will evaluate the emissions of
ted gasoline.
7-1
-------
In addition to vehicular emissions, however, changes in emissions
from fuel production facilities and fuel distribution systems would be
expected to occur as alternative fuels increase their presence in the
marketplace. Certain alternative fuels, such as methanol derived from
natural gas, would likely be manufactured in foreign locations, as some of
the gasoline consumed in the U.S. is currently. Other alternative fuels, such
as biomass based and coal based fuels, would likely be manufactured
exclusively in domestic plants. Emissions from these fuel production
facilities, and the location of those facilities, are thus important
considerations. Both vehicular and stationary source emissions are
discussed in greater detail below.
A. Vehicular Emissions
This section will discuss the impact of the use of alternative motor
fuels on light-duty vehicle emissions. The emissions to be discussed
include both regulated emissions—volatile organic compounds (VOCs) (with
respect to ozone formation), carbon monoxide (CO) and nitrogen oxides
(NOx)—and those unregulated emissions called air toxics. The discussion of
air toxics focuses on those emissions which have been determined to be
proven or probable human carcinogens.
1. Regulated Emissions
a. Introduction
The primary environmental benefit in the area of regulated
emissions of the use of alternative fuels will be reductions in urban ozone
levels. Ozone is formed by the photochemical reactions of volatile organic
compounds (VOCs) and NOx. Some VOCs have greater tendencies (i.e.,
higher reactivities) toward ozone formation. This discussion deals only
with VOC emissions associated with the combustion of a fuel and
evaporative losses from the vehicle; those emissions due to production and
distribution of the fuel are discussed separately. When determining the
ozone-forming HC emissions, only the nonmethane hydrocarbon (NMHC)
fraction is used because methane is considered to be of low reactivity with
respect to ozone formation.! 1]
EPA mass emission data are available only for methanol fuel vehicles
and compressed natural gas (CNG) fuel vehicles, and then by assuming that
the VOC emissions can be grouped as either NMHC, methanol (MeOH) or
formaldehyde (HCHO).[l,2] Emissions from other alternative fuel vehicles
are discussed relative to these emissions.[3] Table 7-1 shows the projected
7-2
-------
Table 7-1
Projected In-Use Organic Emissions Tg/mile')
CFVs
Proposed
Standards
TvDe of Emission
NMH<7
MeOH
HOT
Exhaust
0 53
0.0
0.005
Hot Soak/Diurnal
0.18
0 0
0.0
Running Loss
0 16
0.0
0.0
Rf fueling
0 07
0 0
QJi
Total
0 94
0.0
0.005
Ml 00
Optimized
Vehicles
M85
Optimized
Vehicles
Tvne of Emission
NMHC
MeOH
HCHO
NMHC
M?0H
HCHO
Exhaust
0.050
0.500
0.015
0.150
0.500
0.035
Hot Soak/Diurnal
0.0
0.030
0.0
0.058
0.122
0 0
Running Loss
0.0
0.025
0 0
0.049
0.111
0 0
Refucline
0.0
0.017
0.0
0.053
0,017
0.0
Total
0.050
0.572
0.015
0.310
0.750
0 035
Dedicated CNG Vehicles Dual-Fuel CNG Vehicles
Tvpe of Emission
NMHC
MeOH
HCHO
NMHC
m?qh
HCHO
Exhaust - best
0.057
0.0
0.005
0 119
0.0
0 004
- worst
0.186
0.0
0 004
0 234
0 0
0 004
Hot Soak/Diurnal
0.0
0.0
00
0.180
0.0
0.0
Running Loss
0.0
0.0
0.0
0.160
0.0
0 0
Refueline
0.0
0.0
0.00
0.030
00
OIL
Total - best
0.057
0.0
0.005
0.489
0.0
0.004
- worst
0.186
0.0
0.004
0.604
0.0
0.004
7-3
-------
in-use emissions of VOCs for methanol and compressed natural gas
vehicles. As the table shows, alternative fuels may or may not result in
lower mass VOC emissions than conventionally-fueled (light-duty gasoline)
vehicles.
As stated previously, CO and NOx are the other regulated emissions
primarily associated with light duty vehicles. Limited testing on CNG
vehicles indicates significant CO reductions are possible; however, not
enough data is available on the impacts of alternative fuels on CO and NOx
to confidently quantify these emissions relative to gasoline. Electricity is
the one alternative fuel which will result in no CO or NOx vehicle emissions.
Emissions of CO and NOx from alternative fuel vehicles are expected to be
controlled via engine and catalyst technology. Due to a lack of knowledge
about and development on the specific type of control technologies to be
used, it is difficult to clearly predict CO and NOx emission impacts; these
gases were not included in the analysis in this study.
When determining the ozone-forming potential of motor vehicle
emissions, mass emissions must be considered along with the reactivity of
the various VOCs. By coupling the mass emissions of the above VOCs with
the their reactivity factors relative to NMHC (listed in Table 7-2), gasoline
equivalent ozone-forming VOC emissions can be determined. It should be
noted that these reactivity factors are still preliminary; work is being done
in this area to further develop these factors. The results of this weighting
are shown in Table 7-3. As the table shows, the use of alternative fuels is
projected to reduce the ozone-forming potential of motor vehicle
emissions. This section will further discuss the ozone reductions associated
with each alternative fuel.
Table 7-2
Ozone-Forming Reactivity Factors
Component
Factor
1.0
0.19
2.2
NMHC
MeOH
HCHO
7-4
-------
Table 7-3
Reactivity-Weighted Projected In-Use Organic Emissions fp/milp.l
CFV§
Proposed
Standards
Tvne of Emission
NMHC
HCHO
Exhaust
0 53
0.0
0.011
Hot Soak/Diurnal
0 18
0 0
0.0
Running Loss
0.16
0.0
0.0
Refueling
0.07
JLfl
QJ1
Total
0.94
0.0
0.011
Vehicle Total Organic Emissions 0.951
Ml 00
ODtimized Vehicles
M85
Optimized
Vehicles
Tvpe of Emission
NMHC
MeOH
HCHO
NMHC
MeOH
HCHO
Exhaust
0.050
0.095
0.033
0.150
0.095
0.077
Hot Soak/Diurnal
0.0
0.006
0.0
0.058
0.023
0.0
Running Loss
0.0
0.005
0.0
0.049
0.021
0.0
Refueling
0.003
0.0
0.053
0.003
0.0
Total
0.050
0.109
0.033
0.310
0.142
0.077
Total Organics Emissions
0.192
0.529
Percent Reduction
79.8
44.4
Dedicated CNG
Vehicles
Dual-Fuel CNG
Vehicles
Tvdc of Emission
NMHC
MeOH
HCHO
NMHC
MeOH
HCHO
Exhaust - best
0.057
0.0
0.011
0.119
0.0
0.009
- worst
0.186
0.0
0.009
0.234
0.0
0.009
Hot Soak/Diurnal
0.0
0.0
0.0
0.180
0.0
0 0
Running Loss
0.0
0.0
0.0
0.160
0.0
0.0
Refueling
0-0
0.0
0.00
0.030
0.0
0.0
Total - best
0.057
0.0
0.011
0.489
0.0
0.009
- worst
0.186
0.0
0.009
0.604
0.0
0.009
Total Organics Emissions
- best
0.068
0.498
- worst
0 195
0.613
Percent Reduction
best
92.8
47.6
-
worst
79.5
35.5
7-5
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b. Fuels
i. Compressed Natural Gas
Compressed natural gas (CNG) can be used in dual-fuel vehicles (CNG
and gasoline) or in dedicated CNG vehicles. Use of CNG-fueled vehicles is
expected to significantly reduce ozone formation because the reactive
NMHC are typically only 5-10 percent of total exhaust HC emissions.
Relatively unreactive methane is the other 90-95 percent. By comparison,
in a gasoline vehicle the exhaust is typically 65-95 percent NMHC.
Formaldehyde is also emitted, at about the same levels as from a gasoline
vehicle. Because the CNG system is a closed system, dedicated CNG vehicles
have no evaporative emissions. Dual-fuel CNG vehicles will have
evaporative emissions due to the gasoline, although refueling emissions
will be about half because of less gasoline use.[2] Table 7-1 shows the
projected in-use mass emissions for dedicated and dual-fuel CNG vehicles.
The numbers are from the EPA's Special Report on CNG, and represent a
"worst case" where exhaust NMHC was assumed to equal a full 10 percent
of total exhaust HC. A "best case" scenario was also presented in this
report where fuel NMHC were assumed to equal exhaust NMHC.
The EPA estimates that the gasoline equivalent ozone-forming VOC
emissions would be reduced from 0.95 g/mile for a gasoline vehicle under
proposed standards to 0.07-0.19 g/mile for a dedicated CNG vehicle, and to
0.50-0.61 g/mile for a dual-fuel CNG vehicle.[2] The reductions are due to
the low mass emissions of the highly reactive NMHC. Again, the ranges
represent "best" and "worst" case valuations of the NMHC fraction of total
HC emissions. The "worst" case values are shown in Table 7-3. Although
the NMHC fraction is assumed to have the same reactivity as the NMHC
fraction from gasoline vehicles, it is less likely that the more complex and
reactive VOCs will form because of the simple chemical nature of CNG
relative to gasoline.[3] Assuming a less reactive NMHC fraction will
further reduce the ozone-forming potential of CNG vehicle emissions.
ii. Electricity
Any ozone-forming vehicular emissions associated with electric
vehicles are likely to be small. The VOC emissions impact of electric
vehicles is currently the subject of investigation and will be addressed in
EPA's forthcoming special report on electric vehicle use. However, the
batteries of these vehicles would require charging by power plants, which
would increase stationary source emissions. These are discussed in more
detail below.
7-6
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iii. Ethanol
Ethanol as a motor vehicle fuel is considered here in two forms: as
an 85 percent ethanol/15 percent gasoline blend (E85) and as a neat fuel
(E100). The primary emissions from an E100 vehicle will be ethanol and
acetaldehyde, a two-carbon aldehyde. More acetaldehyde is expected to
be emitted from an ethanol-fueled vehicle than from a gasoline-fueled
vehicle. Formaldehyde will also be emitted, although emission levels are
expected to be similar to those of a gasoline vehicle and much less than for
a methanol vehicle. Almost no ethanol will be emitted.[3] Additional VOC
emissions may occur due to the incomplete combustion of ethanol, and
possibly, fuel additives.
Because of limited emissions data for ethanol vehicles, the ozone-
forming potential of emissions from an ethanol fuel vehicle can only be
crudely estimated by comparing the reactivities of the anticipated
emission components.[3] In the EPA's Special Report on Ethanol, ethanol
was found to be slightly more photochemically reactive than methanol, but
less reactive than NMHC. Recent data show that ethanol may be less
reactive than methanol due to the secondary reactions of acetaldehyde, a
combustion product of ethanol.[4] Acetaldehyde was found to be slightly
less reactive than formaldehyde, but more reactive than NMHC. However,
PAN (peroxyacetyl nitrate), which acts as a reservoir for NOx released
downwind, thereby producing more ozone, can be produced from
acetaldehyde. Another study was mentioned which had determined
ozone-forming potential on a per carbon basis. On this basis, optimized
E85 and E100 vehicles could have potentials for reducing ozone formation
similar to optimized M85 and M100 vehicles. Emissions and city specific
ozone modeling data is needed on optimized E85 and E100 vehicles to
better determine the reduction in ozone-formation that occurs with
ethanol-fueled vehicles compared to gasoline vehicles.
iv. Liquefied Petroleum Gas
Liquefied petroleum gas (LPG) consists primarily of propanes and/or
butanes. As previously stated, LPG for automotive use (HD-5 propane) has
a minimum required propane content of 95 percent. A significant portion
of the emissions from LPG vehicles will thus be propanes and butanes.
Because these are larger molecules than the one and two carbon
compounds, there will likely be a greater variety in the composition of
NMHC emitted, and the assumption of equal reactivities for the NMHC from
light-duty gasoline vehicles and LPG vehicles will be more valid, though
7-7
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still conservative. LPG-fueled vehicles have no evaporative-type
emissions.[4]
LPG vehicle emissions are expected to have a greater ozone-forming
potential than CNG vehicles, but much less than gasoline vehicles.
Currently, there is very little emissions data on LPG vehicles, and the EPA
has not yet issued a "Special Report" on this fuel. More data is needed
before the ozone-forming potential of LPG vehicle emissions can be better
estimated.
v. Methanol
Methanol is considered here in the same two forms as ethanol: as a
blend (M85) of 85 volume percent methanol and 15 percent other HC
(probably gasoline), and as a neat fuel (M100). The methanol fueled
vehicles considered here are those optimized for each fuel. The primary
emissions from M100 vehicles will be methanol and formaldehyde. As
shown in Table 7-1, M100 vehicles will have minor amounts of NMHC
exhaust emissions which are incomplete combustion products of methanol
and possibly fuel additives. Because of the low HC content and low Reid
vapor pressure (RVP) of the fuel, no NMHC evaporative emissions are
expected from a dedicated methanol vehicle. M85, of course, will have
NMHC exhaust and evaporative emissions, but the total NMHC emissions
will be about one-third of the NMHC emissions from light-duty gasoline
vehicles. Even though the composition of the NMHC fraction may differ for
gasoline and methanol vehicles, they are assumed to have the same
reactivities here. Methanol vehicles will have higher methanol and
formaldehyde emissions than gasoline vehicles.
As shown in Table 7-3, per vehicle reductions of gasoline-equivalent
ozone-forming VOC emissions are 44 and 80 percent for M85 and M100
vehicles, respectively, compared to gasoline vehicles.[1] This is primarily
due to lower mass emissions of NMHC and to the low reactivity of
methanol. Note that even though total mass emissions of M85 are greater
than for a conventional fuel vehicle (CFV), ozone-forming potential is
reduced by almost half. Formaldehyde emissions comprise less than 20
percent of the equivalent ozone-forming VOC emissions listed in Table 7-3.
Recent modeling of the South Coast Air Basin has shown that summertime
formaldehyde levels will not change with the use of methanol-fueled
vehicles provided the methanol vehicles meet emissions levels of
comparable gasoline vehicles. In winter, formaldehyde levels may
increase compared to current levels, but will still be below summertime
levels and past (1970's and 1980's) winter levels.[4]
7-8
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2. Air Toxics Emissions
a. Introduction
EPA has estimated that 1500-3000 cancer incidences due to air
toxics occur in the U.S. annually; motor vehicle emissions account for about
58 percent of these.[5] Motor vehicle emissions contribute toxic pollutants
directly and indirectly (indirect emissions are photochemical reaction
products of direct emissions and other atmospheric compounds). Some
directly emitted toxic compounds are uncombusted fuel components while
others are incomplete combustion products. As for VOC emissions, toxics
emissions can occur as evaporative or exhaust emissions; the evaporative
emissions can be further broken down into hot soak/diurnal, running loss,
and refueling emissions.
In the discussion of regulated emissions, it was shown that the use of
alternative fuels can result in a reduced total mass of air toxics emissions
and/or in emissions of less photochemically reactive compounds. Both of
these results can reduce motor vehicle emissions of air toxics. Reducing
mass emissions results in reductions of air toxics and their effects simply
because there are less of them. It is assumed that reductions of NMHC
mass emissions result in proportional reductions of toxics, as will be
discussed further below. Compounds which are less reactive with regard
to ozone formation are likely to form fewer indirect air toxics (depending,
of course, on the specific atmospheric chemistry involved). Thus, in
scenarios of displaced gasoline volume due to the use of alternative fuels
such as compressed natural gas (CNG), electricity, neat ethanol, liquified
petroleum gas (LPG) and neat methanol, the impacts of air toxics on health
effects are expected to change. The nature of these changes is discussed in
more detail below, but a prominent feature is the expected reduction in
cancer risk from air toxics, such as benzene, 1,3 butadiene, and others. In
this section, the primary motor vehicle-emitted air toxics are discussed,
and the emission reductions of the clean alternative fuels are discussed
relative to CFV emissions.
Alternative fuels, by changing the chemistry of emissions, can also
change the potential for health effects. Since more is known about cancer
risks as compared to non-cancer risks, almost the entirety of the discussion
concerns cancer risks. However, non-cancer effects are also of interest.
For non-cancer health effects, there are two major exposure scenarios:
ambient air and microenvironments. In the ambient air, the key issue is
chronic low-level effects; in microenvironments, such as personal garages,
the major issue is brief peak-exposures that have the potential for acute
7-9
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and chronic noncancer effects. For conventional gasoline, the major non-
cancer health risks of interest are for the criteria pollutants (i.e. ozone,
nitrogen dioxide, and carbon monoxide) in the ambient air and air toxics
(e.g., formaldehyde) in microenvironments. Generally, the change of
interest in non-cancer health effects of air toxics emissions is within
microenvironments. Compared to gasoline, microenvironmental exposures
to formaldehyde and methanol could increase with methanol fuels;
acetaldehyde and ethanol levels could increase with ethanol fuels, as could
PAN, which is mutagenic and more injurious to plants than ozone. All air
toxics will likely decrease with electricity. Whether or not these changes
would impact health risks cannot be stated with certainty due to major
gaps in both the health effects and exposure data bases.
However, many of the air toxics of interest can cause health effects.
As examples, formaldehyde can cause pulmonary function effects and lung
irritation, raising concerns that people with pre-existing lung disease such
as asthma may be at risk; acetaldehyde is also a lung irritant. Methanol at
high concentrations has exhibited developmental effects on rats and mice,
effects on the nervous system, and other systems; such effects of inhaled
ethanol, gasoline and other fuels are virtually unknown. Knowing that
these pollutants have the potential of causing effects is quite different
from knowing whether they are likely to cause effects under actual
exposure scenarios. Given the potential range of effects, it is necessary to
achieve sufficient understanding to develop risk assessments for both
conventional and alternative fuels. This need is recognized in both the
AMFA and the Clean Air "Act Amendments. EPA is conducting research on
these issues and is seeking to stimulate private sector research as well,
through ORD's development of the Alternative Fuels Research Strategy,
currently in draft.
b. Descriptions of Air Toxics
EPA has currently identified several air toxics as having serious
health risks and being due, in large part, to emissions from gasoline-fueled
vehicles. Most of the cancer incidence attributed to gasoline-fueled vehicle
emissions is due to five air toxics (single compounds or groups of
compounds): benzene, 1,3-butadiene, formaldehyde, gasoline vapors, and
polycyclic organic matter (POM). The California Air Resources Board has
identified five "high-risk" substances as accounting for 98 percent of that
state's motor vehicle-related cancer incidence. These are, in order of
decreasing risk, benzene, 1,3-butadiene, diesel particulate, formaldehyde
and acetaldehyde. The primary difference between the EPA and CARB lists
is that EPA considered individual as well as groups of compounds while the
7-10
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CARB considered single compounds. The EPA methodology will be followed
in the analysis' presented here.
It is important to note that EPA estimates of cancer incidence are
based on exposure to the various compounds listed, not to the mixture
resulting from the combustion of gasoline. Because gasoline is a complex
mixture, and its combustion products even more so, it is difficult to
estimate cancer incidences from the use of gasoline. In addition, current
estimates of cancer risk do not include consideration of atmospheric
chemistry. Transport and transformation are significant considerations
when extrapolating from emissions to exposure. For example, the toxic
compound 1,3-butadiene reacts much more rapidly than benzene in the
urban environment; therefore, equivalent dispersion exposure models
cannot be used for these two compounds. Also, preliminary irradiation
chamber data suggest that atmospheric transformation of innocuous
organic compounds can produce chemical mutagens. Research into the
correlation between exposure to air toxics and incidences of cancer is
continuing.
Table 7-4 lists the unit risk factors and projected U.S. exposure and
cancer incidence for the year 2005 for the air toxics mentioned above.[6]
Unit risks are the individual lifetime excess cancer risk from continuous
exposure to 1 |ig carcinogen per m3 of inhaled air. Assuming a lifetime of
70 years, the unit risk per year is obtained by dividing the numbers in
Table 4 by 70.[7] The following sections describe these compounds with
respect to their emissions from current mobile sources and potential
reductions due to alternative fuel use. Each air toxic discussion includes
the EPA carcinogen classification (except for POM, which as a composite of
many compounds does not have a classification) as follows:
A = proven human carcinogen
B = probable human carcinogen
(B1 indicates limited evidence from human studies; B2 indicates
sufficient evidence from animal studies but inadequate evidence
from human studies)
i. Benzene
Benzene is present in exhaust, evaporative, refueling and running
loss emissions. It is a known human carcinogen (A). Mobile sources
account for the majority of current benzene-related cancer incidence, and
gasoline-fueled vehicles account for about 97 percent of the mobile source
benzene emissions. Of benzene emissions from mobile sources,
7-11
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Table 7-4
Risk, Exposure, and Cancer Incidence Data for
Motor Vehicle-Related Air Toxics Emissions
2005
Lifetime
Projected
Projected
Unit Risk
Exposure
Cancer
Air Toxic
fat 1 ug/ml^
Cus/mi)
fyg/mil
Benzene
8.3E-06
1.7 - 3.5
67 - 114
Formaldehyde
1.3E-05
27 - 48
Direct
0.52 - 0.59
Indirect
0.90
1,3-Butadiene
2.8E-04
0.13 - 0.15
144 - 171
Acetaldehyde
2.2E-06
0.15 - 0.17
I
Gasoline Vapor
6.6E-07
NA
30 - 119
POM
2.5E-04
0.15
1 - 146
Gasoline Part.
3.3E-03
approximately 82 percent come from exhaust emissions, 16 percent from
eyaporative emissions, and 1 percent from refueling emissions. Use of
alternative fuels will significantly reduce benzene emissions, and thus
cancer incidence due to benzene, for several reasons. First, exhaust NMHC
emissions for many alternative fuels will be reduced. Additionally, the
fuels considered are much simpler with regard to the number of
components in the fuel and the chemical complexity of these components,
and thus benzene will be less likely to be formed during combustion. Also,
most neat fuels will have no evaporative-type NMHC emissions. Dual-fuel
and near neat fuel vehicles will emit benzene in quantities related to the
aromatic content of the gasoline and to the amount of gasoline used.[3]
ii. Formaldehyde
Formaldehyde, a probable human carcinogen (Bl), is emitted directly
by motor vehicles and is also produced by the photochemical reactions of
other VOCs in the atmosphere. It is estimated that the directly emitted
formaldehyde comprises less than 50 percent of ambient formaldehyde
levels (indirect formaldehyde is responsible for 50-90 percent of
7-12
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formaldehyde in ambient air).[8] Mobile sources contribute about 35
percent of the ¦ indirectly produced formaldehyde.[6] Direct formaldehyde
emissions from methanol fueled vehicles are expected to increase relative
to emissions from CFVs. For all other AFVs, however, direct formaldehyde
emissions are expected to be less than or equal to those of CFVs. Exhaust
emission control technology may be able to be modified to specifically
lower direct formaldehyde emissions even more. Because all of the
alternative fuels are expected to reduce the ozone-forming potential of
motor vehicle emissions relative to CFVs, indirect formaldehyde will be
reduced in all cases.
iii. 1,3-Butadiene
1,3-butadiene is a photochemically reactive probable human
carcinogen (B2) present in exhaust emissions. It has the highest unit risk
of the toxics listed, except possibly gasoline particulate. Essentially no
information exists as to the source of butadiene emissions (i.e., the degree
to which emissions are uncombusted butadiene in the fuel, incomplete
combustion products, or recombinations of combustion radicals). Because
exhaust NMHC emissions will be reduced when AFVs are used, and
butadiene is not likely to be a combustion product of alternative fuels,
cancer incidence due to 1,3-butadiene will also be reduced by the use of
alternative fuels.
iv. Acetaldehvde
Acetaldehyde is a probable human carcinogen (B2) emitted in CFV
exhaust and formed photochemically in the atmosphere. Acetaldehyde is
one of the primary emissions from neat ethanol vehicles. It has a lower
unit risk than formaldehyde, and in CFVs it is emitted at lower rates than
formaldehyde.
v. Gasoline Vapors
Whole gasoline vapor has been classified by EPA as a probable
human carcinogen (B2). While gasoline vapor can include vapors of all the
gasoline components, is possible that the specific carcinogens are certain
compounds in the family of C6-C9 branched aliphatic hydrocarbons, but
this is not certain. The range of predicted cancer incidence rates for
gasoline vapors listed in Table 7-4 reflects, on the low end, those due
solely to the C6+ fraction, and on the high end, those due to all gasoline
vapors. As gasoline vapor emissions are an evaporative phenomena,
cancer incidence due to gasoline vapor will be reduced when alternative
7-13
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fuels are used because of the reduced evaporative NMHC emissions of
alternative fuels, including little or no refueling emissions. Additionally,
because of the chemical simplicity of the alternative fuels relative to
gasoline, higher order compounds (NMHC) are unlikely to form.
vi. Polvcvclic Organic Matter (including Particulate 1
Polycyclic organic matter (POM) is a widely varying group of
chemicals which are formed from the incomplete combustion of fuel and
oil. Heavier POM, which can condense or adsorb onto particulate matter,
has greater deleterious health effects than the lighter POM found in the
vapor phase. POM on particulate matter can be subject to further chemical
transformation in the exhaust and in the atmosphere. Although most
particulate matter comes from diesel vehicles, particulate from gasoline-
fueled vehicles, which emit 30-100 times less particulate per mile than
diesel vehicles, has one of the highest unit risks of the listed toxics. POM
and particulate will decrease with the use of AFVs because exhaust NMHC
emissions will be reduced. Additionally, most of the alternative fuels are
chemically simple compounds, and hence formation of heavier, complex
molecules like POM is unlikely.
c. Fuel-Specific Air Toxic Benefits
In Table 7-5, cancer incidence due to specific types of emissions of
specific air toxics are shown for CFVs under the President's proposed
standards which are very similar to the Tier I standards contained in the
Clean Air Act Amendments of 1990. The cancer incidence values listed in
Table 7-5 differ from those presented in the Methanol Special Report [1]
for the following reasons. Under the President's Clean Alternative Fuels
Program, new VOC emissions standards were proposed for gasoline
vehicles. In the Methanol Special Report, these new standards were
presented along with the current standards for gasoline vehicles and an
estimated total of 69 cancer incidences for the nine severe extreme ozone
nonattainment areas in 2005 following implementation of the President's
proposed emission standards. The cancer incidence values based on these
proposed VOC standards were calculated assuming a 39.1 percent
reduction in cancer incidence from the base cancer incidence values for
each toxic (based on existing VOC standards). The estimates thus did not
include the effects of VOC reduction on air toxics emissions.
7-14
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Estimated
Cancer
Incidences
(Ch from
Exposure
to Air Toxics1
CFV
Proposed
Standards2
Optimized M100
Emissions
% Red CI
Optimized M85
Emissions
% Red CI
Dedicated
Emissions
% Red
CNCi
CI
Dual-Fueled
Emissions
% Red CI
Exhausi Benzene
14.156
90 6
1.3
71.7
4 0
besi
worsl
89.2
64 9
1.5
5 0
77 6
55 8
3 1
6 2
Evap. Benzene
1.583
100 0
0 0
67.8
0.5
100 0
0 0
0 0
1 7
RunLoss Benzene
0.764
100 0
0 0
69 4
0 2
100 0
0 0
0 0
0 8
Refuel Benzene
1 092
100 0
0 0
24 3
0 8
100 0
0 0
57 1
0 5
Gasoline Vapor
6 724
100 0
0 0
24 3
5 1
100 0
0 0
57 1
2 9
Exhausi 1,3-Bul.
24 586
90 6
2 3
71 7
7 0
best
worsl
89 2
64 9
2 6
8 6
77 6
55 8
6 6
10 8
Exh. Gasoline PCM
19.122
90 6
1 8
71 7
5 4
best
worst
89 2
64 9
2 1
6 7
77 6
55 8
4 3
8 4
Dir. Formald.
1.614
-200 0
4.8
-600.0
11.3
best
worsl
0 0
18 2
1.6
1.3
18 2
18.2
1 3
1.3
Indir. Formald.
3.938
79.8
0.7
44.4
2.2
best
worst
92 8
79 5
0 3
0.8
47 6
35 5
2.1
2 ,5
TOTAL
73.579
11.1
36.5
best
worsl
8 1
22 4
22 1
35 1
% Reduction
84.9
50 4
best
worsl
89 0
69 5
70 0
52 3
1 See text, pages 7-14 through 7-18, lor assumptions underlying these projections
^ Year 2005 caiiLer incidence (CI) iii 9 severe/extreme o/.one nonutlainmcnt areas
-------
The cancer incidence values shown for clean-fueled vehicles (CFVs)
in Table 7-5 include the effect of the VOC emission reductions which occur
in going from the current to the proposed emission standards. In this
report, changed in cancer incidence associated with the use of alternative
fuels are compared to these more recently determined cancer incidence
numbers.
The changes in NMHC, methanol and formaldehyde emissions due to
the use of alternative fuels are applied to the specific cancer incidence as
follows. As previously mentioned, changes in NMHC emissions are
assumed to proportionately affect cancer incidence due to toxics that are
NMHCs. Thus exhaust NMHC reductions are assumed to reduce exhaust
benzene, 1,3-butadiene, and POM. Evaporative, running loss and refueling
NMHC emissions changes likewise affect cancer incidence due to
evaporative, running loss and refueling benzene emissions, respectively.
Changes in refueling NMHC emissions are assumed here to also affect
cancer incidence due to gasoline vapors. Direct formaldehyde emissions
changes affect only direct formaldehyde cancer incidence. Indirect
formaldehyde cancer incidence is reduced in proportion to the total change
in gasoline equivalent ozone-forming VOC emissions.
There is, however, some uncertainty in the assumption that cancer
incidence will decrease proportionately with decreases in NMHC emissions
that requires mention. Cancer risk, as related to mobile sources, is a result
of exposure to effective levels of a complex mixture containing pollutants
of. differing cancer activities. Since all NMHC do not have equivalent cancer
characteristics, cancer risk depends upon the specific mixture of NMHC.
Thus, the benefits to cancer risk are a result of the specific nature of the
change in the complex mixture that will occur with alternative fuels.
However, the complex mixture of pollutants from both gasoline and
alternative fuels is not yet fully characterized, creating uncertainty in
predicting changes in cancer risk. For example, benzene levels and hence
risk will decrease, but it is conceivable that other carcinogenic compounds
could be formed or increased or that the proportionality of existing NMHC
carcinogens could change. Ongoing research programs by EPA and
industry will elucidate these issues.
i. Compressed Natural Gas fCNG'l
Per vehicle reductions in cancer incidence for dual-fuel and
dedicated CNG vehicles are expected to be 52 and 70 percent,
respectively.[2] The greatest percent reductions for dual-fuel vehicles
occurs for exhaust and refueling associated cancer incidence. Although
7-16
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other evaporative emissions are similar to CFVs for dual-fuel vehicles,
refueling emissions were estimated at half the CFV emissions because of
less refueling.[2] Dedicated CNG vehicles have no evaporative NMHC
emissions and thus no associated cancer incidence. Cancer incidence due to
indirect formaldehyde was reduced for both types of CNG vehicle due to
the overall reduction in the ozone-forming potential of VOC emissions.
ii. Electricity
Since electric vehicles are expected to have no mobile source
emissions, there will be no associated cancer incidence (i.e., a 100 percent
reduction compared to CFVs).
iii. Ethanol
Because of limited emissions and health effects data for ethanol.
cancer incidence can only be discussed relative to gasoline and methanol
fuels. Although acetaldehyde is a primary emission from ethanol fueled
vehicles, it is less carcinogenic than formaldehyde, and most of the
carcinogenicity associated with ethanol will be due to the formaldehyde.[3]
Formaldehyde emissions from ethanol fueled vehicles are expected to be
similar to those from CFVs. If total reductions in ozone-forming VOC
emissions due to the use of ethanol are similar to those due to the use of
methanol fuels, indirect formaldehyde will be reduced relative to CFVs.
Another concern is the formation of PAN from acetaldehyde emissions,
which can lead to increased ozone formation as well as possibly having
serious human health implications. Overall, the EPA estimated that ethanol
use will yield cancer incidence reductions of the about the same magnitude
as shown for methanol in Table 7-5.[3]
iv. Liquefied Petroleum Gas ("LPG)
As stated in the LPG discussion of regulated emissions, limited data is
available on LPG vehicle emissions, and thus no extrapolation to cancer
incidence can be made at this time. The cancer incidence due to LPG use
will likely be greater than that due to CNG but less than the cancer
incidence due to CFVs. Limited speciation data have shown reduced toxics
levels and reactivity compared to gasoline emissions.[4] LPG emissions
are likely to be more photochemically reactive which could increase
indirect formaldehyde cancer incidence compared to CNG vehicles, but
cancer incidence would still be less than from CFVs. The data in this
analysis, however, assume equal reactivity for all NMHC. Because LPG
7-17
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has no evaporative emissions, those cancer incidence due to evaporative
toxics will be eliminated.
v. Methanol
As shown in Table 7-5, per vehicle cancer incidence due to methanol
vehicles is estimated to be reduced by 50 and 85 percent, respectively, for
M85 and M100 optimized vehicles. The reductions in M85 vehicles are
due to lower emissions of exhaust and evaporative NMHC which directly
reduce all of the source specific toxics listed in Table 7-5 (except
formaldehyde). Because M100 has no evaporative emissions, greater
reductions are achieved. As expected, cancer incidence due to directly
emitted formaldehyde increases, but because of the lower ozone-forming
potential of the VOC emissions of both M85 and M100, cancer incidence
due to indirect formaldehyde decreases. While the aspect of higher direct
formaldehyde emissions is used by some to downplay the benefits of
methanol, considerable uncertainties exist regarding the increased
carcinogenic potential of formaldehyde due to MFVs relative to other
sources, including CFVs. Cancer incidence is further reduced if it is
assumed that the NMHC from MFVs is less reactive than that from CFVs
due to the chemical simplicity of the methanol molecule.
3. Conclusion
The use of clean alternative fuels will substantially reduce the ozone-
forming potential of motor vehicle emissions relative to the use of gasoline.
The type of reduction depends on the fuel used, but can include mass
emission reductions and emission of compounds which are less
photochemically reactive. About an 80 percent reduction in the gasoline
equivalent ozone-forming VOC emissions is expected with the use of neat
alternative fuels in optimized vehicles, and about a 40 percent reduction
with the use of near neat-fueled and dual-fueled optimized vehicles.
The use of clean alternative fuels is also expected to reduce the
cancer incidence due to motor vehicle-emitted air toxics. Per vehicle
cancer incidence reductions of about 80 percent for neat fuels used in
optimized vehicles and about 50 percent for near neat-fueled and dual-
fueled optimized vehicles are estimated. Sparse emissions data on
dedicated and flexible-fuel alternative fuel vehicles limits further
comparison of the air toxics benefits of alternative fuels relative to
gasoline. Additionally, the carcinogenicity and other health effects of the
prominent air toxics are still debated. One recent area of study is the
possible carcinogenicity or cocarcinogenicity of ozone; there is no
7-18
-------
conclusive data yet. While cancer incidence is the primary factor in
comparing air toxics effects, other detrimental health effects occur as well,
for both CFVs and AFVs. Finally, dedicated, optimized alternative fuel
vehicles are more desirable than flexible or dual-fueled vehicles because
much of the air quality and toxics benefits are substantially reduced when
FFVs are used.
B. Stationary Source Emissions
The displacement of gasoline by some form of alternative fuel will
also affect stationary source emissions. A brief discussion of the emission
impacts of various alternative fuel production technologies ~nd the
stationary source impacts of alternative fuel use are presented below.
In order to estimate the stationary source emission effect of
alternative fuel use, gasoline-related emissions from refineries must be
compared to emissions related to the production of alternative fuels.
These are shown in Table 7-6 as compiled from several sources in the
literature.[9,10,11] In section IV of this appendix an overall assessment of
the relative contribution of stationary and mobile sources is made using
these emission factors.
As shown in the table, emissions of VOC, carbon monoxide, and toxics
from refineries are generally greater than those from other fuel production
facilities. Emissions of nitrogen and sulfur oxides from fossil fuel burning
utilities are much greater than other facilities including refineries.2 The
emissions estimates for all of these sources are based upon current
regulations and technology. It is reasonable to assume that declines in
emissions in all the stationary sources will occur in the future. For many
of the alternative fuel production processes considered, information on
emissions is somewhat limited, due to the fact that such facilities are not in
widespread use. Thus, the figures presented in the table should be
considered as initial estimates; additional analysis in this area would be
desirable.
Under each of the alternative fuel penetration scenarios discussed in
this report, use of alternative fuels would likely be concentrated in large
urban (and likely coastal) areas. Only a small portion of gasoline consumed
in urban coastal areas is currently imported as a finished product (only 2%
2The majority of electrical generating capacity in the U.S. is coal based, and produces
high emissions of NOx, SOx, and particulates. Natural gas also produces large
quantities of NOx, but much less SOx and particulates.
7-19
-------
Tabic 7-6
FUEL PRODUCTION EMISSIONS
(G/MMBTU OUTPUT)
CNG1 ELECTRICITY2
Domestic
Foreign
Vented/
Alaskan
Refinery
Municipal
Natural
Natural
Flared
Natural
Feedstock
Oil
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Conventional
MSW
Solar
Emissions(ion/yr.)
VOC
40
20
20
20
0
0
0
0
1
1
0
NOx
12
32
32
32
0
0
0
0
260
260
0
CD
20
6
6
6
0
0
0
0
10
10
0
SO2
50
8
0
0
0
0
0
0
60
0
0
Air Toxics
1
1
1
1
0
0
0
0
0
0
0
Particulate
1
20
20
20
0
0
0
0
50
50
0
ETHANOL3 LPG4 METHANOL5
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG
(Dedicated)
(Coproduced)
Biomass
Waste
Gas
Gas
Gas
Emissions (ton/yr.)
VOC
5
1 2
20
20
20
20
0
0
0
NOx
100
3.6
32
32
32
32
0
0
0
CD
1 0
6
6
6
6
6
0
0
0
SC>2
500
1 5
8
8
0
0
0
0
0
Air Toxics
1
0.3
1
1
1
1
0
0
0
Particulate
1 0
0.3
20
20
20
20
0
0
0
' Compressed Natural Gas. The production of natural gas produces few (and assumed zero) emissions. Tbe production of synthetic natural gas from coal, biomass, or waste is assumed to
have the same emission factors as tbe production of methanol from these sources as they would entail the use of a gasificr, which is tbe main source of emissions u a synthetic fuels plant
Toxic emissions from gasifiers were assumed equivalent lo refineries for lack of a belter estimate. Production of CNG from biomass or waste may be accomplished by biogasification
significantly reducing total emissions from these listed here
^Electricity Generation Emissions from electricity generation were based upon a weighted average of the curreot US electrical generation capacity shown in Table 7-2 below Ihe type of
power plant thai would be used lo produce tbe needed electricity depends upon the regtoo of the country. Coal burning is responsible for high SOXv NO*. and paniculate emissions in the
average. Natural gas burning also produces larger quantities of NOx.
Energy Mia Used in the Generation of Electricity (12). Nationwide - Coal - 54 7%, Oil = 4 6%, Natural Gas = 106%, Other = 29 9%
^Ethanol: The production of ethanol from corn requires external energy of which the majority is supplied from a power plant burning fossil fuel, primary coal These power plants are
responsible for the emissions shown in Table 7-1 Reci.nl developments in dehydration of ethanol are eliminating the need for benzene which is the primary source of toaic emissions
^Emission from LPG production were assumed to bc30% of a refinery since LPG production from oil constitutes only 30% of the production of LPG Ihe remaining 70% is produced from
natural gai
^Methanol Ihe emissions from methanol production fiom natural gas an much lo*er (and assumed zero for this analysis) than from coal as the main producer of emissions for a coal lo-
meihanol plant is the gasificr Ihe production of methanol from wastes or biomass would produce similar or lower emissions as that for coal
-------
of the western and 15% of the eastern United States consumption). Thus,
any gasoline -displaced as a result of alternative fuel use would likely be
that produced at domestic refineries3, primarily those located in urban
areas where environmental pressures are strongest.
The actual location of new alternative fuel production facilities is also
an important consideration. Alternative fuel production facilities could be
located in either urban or rural areas depending on the type of feedstock
being used and the location of the market for the fuel. It may be
reasonable to assume that most facilities would be located near raw
material sources, with the exception of electrical generating facilities due
to transmission losses. However, due to the lack of any concrete evidence
on the location of alternative fuel production facilities, no distinction
between urban or rural emissions was assumed. The actual location of
hypothetical fuel production facilities is difficult to determine, and more
study of this issue is necessary before firm predictions can be made.
II. Global Warming Impacts
A. Overview
One issue which has come the the forefront in the assessment of
alternative transportation fuels relates to the effect that the use of such
fuels would have on the "greenhouse effect," or global warming. The
combustion of fossil fuels has been identified as one of the major
contributors to the increase in concentrations of atmospheric C02 since he
beginning of the industrialized era, as well as the build-up of other
greenhouse gases such as CH4 and N2O. In this section, the impact of
various alternative fuels on the amount of C02 and other trace greenhouse
gases released into the atmosphere is considered.
1. Transportation Perspective
In dealing with this issue it is important to place the U.S.
transportation industry in the proper perspective. Global estimates
indicate that at present over 5 quadrillion grams of carbon are released
3 One reason why displacement would probably occur at domestic refineries is that
U.S. refineries typically produce a higher percentage of gasoline (higher
conversion) than foreign refineries. Economic pressures resulting from a reduction
in gasoline demand would probably dictate that domestic refiners would reduce the
severity of upgrading processes before foreign refiners would reduce gasoline
production.
7-21
-------
into the atmosphere via fossil fuel combustion each year.[12] Estimates of
the effective C02 release due to deforestation are on the order of 1
quadrillion grams of carbon per year. For comparison, the U.S.
transportation industry currently consumes about 125 billion gallons of
fuel each year, which ultimately results in emissions of about 0.4
quadrillion grams of carbon annually, about 7 percent of global
anthropogenic C02 emissions.[13]
The U.S. transportation industry also contributes to greenhouse gas
emissions through the release of trace greenhouse gases such as methane
(CH4), nitrous oxide (N2O), and chlorofluorocarbons (CFC-12), contributing
0.1, 0.7, and 11.0 percent to global emissions of these pollutants,
respectively. Automobiles also contribute to global warming through
emissions of hydrocarbons (HC) and oxides of nitrogen (NOx) which
produce tropospheric ozone (another greenhouse gas) and through
emissions of carbon monoxide (CO), which slows the natural removal of
methane from the atmosphere. As shown in Figure 7-1, excluding
tropospheric ozone effects, the U.S. transportation industry currently
accounts for roughly 7.5 percent of global greenhouse gas emissions
(roughly 30 percent of national greenhouse gas emissions).
While the U.S. transportation industry accounts for only a small
fraction of global greenhouse gas emissions, its contribution cannot be
ignored. The industry is one of the single largest individual contributors to
global warming, and thus the effects of any change in U.S. transportation
fuels or policy should be evaluated carefully. Switching a portion of the
U.S. fleet from import-based gasoline to an alternative fuel could result in
either a global warming benefit or detriment, depending on vehicle
technology and the type and source of the energy feedstock used to
produce the fuel. A more detailed discussion of the global warming
impacts of the various fuel/feedstock combinations evaluated in this
report is presented below.
2. Relative Global Warming Potentials of Greenhouse Gases
The relative global warming contribution of emissions of various
greenhouse gases is dependant on their radiative forcing, atmospheric
lifetime, and other considerations. For instance, on a mass basis, the
radiative forcing of CH4 is much higher than that of C02; however,
methane's effective atmospheric residence time is much lower than that of
carbon dioxide. Other gases, such as CFCs, have both long residence times
and high radiative forcings. The relative global warming impacts of
7-22
-------
U.S. TRANSPORTATION INDUSTRY
CONTRIBUTION TO GLOBAL WARMING
(percent)
Other
92.5%
C02
5.6%
CH4,C0,N20
0.4%
CFC-12
1.5%
Weighted Greenhouse Gas Emissions (Based on OPPE, IPCC)
-------
various greenhouse gases, with consideration given to atmospheric
lifetimes and indirect warming effects, were used to determine "C02
equivalent" emissions for each of the alternative fuel scenarios evaluated
in this report. The preliminary global warming potentials presented by
the Intergovernmental Panel on Climate Change (IPCC) were used in this
analysis, and are shown in Table 4.134] As indicated in the table, the IPCC
has calculated different global warming potentials for different time
horizons, 20 to 500 years, which reflecting the "short term" and "long
term" global warming effects of these gases. As can be seen, even though
the magnitude of vehicular emissions of CH4, N2O, and CO are significantly
lower than emissions of CO2, their importance with respect to global
warming is not insignificant.
Table 7-7
(per unit mass
of emission)
Time
Horizon
Greenhouse
Gas
500 vr
20 vr
C O2
1
1
CO
2
7
CH4
9
63
N2O
190
270
CFC-12
4500
7100
B. Greenhouse Gas Emissions from Transportation Fuel Use
In this section, the C02 and trace greenhouse gas production
resulting from the use of gasoline and alternative transportation fuels is
examined. Emissions occurring at all points in the fuel use chain, from
resource extraction, fuel processing, fuel distribution, and vehicular
combustion are determined.4 It should be noted that the level of CO2
emitted is a function of the carbon content of the fuel. Control of CO2 must
thus be directed at the fuel efficiency of the vehicle or fuel production
4Emissions from the manufacture and assembly of vehicles should also be considered,
for completeness. Differences in manufacturing emissions between vehicle types
appear to be small, however, and have not been evaluated in this report.
7-24
-------
process, and is not controlled merely by the addition of emission control
"technology. An overview of the analysis results is presented in Table 7-8,
and in the text below. The range presented represents both long term and
short term effects, based on the GWPs given above. A more detailed
description of the analysis and calculations is provided in Appendix 7-A.
1. Gasoline Vehicles
As can be seen from Table 7-8, a gasoline fueled vehicle certifying
to a CAFE standard of 27.5 mpg (with corresponding in-use fuel economy
of 23.1 mpg) produces between 570 and 720 grams of C02-equivalent
emissions per mile travelled, depending on the location of the crude oil
source (domestic or foreign) and the trace gas global warming potential
factors assumed.5 The vast majority of these emissions occur at the
vehicle; the rest are released at various points in the fuel supply chain,
primarily during refining. Additional details on the analysis of greenhouse
emission from gasoline vehicles is provided in Appendix 7-A.
As stated above, gasoline displaced by the use of alternative fuels
would likely be import based. As stated in Appendix 3, the most likely
point of introduction for alternative fuels is in coastal high-ozone cities,
where the environmental benefits of alternative fuels can be fully utilized,
and where the high population of vehicles make the economics of
alternative fuel distribution most favorable. Much of the gasoline
currently supplied to these areas, and an increasing amount in the future,
originates in foreign countries. As alternative fuel use displaces gasoline,
shipments of imported oil will likely diminish. Thus, for the global
warming analysis, it was assumed that all gasoline displaced from the U.S.
transportation market would be import based. This is reflected in the
comparisons made in Table 7-8. The use of reformulated gasoline may
change the greenhouse gas emissions associated with gasoline somewhat.
Reformulated gasoline will be added to the analysis when composition and
emissions data become available.
5 The actual emission factor for gasoline vehicles is dependent on the actual fuel
economy of the vehicle. As was described in Appendix 3, the CAFE credits resulting
from the sale of alternative fueled vehicles may, under some scenarios, cause the fuel
economy of new gasoline vehicles to "slip" slightly, thus increasing the amount of
fuel consumed per mile travelled. Under such a scenario, total emissions of C02 from
gasoline vehicles would be proportionally higher.
7-25
-------
mmmmm
wmmmm*
Fuel Source / Type
Crude/Gasoline
Domestic Gas/CNG
Domestic Gas/Methanol
Domestic Gas/Elccuic
Remote Gas/CNG
Remote Gas/Methanol
Coal/CNG
Coal/Mcthanol
Coal/Electric
Biomass/CNG
Biomass/Methanol
Biomass/Ethanol
Biomass/Elecuic
MSW/CNG
MSW/Methanol
MSW/Electric
LPG/LPG
TABLE 7-8: Greenhouse Gas C02 Equivalent
Range: Lower to Upper limit of Emissions Possible
mm
600 800
CC)2 I:i|invalciil
L.J r 1 111111 i8 l.ower l.imil
-------
2. CNG Vehicles
CNG vehicles can offer global warming benefits or detriments relative
to gasoline vehicles, depending on the origin of the natural gas and the
type of CNG vehicle technology used. As shown in Table 7-8, dedicated
CNG vehicles exhibit global warming benefits relative to dual-fueled CNG
vehicles due to their higher engine efficiency. When fueled with CNG
derived from domestic natural gas, both dedicated and dual-fueled CNG
vehicles offer greenhouse gas reductions ranging from 16 to 39 percent
relative to import based gasoline vehicles. Use of remote natural gas
would detract from the global warming benefits of CNG use, due to the
additional energy required to liquefy and transport foreign natural gas
resources to the U.S. Under such a scenario, CNG would offer benefits of 1
to 25 percent over gasoline use.
The use of CNG produced from biomass or solid waste, or from gas
which is currently vented and flared would offer significant advantages
relative to gasoline, due to the renewable nature of the feedstock. Using
the production technologies described in Appendix 4, CNG derived from
biomass can offer emission reductions of 78 percent for DFVs and 81
percent for dedicated vehicles. The global warming benefits associated
with municipal waste-based CNG are similar, at 82 and 85 percent
reductions for dual fuel and dedicated vehicles, respectively.6 As shown in
Table 7A-1 in Appendix 7-A, a decrease of up to 115 percent relative to
gasoline vehicles is projected in the 500 year timeframe for vehicles
operating on CNG produced from vented or flared natural gas. In contrast,
CNG vehicles operating on coal-based synthetic natural gas could produce
nearly twice the emissions of greenhouse gases as their gasoline
counterparts.
In summary, the use of CNG as a vehicle fuel could result in any of a
number of global warming effects, from a 93 percent increase to as much
as a 115 percent decrease in greenhouse gas emissions, depending on the
location and type of energy resource used to produce the gas. Additional
details of the analysis of greenhouse gas emissions from CNG vehicles is
presented in Appendix 7-A.
6The benefits of biomass and municipal wastes as fuel feedstocks could approach 100
percent if production processes were redesigned to maximize C02 emission reductions
(i.e. use renewable fuels to provide process energy).
7-27
-------
3. Electric Vehicles
In addition to offering excellent emission characteristics, electric
vehicles could also provide significant global warming benefits relative to
gasoline vehicles. Actual global warming benefits will depend on the
means of electricity production employed, however. The sources of
electricity for electric vehicles evaluated in Appendix 4 include fossil fuels
(coal and natural gas), solar energy, biomass, and municipal waste. As
shown in Table 7-8, if electricity from coal or natural gas is used, the
greenhouse gas emissions from electric utilities could be less than or equal
to those due to gasoline production, resulting in C02 equivalent emissions 0
and 41 percent lower than import based gasoline, respectively.7 If any of
the other feedstocks is used for electricity production, substantially greater
global warming benefits would occur. The lower limit values for EVs
shown in Figure 8 are based on a vehicle providing a driving range of 70 to
90 miles before recharging. If a vehicle range similar to that of a gasoline
vehicle were required, the added weight of the necessary batteries would
significantly reduce the performance and efficiency (and consequently
increase C02 emissions) of the vehicle, as illustrated by the upper limit
values.8
4. Ethanol Vehicles
The CO2 emissions due to ethanol production and use have been
estimated, and are compared to the C02 emissions due to the production
and use of imported gasoline. In each step of the cycle, all significant CO2
emissions that come from non-renewable energy, and therefore contribute
net positive amounts of C02 to the atmosphere, have been quantified. Both
corn and cellulosic biomass have been considered as ethanol feedstocks.
CO2 emissions due to the combustion of ethanol in motor vehicles are
not considered a net positive contribution of C02 to the atmosphere
because they are assimilated by the next crop. However, greenhouse gas
emissions due to other processes associated with the production of ethanol
fuel, such as corn farming, fertilizer manufacture and ethanol and
7This relatively small change relative to gasoline vehicles is due, in part, to an
increase in NOx emissions resulting from the combustion of fossil fuels at utilities.
Increased NOx emissions would lead to increased ozone formation.
8 It is doubtful that a 3S0 mile range could be achieved at all with Lead-Acid or Nickel-
Iron battery technologies. It is possible that Sodium-Sulfur battery technology could
be used to achieve a driving range commensurate with gasoline vehicles, albeit at
the loss in efficiency and increase in greenhouse gas emissions described above.
7-28
-------
byproduct production, do contribute net positive amounts of greenhouse
gases to the atmosphere because these processes are primarily fueled by
non-renewable fossil fuels. Use in a dedicated vehicle running on corn-
based ethanol could result in reduced emissions of 11 percent. The use of
biomass-based ethanol in a dedicated vehicle could result in reductions of
as much as 68 percent.9
Clearly a number of uncertainties exist in the quantity of C02
emissions from various stages of ethanol manufacture. Determination of
energy requirements and allocation of byproduct credits could result in a
net increase or decrease in CO2 emissions from ethanol fuels. However,
future plants and expansions are likely to be more energy efficient. This,
along with increasing yields, could reduce CO2 emissions due to ethanol
fuels.
5. LPG Vehicles
As shown in Table 7-8, LPG vehicles offer moderate greenhouse gas
reductions of 14 to 26 percent relative to imported gasoline. Our analysis
assumes only domestic LPG resources. Because the vast majority of these
emissions are due to the vehicle, the reductions achieved are highly
dependent on vehicle efficiency, as discussed in Appendix 4. A LPG
vehicle efficiency of -5 percent relative to gasoline vehicles was assumed
in this analysis.[15] Improvements in LPG vehicle efficiency would yield
significant additional global warming benefits. The LPG production cycle,
including LPG extraction, processing, and transmission, and LPG vehicle
emission factors are discussed more thoroughly in Appendix 7A.
6. Methanol Vehicles
As with CNG vehicles, the use of methanol as a vehicle fuel can offer
global warming benefits or detriments relative to gasoline vehicles,
depending on the feedstock used to produce the fuel methanol and the
type of methanol vehicle (FFV or dedicated) used. It is assumed that
vehicles are fueled with M85, with domestic crude supplying the 15
percent gasoline, while dedicated vehicles would use M100. As shown in
Table 7-8, dedicated methanol vehicles exhibit global warming benefits
relative to flexible fueled methanol vehicles due to their higher engine
efficiency.
9The benefits of biomass as a fuel feedstock could approach 100 percent if production
processes were redesigned to maximize C02 emission reductions (i.e. use renewable
fuels to provide process energy).
7-29
-------
When fueled with methanol derived from domestic natural gas,
methanol vehicles offer greenhouse gas reductions of 9 to 25 percent
relative to import-based gasoline vehicles. Unfortunately, due to the
favorable economics of foreign gas and limitations of domestic
conventional supply, it is likely that any significant increase in methanol
demand would be supplied by methanol produced from foreign natural
gas. If foreign natural gas were used in fuel methanol production, the
greenhouse gas reductions would be 8 to 24 percent over those of gasoline
vehicles (these benefits are not quite as great as those from domestic gas,
due to the increased product transportation required). The use of
methanol produced from biomass or solid waste, due to the renewable
nature of the feedstock, or from gas which is currently vented and flared,
would offer significant advantages relative to gasoline. Methanol vehicles
operating on coal-based methanol would produce nearly 60 percent more
than the greenhouse gases emissions of comparable gasoline vehicles,
although technologies to mitigate these potential greenhouse gas increases
exist, as will be discussed in Section C below. Additional details of the
analysis of greenhouse gas emissions from methanol vehicles is presented
in Appendix 7-A.
C Options for Mitigating Greenhouse Gas Increases Resulting from
Alternative Fuel Use
The Conference Report to S. 1518, the Alternative Motor Fuels Act of
1988, directs EPA to discuss carbon dioxide impacts of alternative fuel use
and propose ways to offset any increases in C02 emissions that may result
from their use.[16] As Table 7-8 shows, several of the alternative
vehicular fuel/feedstock combinations evaluated in this report could
potentially result in increased greenhouse gas emissions relative to
gasoline. This is particularly true of coal-based fuels, where per-mile
emissions of C02 approach twice those of a conventional gasoline vehicle,
due to coal's high carbon-to-energy ratio.
Many of the emissions from coal-based alternative fuels originate at
the fuel production facility, where much C02 is formed during the process
of increasing the hydrogen content of the syngas. Technologies exist for
removing and recovering CO2 formed during combustion in most fossil fuel
applications, but are typically cost and energy intensive due to the low CO2
concentrations found in most stack gases. However, in coal gasification
technologies that produce synthetic natural gas (SNG) or methanol, most
CO2 is emitted in highly concentrated streams. These streams are at high
pressures, which enables recovery without the need for compression.
7-30
-------
Hence, the economics of C02 recovery are more favorable and the
environmental benefits of recovery are more easily justified than for low
CO2 concentration stack gases.
Although traditional markets for CO2 probably could not absorb the
significant additional quantities recovered from the production of
alternative fuels from coal, the use of CO2 in enhanced oil recovery (EOR)
provides a promising market for the future. At average rates of CO2
consumption, the current C02 flooding projects in this country use 4 to 14
million tons of C02 annually, primarily produced from underground
reserves in Colorado and other Southwestern states. This volume of CO2 is
equivalent to 20 to 60 percent of the CO2 that would be released annually
from coal-based SNG or methanol production under alternative fuel market
Scenario 1 (and obviously a smaller fraction of the amount produced under
Scenarios 2 and 3). Since more floods are planned for the future, this
market could grow to absorb an even greater fraction of the C02 recovered
from the production of alternative fuels from coal under the scenarios
presented in this report.
Two alternative options to the sale of CO2 would be to dispose of it in
depleted oil and gas wells or deep in the ocean. The first of these options
has been investigated by Steinberg and Cheng in great detail, and appears
to be feasible.[17] Typical depleted wells have pressures of 100 to 500
psia; supercritical CO2 could be injected into wells at 2000 psia. About 12
billion tons of CO2 could be stored in depleted oil well, and 97 billion tons
of CO2 in depleted gas wells, assuming the entire historic volume of U.S. oil
and natural gas production were available.10[ 181 Combined oil and gas
well capacity would provide several hundred years of storage for CO
produced at coal-based alternative fuel plants under Scenario 3.
Steinberg and Cheng explored two systems for ocean disposal of
liquefied C02. The first system involved discharging C02 at 2000 psi at a
depth of 500 meters by piping the liquid C02 100 miles out to sea. The
natural thermocline circulation of the ocean would provide the dissolution
necessary. The second system involved discharging the C02 at depths of
3000 meters. At this depth, the CO2 would be more dense than the water
(it would be at a pressure of about 4400 psi) and would form a pool that
would sink to the floor of the ocean. To achieve these conditions, the CO2
10This estimate assumes that any groundwater or other fluid that has entered the
depleted wells could easily be removed; the feasibility of this operation would need to
be evaluated
7-31
-------
would need to be compressed to 4000 psi and piped about 200 miles out to
sea, a more costly process than the first disposal system.
Additional study into the feasibility of long term storage of C02 in
depleted oil or gas wells is desirable, since the global warming benefits of
this process would be minimal if the retention time were short. However,
it appears that retention of CO2 would be quite successful, at least in
depleted gas wells, since these wells held natural gas for thousands of
years at pressures greater than 2000 psi. If CO2 can be retained
indefinitely in the reservoirs, this method could prove to be attractive as
part of a strategy to mitigate the release of CO2 from the production of
coal-based alternative fuels. In this report disposal of recovered C02 in
depleted gas wells is explored as a likely option in the near term.
A summary of the control options, the estimated costs, and the
expected reductions in emissions of CO2 are presented in the remainder of
this section for vehicles operating on coal-based fuels. A more detailed
explanation of this information, including a discussion of CO2 markets, is
provided in Appendix 7-B.
1. Options for CO? Control
Options for recovering CO2 from a coal conversion facility vary
depending on the plant design, the location of the emissions, and the
concentration of CO2 in the stream. In a coal-to-methanol plant, the CO2
vented from the acid gas removal unit (about 80 percent of the total C02
emissions in a dedicated plant, as shown by Figure 7-2, or 50 percent of
total emissions in a methanol/electricity coproduction plant, as shown in
Figure 7-3) could be recovered quite easily, by merely eliminating the use
of nitrogen in the acid gas removal process.[17,19] The remaining 20-50
percent of the CO2 emissions are somewhat more difficult and expensive to
recover. The CO2 in the sulfur plant tail gas (6-8 percent of the total CO2
emissions from a coai-to-methanol plant, Figures 7-2 and 7-3) can be
removed if oxygen is used instead of air in the sulfur plant to improve the
concentration of C02 in the tail gas to a marketable level. The C02 in the
boiler stack gases (42 percent of total emissions from a coproduction plant,
but only 13 percent from a dedicated plant) may be recovered by
stripping, or, in the case of a coproduction facility, by modifying the
electricity generation section to improve the concentration of C02 and
make recovery easier by burning the fuel gas with oxygen, using steam or
recycled CO2 to cool the turbines.
7-32
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Figure 7-2
Dedicated Methanol Plant - Texaco Gasifier with ICI Methanol Synthesis
(based on design by EPRI, report AP-1962)
02
1
Coal Feed
14,448
ton/day
Gasification
&
Solids
Removal
COS
Hydrolysis
COS^ H2S
CO Shift
(CO+H2O
-••CO2+H2)
Stream
1
2
3
4
5
Total Carbon
(tons/day)
10,080
4,865
330
4,060
790
C02 (tpd)
—
17,820
1,210
0.53
2,880
Fraction of
Total C02
Released
—
0.81
0 06
<0 01
0 13
137,360 gal/hr
N2
Rectisol
Acid Gas
Removal
Acid
Gas
Claus Sulfur
Plant
SCOT
Tail Gas
Treatment
Gas Fired
Boiler/Steam
Generators
H20
~
Tail Gas
to
Atmosphere
t
Stack Gas
to
Atmospheie
-------
Figure 7-3
Methanol-Electricity Coproduction Plant
Texaco Gasifier with ICI Methanol Synthesis
(based on design by EPR1, icport AP-3749)
O2
1
Coal Feed
14,933
ton/day
Gasification
&
Solids
Removal
CO Shift
CO+H2C»
CO2+H2
Stream
1
2
3
4
5
Total Carbon
(tons/day)
9,425
4,025
685
1,010
3,380
C02 (tpd)
—
14,745
2,515
90
12,385
Fraction of
Total C02
Released
—
0 50
0 08
<0 01
0 42
Air ¦
Compressed
C02
Air-
Flash C02
Selexol
Acid Gas
Removal
And
Gas
Claus Sulfur
Plant
Cold Bed
Adsorption
Reactor
I ,
Incinerator |
~
Tail Gas
10
Atmosphere
Methanol
Synthesis
I
Air
Prehcaicr Coinbusior
Methanol
Product
33,836 gal/hr
725 MW
(Net)
Heat
Recoveiy
Steam
Generators
628 MW
(Nci)
Slack Gas
to
Atmosphere
-------
Since recovery from the boiler stacks could be costly, a better option
for maximizing C02 recovery might be to shift all the CO not needed for
methanol synthesis and remove all excess CO2 at the acid gas removal step.
This last option requires analysis that was outside the scope of this study;
future analyses should explore the costs of this modification.
2. Economics of CO? Control Options
The analysis performed for this study was based on estimated costs
of modifying a dedicated coal-to-methanol plant or a methanol/electricity
coproduction plant for C02 recovery. Since this analysis was preliminary
and not rigorous, the estimated costs should be viewed with some
uncertainty. In particular, there exists some questions regarding the
appropriate costs for a pipeline to dispose of the recovered C02- A more
complete analysis of all costs associated with the proposed plant
modifications must be made to determine the exact costs of CO2 recovery.
For a dedicated coal-to-methanol plant producing approximately 1
billion gallons per year, recovery of about 80 percent of the CO2 emitted
by the plant (from Stream 1 in Figure 7-2) would require a capital
investment of about $200 million and an acid gas removal process that
does not use nitrogen for solvent regeneration. Initial estimates indicate
that the cost of the recovered CO2 would be about $13 per ton of CO2
recovered.11 If allocated another way, the recovery costs could be passed
along to the methanol, the cost of which would rise less than $0.07 per
gallon due to these modifications. If the C02 recovered was sold for use in
enhanced oil recovery (EOR), however, the byproduct credit from the sale
could be as high as $0.10 per gallon of methanol produced, (assuming that
suitable EOR projects are located within 100 miles of the plant), more than
enough to cover the price increase due to the modifications.12 (This
byproduct credit will decrease as the distance between the plant and a
suitable EOR project increases beyond 100 miles, since some of the credit
will be used in transportation costs.)
11 A detailed discussion of the marketability of coal-based CO2 is presented in
Appendix 7-B.
12 In developing of preliminary plans to compress and recover the CO2 from the acid
gas removal unit stacks at the Great Plains Coal Gasification Plant and sell it to Shell
Canada for use in EOR projects, it was estimated that at an oil price of $20-$25/bbl this
process would be economical. However, the project was put on hold because the
incremental energy costs required for the relatively small volumes of CO2 initially
desired by Shell Canada were too great.[24]
7-35
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If essentially all of the C02 emitted by the plant were recovered (>98
percent), the total increase in capital cost would be approximately $260
million. Passing the recovery costs along to the CO2 would result in a cost
of about $14 per ton of CO2 recovered. If the costs were allocated to the
methanol instead of the C02, the net increase in the price of methanol
would be $0.09 per gallon.
For a methanol/electricity coproduction plant, it was estimated that
the capital cost of recovering 50 percent of the C02 emitted (the fraction of
emissions that would be most easily recovered) would be about $175
million at a cost of $13 per ton of C02 recovered. Recovery of C02 from a
methanol/electricity coproduction plant would require a greater capital
investment per gallon of methanol produced than a dedicated plant, due to
the fact that methanol is not the primary product of the plant, unless the
costs are divided between the two products on an energy equivalent basis.
If costs were allocated in this manner, methanol costs would increase
about $0.08 per gallon, and electricity costs would rise less than $0.01 per
kwh.
If essentially all (98 percent) of the C02 emitted by the plant were
recovered, the capital costs would increase approximately $600 million. It
would cost about $21 per ton of CO2 recovered. Electric rates would
increase about $0.01 per kwh if costs were allocated to the electricity.
The options to recover CO2 from a coal-to-"synthetic" natural gas
(SNG) plant are very similar to those for a coal-to-methanol plant, since
many components of the plant designs are identical. In a coal-to-SNG plant,
acid gas removal and sulfur recovery are used to remove sulfur
compounds and excess C02 before the gas goes on to methanation and
conversion to synthetic natural gas (SNG). (This is the point at which most
of the CO2 is released in the plant, so recovery of this CO2 could be
particularly cost effective.) The total capital cost to recover CO2 from a
plant producing 150 million cubic feet per day of gas is estimated to be
$325 million. This would cost $11 per ton of CO2 recovered. If the costs
were allocated to the gas, costs would rise about $2.40 per million BTU.
3. Global Warming Benefits
The use of CO2 recovery in conjunction with coproduction of
methanol and electricity from coal may be particularly attractive because
it could reduce the global warming contributions of both the power and
transportation sectors. If all of the construction of coal-fired utilities thai
7-36
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is planned (according to EIA) through the year 2010 were coproduction
plants, approximately 4.7 billion gallons methanol could be made annually.
This would be enough methanol to cover the demands for the year 2000
under either Scenario I or 2 (but not enough for the demands in 2010). If
CO2 recovery options were employed at the plants, the total projected C02
emissions from the power sector could be reduced by as much as 2 percent
and from the transportation sector by 2 percent, assuming adequate
markets or disposal sites for the C02 were available.[20] If, as EIA
estimates, demand exceeds capacity even with the planned additions, and
coproduction plants were constructed to fill this need, up to 38.4 billion
gallons of methanol could be produced each year (more than enough to
fulfill the methanol demand under any of the scenarios discussed in this
report). Using recovery technology, the CO2 emissions from the power
sector could be reduced by as much as 12 percent and from the
transportation sector by 15 percent.
Table 7-9 shows the potential reduction in C02-equivalent emissions
from coal-based alternative fuels due to recovery of the CO2 released
during production. Emissions from a dedicated plant would decrease 330
grams CO2 emitted per mile from the levels reported in Table 7-8 for a
dedicated vehicle (825 g/mi CO2 equivalent) if approximately 80 percent
of the emissions were recovered. As stated above, this would require a
capital investment of about $200 million and cost $9 per ton of C02
recovered. Recovery of essentially all of the emissions from a dedicated
methanol plant would result in a reduction of 395 grams CO2 emitted per
mile from these levels, at a capital investment of $260 million and a CO2
cost of $14 per ton. These emission levels are roughly 30 percent less than
those produced by a gasoline vehicle.
Table 7-9 also shows that recovery of the most concentrated and
easily recovered fraction of CO2 emissions (50 percent of total) of the
emissions from a methanol/electricity coproduction plant would reduce the
emissions by 445 grams CO2 emitted per mile for a dedicated vehicle
operating on methanol from this plant (assuming that all CO2 emission
reductions and recovery costs are allocated to methanol). Net emissions
for such a vehicle would be 310 grams per mile C02-equivalent. If the
plant were modified to shift more CO to CO2, even greater reductions could
be realized. For a coal-to-natural gas plant, recovery would reduce CO2-
equivalent emissions to 420 g per mile for a dedicated vehicle. Obviously,
if the recovery technologies discussed here were employed, CO2 emissions
from coal-based fuels could be brought down to levels comparable with or
less than gasoline vehicles.
7-37
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Table 7-9
CO2 Equivalent Emissions from Coal-based Dedicated Alternative Fueled
Vehicles Employing CO2 Recovery Options at the Conversion Facility
(Gasoline Vehicle = 590 g C02/mile)
Fuel
Process
Methanol Methanol Methanol CNG
Dedicated Dedicated Coproduction Gasification
CO2 Recovered
79 percent 98 percent 50 percent 98 percent
Emissions Without
Control (g C02/mi)
825
825
755
925
Emission Reductions
With Control
fg C02/nr>0
330
395
445
505
Net Emissions
(g C02/mi)
495
430
3 10
420
Control of other global warming gases, such as methane, from
alternative fuel production processes are also worth exploring. Future
analyses should include an assessment of the potential for mitigating the
release of CH4 from coal-based fuels, especially methane emissions
produced from coal mining. As alternative fuel programs are explored and
enacted, they will most likely include assurances that production of the
alternative fuels will not increase emissions of global warming gases.
Hence, research into C02 control options should continue to find the most
technically feasible and economically reasonable options available. The
options presented here should be explored in greater detail. In addition,
ideas such as shifting the stream entering the turbine combustor to
increase the concentration of CO2 and removing all the CO2 prior to
combustion or using recycled gas through the combustor to keep
temperatures down should be explored for their costs and feasibilities.
III. Other Environmental Impacts
In addition to the regulated pollutant, health effect, and global
warming impacts associated with alternative fuel use, there are a number
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of other environmental concerns. These include fuel spill and leak issues,
refueling and fire hazards, and operator safety. Several of the concerns
are specific to the individual fuels, and therefore are only discussed in that
section. Due to the complexity of many of these issues, a great deal of
research is necessary. EPA is engaged in research in many of these areas,
and is currently developing a comprehensive research strategy that will
address many of these issues.
A. Compressed Natural Gas
The most significant concerns associated with CNG vehicle use are in
the areas of refueling, vehicle operation and crashes, and risk of fire. As
long as normal, properly functioning equipment is being used, CNG
refueling should be generally less hazardous than refueling with
gasoline.[21] Incorporation of design features such as vents in the vehicle
body and ventilation of garages can mitigate the risks of fuel leakage
during regular vehicle operation. In vehicle collision scenarios, CNG would
appear to pose a level of risk somewhere between diesel fuel and gasoline.
Safety devices such as fuel release regulators and solenoid valves to shut
off fuel flow can be used to lessen the severity of any release of natural
gas from a CNG vehicle, and minimize the significance of collision risks. In
the event of a fuel release resulting in a fire, the resulting problems from a
CNG fire are likely to be easier to deal with than for conventional fuels.
However, although CNG vehicles appear to be relatively safe based on
preliminary tests, conclusions concerning CNG vehicle safety are
conditional on regulations assuring safe design and operation. A more
detailed discussion of several of these issues follows.
1. Refueling
The hazards posed in refueling with compressed natural gas are
different from those posed in refueling with conventional liquid fuels. As
long as normal, properly functioning equipment is being used, CNG
refueling should be generally less hazardous than refueling with gasoline
or diesel fuel since there will be no toxic or flammable vapors escaping
from CNG refueling equipment, as there often is with conventional
refueling equipment. In the event of equipment failure, CNG systems
would offer a significant advantage compared to gasoline or diesel systems
in the area of environmental exposure. While gasoline and diesel fuel
storage tank or dispensing equipment leaks could lead to contamination of
the surrounding environment with toxics, CNG leaks would introduce no
such toxic materials into the environment. On the other hand, CNG
equipment failure could pose a greater risk of physical injury to the
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operator compared to gasoline and diesel fuel systems. These injuries
could take the form of cryogenic burns from gas cooled by rapid expansion
or injuries resulting from being struck by a flailing hose.[21] Both of these
risks can be minimized by designing the equipment to both resist
catastrophic failures and so that if such a failure were to occur, it would
occur at a point which is already anchored, contains a valve to shut off the
flow of fuel, and/or is in an area where people are not likely to be exposed
to the leak.
In cases where the refueling is being done indoors, flammable
concentrations of fuel vapors of any type can build-up. For CNG systems,
very little vapor should be released during normal operation. However, in
the event of fuel leakage from malfunctioning equipment, large quantities
of vapor could rapidly escape. The risks of vapor build-up, however, can
be minimized by enclosing the fuel line in a ventilation line. Since fuel
leakage cannot be completely prevented, however, the best strategy for
minimizing risks is building design. Proper ventilation and placement of
equipment which could serve as ignition sources should greatly reduce the
risks of fire or explosion posed by any fuel source.
2. Vehicle Operation and Crashes
During normal operation of existing fleets of CNG vehicles, it appears
that small leaks have been observed with greater frequency than in
conventionally fueled vehicles.[22] It would be reasonable to conclude
that the highly-pressurized nature of the CNG fuel system could make it
more prone to small leaks and to more fuel being released from a given
leak. Small leaks pose concerns about vapors accumulating to flammable
concentrations either in vehicle compartments or vehicle storage
enclosures. Incorporation of design features such as vents in the vehicle
body and ventilation of garages can mitigate the risks of fuel leakage.
Currently, there is insufficient data to determine to what extent small fuel
leaks actually pose any hazards.
In vehicle collision scenarios, CNG would appear to pose a level of
risk somewhere between diesel fuel and gasoline. To analyze collision
hazards it is necessary to evaluate the risks of, and the likely extent of,
fuel leaks. It is also necessary to examine the ease with which such
problems can be dealt with in the event of combustion of leaked or leaking
fuel.
In the absence of extensive data on the use of CNG vehicles, it is
difficult to make an accurate assessment of the relative risks of fuel
7-40
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release. However, some assessments can be made as to estimates of
relative risks. • Because of the structural integrity needed by the fuel
storage cylinders to hold compressed natural gas, these cylinders are much
more likely than gasoline or diesel fuel tanks to survive collisions without
release of fuel from the storage tank. On the other hand, fuel lines, valves
and fittings would be more prone to severe leaks than gasoline or diesel
systems because of the pressurized nature of the fuel. However, safety
devices such as fuel release regulators and solenoid valves to shut off fuel
flow when the engine stops can be built onto the fuel cylinder to lessen the
severity of any release of natural gas from a CNG vehicle, and minimize the
significance of this risk.
3. Risk of Fire
In the event of a fuel release resulting in a fire, the resulting
problems from a CNG fire are likely to be easier to deal with. First of all,
fires from liquid fuels are difficult to extinguish and difficult to control if
they are not extinguished. On the other hand, natural gas torch fires
(which are the only kind likely to be sustained) can be extinguished by
shutting off the fuel source, which is not generally possible in liquid fuel
fires. Some currently in-use CNG vehicles have a readily accessible quarter
turn shut-off valve for this purpose. Should it be difficult to shut off the
flow of CNG, it should still be possible to control the damage from the fire
because of its localized nature. Severe explosions are unlikely in any case
since CNG cylinders are designed to handle conditions likely to lead to
explosions and will eventually vent off gas which will burn in a relatively
controlled manner rather than rupturing to produce an explosive release.
4. Maintenance
The issue of maintenance might also pose some concerns. On CNG
equipped vehicles, it is possible that a maintenance worker could release a
large amount of fuel by inadvertently creating a vent in the fuel system.
In such a case, the worker could also face the risk of cryogenic burn as
described earlier. If the fuel release occurred outdoors, no other hazards
should be posed unless there was an ignition source immediately present,
due to the rapid dispersion of the gas. On the other hand, if the
maintenance were being performed indoors, there is a potential for the
rapid formation of a flammable or explosive cloud.
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B. Electricity
1. Battery Disposal
One potential environmental impact associated with electric vehicle
use is the disposal of the batteries used. If based on traditional battery
technology, EV batteries would contain acids considered to be hazardous
waste, thus being difficult to dispose of safely. As a solid waste, these
batteries could take up a large amount of valuable landfill space, and
possibly make landfill management more difficult. Additional measures
may be necessary io control acid seepage into ground water reservoirs. It
may, however, be possible to recycle EV batteries, reducing or even
eliminating these disposal problems.
2. Health and Safety
There are expected to be no significant health or safety risks
associated with the widespread use of electric vehicles. The flammability
and inhalation concerns associated with the other fuels do not apply for
EVs. The current literature makes no mention of any other increased risks
or concerns to vehicle operators or maintenance workers. Additional
emission analyses to evaluate the health concerns of increased electricity
production will be done for subsequent versions of this report.
3. Increased Electricity Generation
An increase in electric vehicle use would lead to an increase in
electricity generation requirements. This would result in an increase in
any environmental concerns associated with electricity generation. Of
course, the extent of such concerns would depend largely on the specific
energy feedstock used to produce the electric power.
C. Ethanol
1. Spill Issues
If ethanol were involved in a spill into the ocean, into a lake or river,
onto land, or into drinking water supplies, the question arises of whether a
greater environmental and public health hazard would be posed relative to
a petroleum fuel spill. The risk relative to other clean fuels, particularly
methanol, is also of interest. An ethanol fuel spill into aquatic systems or
on land poses environmental and health concerns because of the fuel's
toxic effects in high concentrations. It could be expected that there would
7-42
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be a slightly larger number of spills (about 20% "per vehicle") of ethanol
for a given mode of transport than experienced for petroleum fuels,
because of the larger quantities of ethanol fuel that would have to be
transported. The modes of shipment would certainly include barge, rail
tank car, and tank truck. Transport by multi-product pipeline, dedicated
pipeline, and ocean-going tanker are also possible, depending on the scale
and location of use and the source of supply. As with transport of gasoline
via these modes, accidental releases are inevitable over a long enough
period of use. Barge and tanker shipment pose a risk of a spill into the
open ocean, coastal waters, rivers, or the Great Lakes. The other modes
would more typically result in spills onto land first, with possible run-off
into surface waters.
Small ethanol spills usually do not require any cleanup efforts
because of the effectiveness of natural biodegradation, while large ethanol
spills may require aeration of the water (to supply depleted oxygen to
marine life and speed biodegradation) and/or use of ethanol-destroying
bacteria. It is unknown whether catastrophic alcohol fuel spills or leaks
would result in greater adverse ecological effects that those for
conventional fuels. In comparison to petroleum fuels, a tanker spill of
ethanol into the ocean should pose less risk to aquatic life. Ethanol's water
solubility allows for rapid dispersion and dilution and, therefore, short
exposure durations. Also, ethanol's quicker biodegradation than that of
crude oil, diesel fuel, or gasoline results in shorter residence times of the
fuel and faster recolonization of life at spill sites, with less severe long-
term effects of spills on animal life and on the environment. In general,
cleanup of ethanol spills requires less extensive efforts and costs than
cleanups associated with spills of water-insoluble petroleum fuels. Thus,
in many scenarios, an ethanol spill should not be as hazardous as a
petroleum spill.
However, in some scenarios, including spills in restrictive waterways
(rivers and lakes), serious acutely toxic environmental effects could result
from alcohol spills. In contrast, gasoline spills would expectedly result in
generally chronic effects. (While gasoline would vaporize more rapidly
than ethanol, those components of the fuel that will partially dissolve
would exhibit some acute effects, like the alcohols, although probably to a
far lesser geographical extent, since they will float and be only slightly
miscible with water. Problems of potential bioaccumulation, however,
would likely be greater with gasoline than with ethanol.) On the other
hand, ethanol spills into rivers and other moving bodies of water benefit
from the fuel's water solubility and biodegradation. Again, in contrast to
petroleum fuels, ethanol spilled into a river from, for example, a barge, is
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quickly diluted and carried downstream. Cleanup of an ethanol fuel spill
into a moving body of water would be handled similarly to that of a spill
into the ocean.
Although, like petroleum fuels, ethanol in high concentrations is toxic
to plant and animal life, its toxic effects after a spill onto land are of
shorter duration and are less acute than those exhibited by a petroleum
fuel spill. Again, ethanol's inherent properties of relative ease of complete
evaporation and biodegradability play a positive role. Its more rapid
evaporation from the earth allows for less to be absorbed into the soil and
water table. (It is important to note that while some of the lighter ends of
gasoline evaporate very quickly, its heavy components require long
periods of time before evaporation occurs.) However, if absorbed,
ethanol's larger degree of biodegradability facilitates decomposition by
micro-organisms present in the soil. Because of its shorter retention
periods near a spill site, cleanup of an ethanol spill on the earth requires
less effort than that of a petroleum fuel spill. In the event of a massive
spill, however, enhancement of the natural biodegradation process of
ethanol may be beneficial.
Since ethanol's solubility in water and, hence, rapid dilution and
dispersion are considered advantages in spills into large and/or quickly
moving water masses, most scenarios where drinking water is at risk
would be less severe with ethanol than with petroleum. In some
situations, however, such as a river spill located very near a drinking
water supply intake, ethanol may indeed contaminate a water supply that
would have escaped contamination by petroleum fuel. However, ethanol
has a taste and odor that most adults can recognize and avoid. With the
possible exception of fetuses and pregnant women, consumption of
drinking water with low levels of ethanol should not be acutely toxic..
2. Leak Issues
The previous section addressed the potential consequences of sudden
releases of significant quantities of ethanol fuel. Slower leaks and
continuous releases of small quantities are also of interest. Because of the
biodegradability of ethanol, smaller routine releases in circumstances that
allow for good dilution should not present an environmental problem. For
example, transfer losses between ship and shore or flushing of cargo tanks
would at most encourage a higher local concentration of ethanol-digesting
bacteria.
7-44
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Leaks into underground water are a potentially greater concern with
all fuels because of the more restricted dilution conditions that can exist.
Also, while bacteria are present in soil and underground water supplies,
they are sparser than in the ocean and surface waters. Ethanol fuel would
be most often stored in underground tanks, creating the opportunity for
both relatively sudden loss of contents and/or undetected leakage over a
period of time. However, industry practices in underground fuel storage
are changing drastically in response to recent legislation. Double wall
tanks, leak monitors, and periodic leak testing will become standard
practice for gasoline tanks. These techniques can be extended by
regulation to other fuels as judged necessary.
If a leak does occur, there will be several differences between the
consequences with ethanol compared to that with petroleum fuels. Ethanol
and petroleum fuels exhibit different hydrological behavior in soils and
may migrate downward at different rates, providing more or less time for
evaporation instead. Once in contact with the water table, ethanol will
tend to mix and dilute more quickly than a petroleum fuel and to
biodegrade more quickly. (There may be a zone in which the ethanol
concentration is too high for biodegradation to occur.) If ethanol reaches a
drinking water well, there is little health risk. Ethanol is not toxic and is
detectable by both odor and taste.
3. Other Environmental Concerns
The massive production of ethanol from corn that could be
experienced under a large alternative fuels program poses other potential
environmental problems in addition to the risk of spills or leaks. Some of
these potential problems include soil erosion and surface water quality
degradation due to pesticides, fertilizers, and situation of habitat. These
potential effects need further research before their impact car. be
quantified.
D. Liquefied Petroleum Gas
LPG must be stored under moderately high pressure (up to 200 psi)
in order for it to remain in the liquid phase. Immediately upon being
released from the pressurized tank, LPG evaporates.[23] Therefore, for the
purposes of this discussion, LPG is treated as a gaseous fuel. The risks
related to the release of LPG would likely be similar to those discussed for
CNG. In the event of serious leakage, propane, being heavier than air, will
tend to accumulate near the source of the leak, making the ignition risk
7-45
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somewhat higher than that discussed for CNG. This risk is lower than for
gasoline, however, because of the hotter ignition source required to ignite
propane. Any release outdoors will dissipate quickly, unless an ignition
source is immediately present, in which case the LPG could explode.
Control measures to avoid this risk, both indoors and out, are discussed in
detail in the CNG section. LPG should pose no risk to ground water because
it becomes gaseous once it is released. Because of the potential for rapid
loss of valuable fuel, it is assumed that tank designs will seek to avoid such
leaks.
Refueling LPG vehicles requires the use of complementary fittings for
the dispensing nozzle and the vehicle. This involves securing the
dispensing nozzle to the refueling fitting of the vehicle. As with CNG, this
is a closed system and refueling losses in the form of vapors are expected
to be considerably less than those for conventional fuels. The health risk
related to inhalation will be reduced with LPG as well. The refueling risks
associated with LPG are assumed to be similar to those discussed for CNG.
As with CNG, LPG crash risk is reduced due to the strength of the tanks
used on LPG vehicles. Research indicates that LPG tanks are at least 4
times stronger than gasoline fuel tanks, and has documented accidents
where the entire vehicle was destroyed, but the LPG fuel tanks were
not.[24]
E. Methanol
Most of the above discussion for ethanol applies equally to methanol.
The environmental impacts of methanol use are considered to be similar to
those discussed for ethanol. Most of these issues are only briefly discussed
again here.
In many scenarios, a methanol spill should not be as hazardous as a
petroleum spill. In comparison to petroleum fuels, a tanker spill of
methanol into the ocean should pose less risk to aquatic life. Cleanup ot
methanol spills requires less extensive efforts and costs than cleanups
associated with spills of water-insoluble petroleum fuels. As discussed for
ethanol, methanol's toxic effects after a spill onto land are of shorter
duration than those exhibited by a petroleum fuel spill. Methanol would
evaporate from an on-land spill faster than ethanol. The relative toxicity
of methanol and ethanol to fish and other organisms at a given dilution is
largely untested. Methanol and ethanol would behave very similarly to
each other in an underground spill, particularly in comparison to their
sharp differences from petroleum fuels. Methanol, however, is toxic at
concentrations that are of no concern for ethanol and is not detectable by
7-46
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taste or odor. Dyes or odorants may be needed for methanol that can be
omitted with e'thanol.
IV. Environmental Impacts of Alternative Fuel Use Scenarios
Based on the alternative fuel consumption and gasoline displacement
estimates presented in Appendix 3 for each of the three scenarios, and the
emission information presented above, the total emission impacts of each
of the alternative fuel penetration scenarios in a given future calendar
year can be estimated. Total emission impacts for each scenario and each
fuel/feedstock combination are presented in Tables 7-10 through 7-17 for
calendar years 2000 and 2010. A discussion of the key findings for each
alternative fuel scenario are presented below.
A. Scenario 1: Maximum Utilization of AMFA Fuel Economy Credits
Tables 7-10 and 7-11 present the overall emission impacts of
Scenario 1, the "maximum AMFA credit" scenario. This scenario allows
CAFE credits for alternative fuel use. Despite the probability of decreased
gasoline vehicle fuel economy, substantial reductions in pollutants would
be realized for many of the fuel/feedstock combinations.
Net carbon dioxide emissions (other greenhouse gases are included as
carbon dioxide equivalents) could change positively or negatively
depending upon the feedstock used. Because of decreasing gasoline vehicle
fuel economy (resulting from the assumed use of CAFE credits), the
greenhouse gas emissions from the entire fleet would increase for most
alternative fuels/feedstocks except for fuels derived from renewable or
"wasted" resources such as vented/flared natural gas. Vented and flared
natural gas use would reduce greenhouse gas emissions by 87 million tons
in 2000 and up to 260 million tons in 2010 because of the reduction of
methane emissions. Coal use, either for natural gas production or methanol
production, could result in increased greenhouse gas emissions up to 70
million tons per year absent technology to control C02 emissions. Most
other feedstocks result in smaller changes, on the order of 10 million tons
per year in 2000.
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Tabic 7-10
EMISSION REDUCTION
AMFA FUEL CREDITS CAFE=27 5
YR 2000 (1000 Tons/Yr)
CMG*
Foreign
V cntcd/
Alaskan
Domestic
Municipal
Natural
Flared
Natural
Natural
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Emission Reduction
VOC
32 5
32.5
32.5
40 0
40 0
40 0
40 0
NO*
(9.27)
(9 27)
(9.27)
0.922
0.922
0.922
0 922
CD
(0.375)
(0.375)
(0.375)
1.54
1.54
1.54
1 54
S02
1.29
3 84
3.84
3.84
3 84
3.84
3 84
Air Toxics
(0.242)
(0.242)
(0.242)
0.077
0 077
0 077
0 077
Particulate
(6.29)
(6 29)
(6 29)
0.077
0 077
0 077
0.077
CO2 (Equivalent)
(48,300)-
1,400-
1,500-
(7.300)-
13,900-
(7,300)-
(6,600)-
(50,300)
3,600
4,800
(10,500)
97,000
(10,500)
(9,800)
ETHANOL
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal Natural
Flared
Natural
Feedstock
Corn
(Dedicated) (Coproduccd)
Biomass
Waste
Gas
Gas
Gas
Emission Reduction (ton/yr.)
VOC
46.8
48.8
48 8
48.8
48.8
53 2
53 2
53 2
NOx
(20.7)
(6.47)
(6 47)
(6.47)
(6 47)
0.47
0.47
0.47
CD
(1.49)
0.519
0.519
0.519
0.519
0.783
0.783
0 783
SO2
(104)
0.223
0.223
1.96
1.96
1.96
1.96
1 96
Air Toxics
(0.180)
(0.178)
1 (0.178)
(0.178)
(0.178)
0.039
0.039
0.039
Particulate
(2.08)
(4 30)
(4.30)
(4.30)
(4.30)
0 039
0.039
0 039
CO2 (Equivalent)
(27,100)-**
(35,600)- (30,700)-
300-
2,100-
(6,800)-
18,300-
(12,780)-
(27,700)
(38,600) (34,900)
900
4,300
(9,900)
87,600
(17,900)
1 Insufficient supply lo meet ihe demand.
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter than that of a conventional gasoline vehicle. Increasing the range would increase emissions signilicamly
** If biomass is used as an cthanol feedstock, C02 increases would decrease lo (900)-(4.100)
-------
Tabic 7-11
EMISSION REDUCTION
AMFA FUEL CREDITS CAFE=27 5
YR 2010 (1000 Tons/Yr)
CNG»
Foreign
Vented/
Alaskan
Domestic
Municipal
Natural
Flared
Natural
Natural
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Emission Reduction
VOC
95.8
95.8
95 8
1 1 1
1 1 1
1 1 1
1 1 1
NOx
(21.0)
(21.0)
(21.0)
2.27
2 27
2.27
2 27
CD
(0.663)
(0.663)
(0.663)
3.79
3.79
3.79
3.79
S02
3.54
9.47
9.47
9.47
9.47
9.47
9 47
Air Toxics
(0 552)
(0.552)
(0 552)
0.189
0 189
0 189
0 189
Particulate
(14.6)
(14.6)
(14.6)
0.189
0 189
0.189
0.189
CO2 (Equivalent)
(110,600)-
8,400-
8,600-
(17.600)-
33,700-
(17,600)-
(15,600)-
(11 1,900)
10,400
13,100
(27,600)
231,000
(27,600)
(25,100)
ETHANOL METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
(Dedicated)
(Coproduced)
Biomass
Waste
Gas
Gas
Gas 1
Emission Reduction (ton/yr.)
VOC
122
1 24
124
1 24
1 24
137
1 37
NOx
(53.8)
(16.7)
(16.7)
(16.7)
(16.7)
3.15
3 15
CD
(0.638)
1.53
1.53
1.53
1.53
5.26
5 26
SO2
(272)
8.24
8.24
13.1
13.1
13.1
13.1
Air Toxics
(0.316)
0.358
0.358
0.358
0.358
0.262
0.262
Particulate
(5.44)
(12.1)
(12.1)
(12.1)
(12.1)
0.262
0 262
CO2 (Equivalent)
(57,600)-**
(93,200)-
(79,200)-
9,200-
20,600-
(17,500)-
31,400-
(60,500)
(96,000)
(85,100)
12,300
21,200
(26,400)
260,000
1 Insufficient supply to meet ihc demand.
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter than that of a conventional gasoline vehicle. Increasing the range would increase emissions significantly
** If biomass is used as an cthanol feedstock, C02 reductions of 5,900-9,800 could be achieved.
-------
As can be seen from the tables, the displacement of gasoline by CNG
vehicles operating on fuel derived from natural gas reserves is expected to
result in reductions of most of the regulated pollutants, particularly
emissions of sulfur oxides and VOC. Annual VOC reductions would be
expected to reach 40,000 tons per year by 2010. If vehicles were
operated on natural gas derived from biomass or coal, net emissions of
regulated pollutants other than VOC and SOx would be expected to increase
due to increases from stationary sources. iMany of these stationary source
emissions would be expected to occur in rural areas (though not shown in
this analysis) and would thus not be as significant as urban decreases
resulting from cleaner fueled vehicle use.
Use of alcohol fuels under this scenario would also result in
significant reductions in VOC emissions. The VOC reductions would
increase from 45,000-53,000 in the year 2000 to 123,000-137,000 tons
per year in the year 2010. Ethanol production results in large reductions
of VOC emissions, but increases in SOx, NOx, and particulate emissions
would be expected. Methanol use would result in slightly higher
reductions of VOC emissions and increases in NOx and SOx emissions only
when coal is used as a feedstock.
B. Scenario 2: Nine Citv Program Equivalent
The nine city program would result in much greater reductions in
VOC emissions than Scenario 1. The expected emission reductions for the
nine city program assuming a fixed CAFE of 27.5 mile/gallon, Scenario 2a,
are given in Tables 7-12 and 7-13, and with an increasing CAFE, Scenario
2b, in Tables 7-14 and 7-15. The nine city program targets alternative
fuel use in the nine worst ozone nonattainment areas in the United States.
The emissions reductions given in the tables are overall emission
reductions though some if not all the fuel producing facilities would be
located outside of the nonattainment areas. However the VOC emissions
reductions, unlike the other pollutants listed (except for NOx emission
reductions from electric vehicles), are dominated by reduced vehicular
emissions which would occur primarily in urban areas.
Greenhouse gas emissions show trends similar to those in Scenario 1
In general, C02 emission reductions in Scenario 2a are lower than in 2b,
due to the CAFE slippage resulting from AMFA credit use in Scenario 2a
which would result in increased fuel consumption by the gasoline portion
of the fleet. The most significant C02 emission reductions would be
realized with natural gas use, either for CNG or methanol production. The
reason for minor reductions in greenhouse gas emissions
7-50
-------
Table 7-12
EMISSION REDUCTION
NINE CITY PROGRAM - CAFE = 27 5
YR 2000 (1000 Tons/Yr)
CNG*
ELECTRICITY*
Foreign
Vented/ Alaskan
1 Domestic
Municipal
Natural
Natural Flared
Natural
Municipal
Feedstock
Coal
Biomass
Waste
Gas
Gas Gas
Gas
Current
Waste
Solar
Emission Reduction
voc
27.8
27.8
27 8
35.6
35.6 35 6
35.6
78.4
78.4
78 5
NO*
(10.4)
(10.4)
(10.4)
2.41
2.41 2.41
2.41
24.3
24 3
57 9
CD
1.65
1.65
1.65
4 02
4 02 4 02
4 02
5.65
5 65
6 94
SO2
6.89
10.1
10 1
10 1
10 1 10 1
10 1
9 62
17.4
1 7 4
Air Toxics
(0.194)
(0 194)
(0 194)
0.201
0.201 0 201
0.201
0.347
0 347
0 347
Particulate
(7.71)
(7.71)
(7.71)
0.201
0.201 0.201
0.201
(6.11)
(6 1 1)
0.347
CO2 (Equivalent)
(48,700)-
14,000-
14,100-
(3.500)-
28,200- (3.500)-
¦ (300)-
1 1,500-
13,400-
40,100
(50,100)
15,750
17,400
(6,400)
132,800 (6,400)
(3.150)
21,800
34,200
53,900
ETHANOL
LPG
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG
(Dedicated)
(Coproduced) Biomass
Waste
Gas
Gas
Gas
Emission Reduction (ton/yr.)
VOC
35.2
37.1
30.9
30.9
30.9
30.9
35.8
35 8
35 8
NOx
(23.7)
2.71
(7.00)
(7.00)
(7.00)
(7.00)
0.880
0.8B0
0 880
CD
(0.720)
4.52
(0.008)
(0 008)
(0.008)
(0 008)
1.47
1.47
1 47
S02
(120)
11.3
1.70
1.70
3.67
3.67
3.67
3.67
3 67
Air Toxics
(0.160)
0.275
(0.170)
(0.170)
(0.170)
(0.170)
0.073
0.073
0.073
Paniculate
(2.4)
0.275
(4.85)
(4.85)
(4.85)
(4.85)
0 073
0 073
0 073
CO2 (Equivalent)
(20,500)-
*~ 6.70O-
(28,700)-
(23,200)
10,400-
13,700-
(2,700)-
18,000-
l
O
O
r-
(21,600)
16,400
(32,400)
(28,100)
12,000
16,600
(8,900)
1 1 1,000
(8,900)
1 Insufficient supply to meet the demand
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter that) thai of a conventional gasoline vehicle Increasing the range would increase emissions significantly
** If biomass is used as an cthanol feedstock, CO2 reductions of 7,500-11,700 could be achieved.
-------
Tabic 7-13
EMISSION REDUCTION
NINE CITY PROGRAM - CAFE = 27 5
YR 2010 (1000 Tons/Yr)
CNG* ELECTRICITY*
Foreign
Vented/
Alaskan
Domestic
Municipal
Natural
Flared
Natural
Natural
Municipal
Feedstock
Coal
Biomass
Waste
Gas
Gas
Gas
Gas
Current
Waste
Solar
Emission Reduction (ton/yr.)
VOC
99
99
99
1 14
1 14
1 14
1 14
173
173
173
NO*
(21.9)
(21 9)
(21.9)
2.81
2.81
2.81
2 81
32.2
32.2
105.4
CD
0.061
0.061
0 061
4 69
4.69
4 69
4.69
12 1
12.1
14 9
S02
5.55
11.7
1 1.7
11.7
11.7
11 7
1 1.7
20 5
37 4
37 4
Air Toxics
0 537
0.537
0 537
0 235
0 235
0 235
0 235
0 750
0 750
0 750
Particulate
(15.2)
(15.2)
(15.2)
0.235
0 235
0 235
0 235
(13.3)
(13 3)
0 750
CO 2 (Equivalent)
(113,000)-
2,400-
2,600-
(20,300)-
37,000-
(20,300)-
(24,100)-
23,200
35,100-
85,400-
(116,600)
12,800
15,800
(29,800)
234,000
(29,800)
(25,500)
41,700
72,600
1 1 1,500
ETHANOL
LPG
METHANOL
Foreign
Vc mod/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG 1
(Dedicated)
(Coproduced)
Biomass
Waste
Gas
Gas
Gas 1
Emission Reduction (ton/yr.)
VOC
138
1 26
1 25
125
1 25
125
137
1 37
NOx
(53.800)
5.90
(16.9)
(16.9)
(16.9)
(16.9)
1.78
1 78
CD
(0.638)
9 84
(0.531)
(0.531)
(0.531)
(0.531)
2.96
2.96
S02
(272)
24.6
2.74
2.74
7.40
7.40
7.40
7.40
Air Toxics
(0.316)
0.491
(0.434)
(0.434)
(0.434)
(0.434)
0 148
0.148
Particulate
(5.44)
0 491
(11.5)
(11.5)
(11.5)
(11.5)
0 148
0.148
C02 (Equivalent)
(51,700)-**
13,800-
(80,100)-
(70,000)-
16,200-
25,700-
(18,400)-
35,800-
(53,700)
31,000
(83,600)
(73,500)
17,800
27,200
(27,800)
250,900
1 Insufficient supply to meet the demand
Parenthesis indicate negative reduction (increases)
* Assuming a vehicle range shorter than that of a conventional gasoline vehicle Increasing the i.i - would increase emissions significantly
** If biomass is used as an ethanol feedstock, C02 reductions of 13,700-18,900 could be achieved
-------
Table 7-14
EMISSION REDUCTION
NINE CITY PROGRAM - INCREASING CAFE
YR 2000 (1000 Tons/Yr)
CNG*
ELECTRICITY*
Foreign
Vented/ Alaskan
i Domestic
Municipal
Natural
Flared Natural
Natural
Municipal
Feedstock
Coal
Biomass
Waste
Gas
Gas Gas
Gas
Current
Waste
Solar
Emission Reduction (ton/yr.)
VOC
44.2
44 2
44 2
52.7
52.7 52 7
52.7
93 7
93.7
93.7
NO*
(9.04)
(9.04)
(9 04)
4.58
4.58 4.58
4.58
27.6
27.6
69.9
CD
5.08
5.08
5.08
7.63
7.63 7.63
7.63
5.50
5.50
7.09
S02
15.7
19.1
19.1
19.1
19.1 19 1
19 1
7.97
17.7
17 7
Air Toxics
(0 04)
(0 04)
(0 04)
0.381
0.381 0.381
0.38 1
0 354
0 354
0 354
Particulate
(8.12)
(8.12)
(8.12)
0.381
0.381 0 381
0.381
(7.77)
(7.70)
0.354
CO2 (Equivalent)
(25,600)-
35,900-
37.500-
8,100-
49,700- 8,100-
16.000-
S^OO-
25.000-
44,300
(33,000)
38,500
38,600
19,300
171,100 19,300
28,000
lS,800
37,000
58,600
ETHANOL
LPG
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG
(Dedicated)
(Coproduced) Biomass
Waste
Gas
Gas
Gas
Emission Reduction (ton/yi.)
VOC
48.8
76.2
49.9
49 9
49.9
49.9
55 2
55 2
55 2
NO*
(24.5)
3.03
(4.86)
(4.86)
(4.86)
(4 86)
3.63
3.63
3.63
CD
3.56
5.05
4.46
4.46
4.46
4.46
6.06
6 06
6.06
SO2
(124)
12.6
13.0
13.0
15.1
15.1
15.1
15 1
15.1
Air Toxics
(0.038)
0.253
0.038
0.038
0.038
0.038
0.303
0.303
0.303
Particulate
(2.49)
0.253
(5.00)
(5.00)
(5.00)
(5.00)
0.303
0.303
0.303
CO2 (Equivalent)
(3,300)-**
7,800-
(13,300)-
(7,400)-
26,600-
30.200-
5,800-
34,800-
5,800-
(6,700)
17,600
(19,600)
(15,000)
30,500
33,800
13,000
135,800
13,000
1 Insufficient supply to meel the demand
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter than that of a conventional gasoline vehicle. Increasing the range would increase emissions significantly.
** If biomass is used as an ethanol feedstock, C02 reductions of 24,600-31,500 could be achieved.
-------
Table 7-15
EMISSION REDUCTION
NINE CITY PROGRAM - INCREASING CAFE
YR 2010 (1000 Tons/Yr)
CNG*
ELECTRICITY*
Foreign
Vented/ Alaskan
Domestic
Municipal
Natural
Flared Natural
Natural
Municipal
Feedstock
Coal
Biomass
Waste
Gas
Gas Gas
Gas
Current
Waste
Solar
Emission Reduction
(ton/yr.)
VOC
1 4 1
141
1 4 1
157
157 157
157
20 1
201
20 1
NOx
(15.2)
(15.2)
(15.2)
9.56
9.56 9.56
9.56
35.7
35.7
125
CD
1 1.3
11.3
11.3
15.9
15 9 15 9
15.9
12.5
12.5
15 9
SO2
33.6
39.8
39.8
39 8
39 8 39 8
39 8
19.3
39 8
39.8
Air Toxics
0.02
0 02
0 02
0 796
0.796 0 796
0 796
0.796
0 796
0 796
Particulate
(14.7)
(14.7)
(14.7)
0.796
0.796 0 796
0.796
(16 3)
(16 3)
0.796
CO2 (Equivalent)
(51,900)-
71,200-
71,500-
22.900-
98,800- 22,900-
37,400-
15,700-
61,500-
91,600-
(53,300)
74,400
77,300
28,400
305,000 28,400
44,300
32,100
76,000
1 17,400
ETHANOL
LPG
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG
(Dedicated)
(Coproduced) Biomass
Waste
Gas
Gas
Gas 1
Emission Reduction
(lon/yr.)
VOC
1 55
1 14
146
146
146
146
158
158
NOx
(50.3)
6.32
(9.62)
(9.62)
(9.62)
(9.62)
9.26
9.26
GD
9.58
10.5
1 1.9
11.9
11.9
11.9
15.4
15.4
SO2
(259)
26.3
33.9
33.9
38.6
38.6
38.6
38 6
Air Toxics
0.181
0.527
0.182
0.182
0.182
0.182
0.772
0.772
Particulate
(5.19)
0.527
(11.0)
(11-0)
(11.0)
(11.0)
0 772
0 772
C02 (Equivalent)
(400)-**
15,300-
(24,200)-
(10,900)
68,700-
76,700-
22.500-
87,000-
(4.500)
31,500
(34,100)
(23.900)
73,200
80,300
34,000
307,000
1 Insufficient supply to meet the demand
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter than thai of a conventional gasoline vehicle Increasing the range would increase emissions significantly
** If biomass is used as an ethanol feedstock, CQ2 reductions of 62.100-73,400 could be achieved
-------
from biomass use, for CNG, ethanol, or methanol, is the energy used in
production and -conversion to a usable fuel.
With a fixed CAFE, use of CNG as a fuel would be expected to result in
yearly VOC emissions of approximately 30,000 tons/yr in the year 2000
increasing to 110,000 tons by the year 2010. With coal as a feedstock NOx
and particulate emissions would increase, but SOx emissions would actually
decrease due to reduced refinery emissions. Emission reductions are
greater when natural gas is used as a feedstock than coal or biomass due to
lower processing emissions.
The use of electric vehicles would produce the greatest reduction in
VOC emissions of any fuel type. At a fixed CAFE, the VOC emissions
reductions increase from 78,000 in the year 2000 to 173,000 tons/year in
the year 2010. Mobile NOx emission reductions would be partially offset
by increased stationary source emissions. With the current energy mix to
produce electricity, particulates would increase slightly, and SOx would
probably decrease provided utility emissions were adequately controlled.
With an increasing CAFE, greater VOC emissions reductions would be
realized earlier, 94,000 tons/year by the year 2000 compared with 78,000
for a fixed CAFE.
Ethanol use would result in large emissions reductions though not as
great as with electric vehicles. While VOC emission reductions would be
substantial, up to 140,000 tons/year by the year 2010, NOx, SOx, and
particulates would increase substantially due to the ethanol power plant
emissions.
The use of LPG would produce VOC emission reductions similar to
that for CNG use. Where LPG differs from CNG is that other regulated
emissions reductions from refinery emissions due to displaced gasoline
production would be offset by refinery emissions associated with LPG
production. If more than the current 30% of LPG production is produced
by refineries, emission reductions associated with LPG motor vehicle fuel
use would increase.
The emissions reductions with methanol use would be substantially
similar to ethanol use with 150,000 tons/year VOC emissions reductions
realized by the year 2010 with an increasing CAFE standard, and
somewhat less with a fixed CAFE requirement. The emissions of NOx and
SOx would be significantly less with methanol use compared with ethanol
use due to lower emissions from controlled gasifiers or the use of natural
gas in the production of methanol.
7-55
-------
C Scenario 3: 1 MMBPD Gasoline Displacement Scenario
Scenario 3 results in the greatest impact on emissions due to the
large displacement of gasoline with alternative fuel. However, since this
plan is not implemented solely in urban areas, the full impact of the
emission reductions may not be realized in improved air quality.
Greenhouse gas emissions impacts are primarily a function of the
feedstocks used. Coal use for methanol or CNG production results in large
increases in emissions (unless carbon dioxide recovery is employed as
shown by the emissions with dedicated production) while natural gas and
biomass fuels show net reductions in greenhouse gas emissions.
Scenario 3 would result in the greatest reductions in VOC emissions
of all the scenarios due to the higher volume of fuel used, as shown in
Tables 7-16 and 7-17. While electric vehicles show the greatest reduction,
increasing from 173,000 tons/year by 2000 to 544,000 by 2010, use of
CNG, methanol, and ethanol would produce comparable emission reductions
of approximately 160,000 tons/year by the year 2000, and significantly
more in 2010.
Using coal as a feedstock for CNG production would reduce some
stationary source emissions such as carbon monoxide and sulfur dioxide,
while increasing NOx and particulate emissions. Substantial reductions in
all other emissions would be realized if natural gas was used as a
feedstock.
Increased electricity use would result in higher particulate emissions
while all other emissions would decrease. The NOx mobile source emission
decreases are nearly offset by increased stationary source emissions. The
VOC emissions reductions would be greater than the use of other
alternative fuels.
Ethanol use would result in higher NOx, SOx, and particulate
emissions which are not insignificant. The nitrogen and sulfur oxide
emissions would increase by 54,000 and 272,000 tons/year respectively
due to increased ethanol demand. The VOC emissions reductions would be
comparable to either CNG or methanol.
7-56
-------
Tabic 7-16
EMISSION REDUCTION
1 MMBPDGASOLINE DISPLACEMENT SCENARIO
YR 2000 (1000 Tons/Yr)
CNG*
ELECTRICITY*
Foreign
Vented/ Alaskan
Domestic
Municipal
Natural
Flared Natural
Natural
Municipal
Feedstock
Coal
Biomass
Waste 1
Gas
Gas Gas 1
Gas
Current
Waste I
Solar
Emission Reduction
(ton/yr)
VOC
106
106
163
1 63
163
239
239
NOx
(22.5)
(22.5)
11.3
1 1.3
11.3
(7.68)
96 0
CD
12.3
12.3
18.9
18.9
18 9
14.9
19 0
S02
38.8
47.2
47.2
47.2
47.2
23.3
47.2
Air Toxics
(0 112)
(0 112)
0 945
0 945
0 945
0 945
0 945
Particulate
(20.2)
(20.2)
0.945
0.945
0 945
(19 0)
0.945
CO2 (Equivalent)
(89,100)
- 80,300-
12,800-
1 16,200-
27,500-
18,000-
106,300
(95,500)
94,800
15,800
382,700
32,600
30,400
152,000
ETHANOL
LPG
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Corn
LPG 1
(Dedicated)
(Coproduced) Biomass
Waste 1
Gas
Gas 1
Gas 1
Emission Reduction
(ton/yr.)
VOC
1 36
1 25
1 25
1 25
138
NOx
(61.7)
(12.4)
(12.4)
(12.4)
9.32
CD
9.06
1 1.5
1 1.5
11.5
15 5
SO2
(317)
33 4
33.4
38.9
38.9
Air Toxics
0.096
(0.100)
(0.100)
(0.100)
0.777
Particulate
(6.33)
(12.8)
(12.8)
(12 8)
0.777
CO2 (Equivalent)
(20,700)-
«~
(53,100)-
(40,200)
55,500-
12,900-
(26,900)
(56,500)
(41,300)
65,000
15,500
I Insufficient supply to meet the demand.
Parenthesis indicate negative reductions (increases)
* Assuming a vehicle range shorter than that of a conventional gasoline vehicle. Increasing the range would increase emissions significantly
** If biomass is used as an cthanol feedstock, C02 reductions of 59,100-61,600 could be achieved
-------
Tabic 7-17
EMISSION REDUCTION
1 MMBPD GASOLINE DISPLACEMENT SCENARIO
YR 2010 (1000 Tons/Yr)
CNCi ELECTRICITY
Foreign Venied/ Alaskan Domestic
Municipal
Natural Flared Natural
Natural
Municipal
Feedstock
Coal
Biomass
Waste 1
Gas Gas 1 Gas 1
Gas
Current
Waste 1
Solar
Emission Reduction
(ton/yr.)
VOC
353
353
391
39 1
501
501
NO*
(37.7)
(37.7)
23.7
23.7
(19 8)
202
CD
27 8
27.8
39 4
39 4
28 7
39 4
SOi
83.1
98.5
98.5
98 5
34.0
98 5
Air Toxics
0.054
0.054
1.97
1.97
1.97
1.97
Particulate
(36 6)
(36.6)
1 97
1.97
(51.8)
1 97
CO2 (Equivalent)
(97,900)-
152,000-
42,300-
76,800-
17,000-
222,000
(116,600)
179,700
5 1,600
86,600
33,600
284,600
ETHANOL
LPG
METHANOL
Foreign
Vented/
Alaskan
Coal
Coal
Municipal
Natural
Flared
Natural
Feedstock
Com 1
LPG I
(Dedicated)
(Coproduced) Biomass
Waste 1
Gas 1
Gas 1
Gas 1
Emission Reduction
(ton/yr.)
VOC
377
377 377
NOx
(24.9)
(24.9) (24.9)
CD
30.3
30.3 30.3
S02
86.4
86.4 98.5
Air Toxics
0.454
0.454 0.454
Particulate
(28.4)
(28.4) (28.4)
CO2 (Equivalent)
(92,800)-
(65,500)- 150.400-
(99,600)
(66,500) 170,600
1 insufficient supply to meet the demand
Parenthesis indicate negative reductions (increases)
-------
The emissions reductions for increased methanol use parallel those
for CNG use. With coal as a feedstock NOx and particulates emissions
increase, while all other regulated emissions decrease. If natural gas could
be used as a feedstock all regulated emissions decrease substantially
though this is not shown in the tables.
D. Summary
In summary, the use of alternative fuels in place of gasoline could
result in both positive and negative environmental impacts; additional
research is required to better quantify these potential impacts. The use of
alternative fuels would likely result in significant reductions of ozone
forming VOC emissions and other regulated pollutants. Electric vehicles
have the greatest potential for reductions of VOC and NOx emissions,
although NOx emissions from conventional electric utilities could offset
these potential reductions. By using nonemitting sources for electricity
generation, such as solar energy, the greatest benefit can be realized. Each
of the other fuels evaluated in the report would also likely produce fewer
emissions than gasoline vehicles, due primarily to reductions in
evaporative and refueling emissions. The potential emission reductions
associated with natural gas usage, either for compressed natural gas or
methanol production, are significant, though not as great as those
anticipated from the use of electric vehicles. The use of coal to produce
clean fuels would result in lower VOC emissions, although most other
pollutant emissions would increase. In addition, reductions in urban
stationary source emissions might be possible for some fuels produced in
remote regions (e.g. fuels produced from Alaskan natural gas, vented and
flared gas, and fuel produced in rural areas).
Alternative fuels can also have an impact on the potential for health
effects resulting from exposure to vehicular emissions. In general, due to a
reduction in the total mass of emissions and specifically in emissions of
photochemically reactive compounds that is projected for most alternative
fuels, the contribution of motor vehicles to air toxic emissions would be
reduced. This would likely result in fewer incidences of cancer and other
health problems associated with exposure to these compounds. However,
emissions of some air toxics, such as formaldehyde, are projected to
increase with the use of some fuels (in this case, methanol); the overall
health impact of alternative fuels use has yet to be quantified.
As discussed in the report, the use of many alternative fuels would
provide intrinsic global warming benefits relative to gasoline. Most
prominently, fuels derived from vented and flared gas, municipal waste,
7-59
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and renewable feedstocks would provide major global warming benefits;
unfortunately, the quantities of these feedstocks are likely to be somewhat
limited in the near term. LPG and fuels derived from "produced" natural
gas (methanol and CNG) would provide only marginal global warming
benefits (and, under certain conditions, detriments) relative to gasoline.
The use of fuels derived from coal would result in significant increases in
C02 relative to gasoline, although, as discussed in this Appendix and in
more detail in Appendix 7-B, technologies exist which could control or
capture CO2 emitted from coal-fired alternative fuel plants.
The other environmental impacts of alternative fuel use remain to be
studied. Many theories exist regarding the impact of large spills of alcohol
fuels relative to gasoline. The general consensus appear to be that an
alcohol spill in a large body of water would be less hazardous than a
petroleum spill, but that an alcohol spill in a restricted waterway could
have serious environmental consequences, depending on the quantity
spilled and the specific characteristics of the body of water. Other issues,
such a vehicular safety, are still being evaluated. In addition, the impact
that a large scale alternative fuels program could have on the ecosystem in
terms of soil stability or contamination from a large agricultural or
silvicultural effort must be evaluated. In general, however, alternative
fuels appear to have significant environmental benefits relative to
gasoline.
7-60
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References
1 "Analysis of the Economic and Environmental Effects of Methanol as
an Automotive Fuel," Special Report, U.S. EPA, Office of Mobile Sources,
September 1989.
2 "Analysis of the Economic and Environmental Effects of Compressed
Natural Gas as a Vehicle Fuel, Volume I, Passenger Cars and Light Trucks,"
Special Report, U.S. EPA, Office of Mobile Sources, April 1990.
3 "Analysis of the Economic and Environmental Effects of Ethanol as an
Automotive Fuel," Special Report, U.S. EPA, Office of Mobile Sources, April
1990.
4 "Environmental, Health and Safety Report, Volume III," Final Report,
Prepared by Acurex Corporation for the California Advisory Board on Air
Quality and Fuels, June 13, 1990.
5 "Cancer Risk from Outdoor Exposure to Air Toxics," External Draft
Review, U.S. EPA, OAR, OAQPS, September 1989.
6 "Air Toxics Emissions and Health Risks from Mobile Sources," J.M.
Adler and P.M. Carey, U.S. EPA, OMS, ECTD, TSS, AWMA 89-34A.6, June
1989.
7 "Air Toxics Emissions from Motor Vehicles," Technical Report (Draft)
EPA-AA-TSS-PA-86-5, U.S. EPA, OMS, ECTD, TSS, September 1987.
8 "Emission Standards for Methanol-Fueled Motor Vehicles and Motor
Vehicle Engines," EPA Final Rulemaking, Federal Register, Part 86, No. 68,
14426-14613, April 11, 1989.
9. Wang, Q., DeLuchi, M.A., Sperling, D., (1990), "Emissions Impacts of
Electric Vehicles, J. Air Waste Management Assoc., 40, 1275-1284.
10. Sperling, D., New Transportation Fuels. University of California Press,
Berkeley, CA, 1988.
11. Pollution Assessment Branch, OAQPS, 1988 Air Toxics Inventory.
12. Bolin, B., Doos, B., Jager, J., and Warrick, R., eds., SCOPE 29: The
Greenhouse Effect. Climatic Change, and Ecosystems. John Wilev & Sons.
New York. 1986.
7-61
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13. "The Motor Fuel Consumption Model, 13th Periodical Report,"
prepared for Martin Marietta Energy Systems, Inc., by Energy and
Environmental Analysis, Inc., May 26, 1987.
14. "Relative Global Warming Potentials of Greenhouse Gas Emissions,"
Daniel A. Lashof and Dilip R. Ahuja, December 6,1989.
15. "Cost & Availability of Low-Emission Motor Vehicles and Fuels.
Volume II: Appendices," AB234 Report, California Energy Commission,
August 1989 DRAFT.
16. Conference Report to S.1518, the Alternative Motor Fuels Act of
1988, September 16, 1988.
17. "Coal-to-Methanol: An Engineering Evaluation of Texaco Gasification
and ICI Methanol-Synthesis Route," by Fluor Engineers and Constructors,
Inc., for EPRI, AP-1962, August 1981.
18. "Alternative Transportation Fuels and the Greenhouse Effect," Sprik,
Timothy L., and Deborah W. Adler, Technical Report for U.S. EPA, March
1990.
19. "Coproduction of Methanol and Electricity," Burns and Roe-
Humphreys, Glasglow Synthetic Fuels, Inc., and General Electric Co., for
EPRI, AP-3749, October 1984.
20. Annual Energy Outlook: 1990. Long Term Projections. Energy
Information Administration, DOE, DOE/EIA-0380(90), Published January
1990.
21. "Analysis of the Economic and Environmental Effects of Compressed
Natural Gas as a Vehicle Fuel, Volume II, Heavy-Duty Vehicles," Special
Report, U.S. EPA, Office of Mobile Sources, April 1990.
22. "Gaseous Fuel Safety Assessment for Light-Duty Automotive
Vehicles", M.C. Krupka, et.al., Los Alamos National Laboratory, November
1983. Prepared for the Department of Energy.
23. "Assessment of Costs and Benefits of Flexible and Alternative Fuel
Use in the U.S. Transportation Sector - Progress Report Two: The
International Experience", Department of Energy, August 1988.
7-62
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24. "Alternative Motor Vehicle Fuels to Improve Air Quality." California
Council for Environmental and Economic Balance.
7-63
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Appendix 7-A
Greenhouse Gas Emissions From
Transportation Fuel Use
This appendix provides the details of the assumptions and
calculations made in the greenhouse gas emissions analysis. The energy
efficiency of and the C02 and trace greenhouse gas production from the
extraction, processing, distribution, and combustion of various alternative
transportation fuels has been evaluated. As discussed in Appendix 4, the
fuels considered here include compressed natural gas (CNG), electricity,
ethanol, liquefied petroleum gas, methanol, and gasoline. Several
alternative feedstocks for these fuels are considered as well, including
natural gas, coal, biomass, municipal waste, and the traditional petroleum
crude. The fuel property data used in this analysis is shown in Table 7A-
l.[l-9] Total CO2-equivalent emissions for each fuel/feedstock
combination are summarized in Table 7A-2.
Table 7A-1
Fuel Properties
(lb/gah
6.20
7.12
6.63
6.58
Density
Weight Heating Value
Percent (Btu/lb)
Carbon Lower Higher
Gasoline
Diesel
Methanol
Ethanol
Natural Gas
LPG
Crude Oil
Fuel Oil
Coal
7.40
8.33
86.5 18700 20173
87.4 18080 19270
37.5 8570 9750
52.2 1 1500
73.0 20800 23000
82.8 19737 21500
84.8 18132 19282
84.8 17833 18907
66.9 10874 121 13
(dry) (dry)
7-A-l
-------
i/vat ^ //w: IUIAL UKLLINHOU5L I.A5 LIVII^IONb IKOM IKANhl'UKlAI ION HJU USt
SM Vtrif 20 year
Energy
Fuel
00c
% relative
CO2 %
relative
Feedstock
Type
Cout in cms
F.i|uiv
to Gasoline
Equiv to
Gasoline
Imported Crude
Gasoline
590
0
720
0
Domestic Crude
Gasoline
570
-3
670
-7
Domestic Gas
CNG
Dual-Fueled Vehicle
440
-25
605
-16
CNG
Dedicated Vehicle
360
-39
455
-37
M85
Flexible-Fueled Vehicle
570
-3
660
-8
Methanol
Dedicated Vehicle
440
-25
520
-27
Electric
350
-40
400
-44
Remote Gas
CNG
Dual-Fueled Vehicle
545
-8
715
-4
CMG
Dedicated Vehicle
440
-25
545
-27
M85
Flexible-Fueled Vehicle
5K0
-2
670
-7
Methanol
Dedicated Vehicle
450
-24
530
-26
Vented/Flared Gas
CNG
Dual-Fueled Vehicle - 80% flared
-60
-1 10
-1490
-307
CNG
Dedicated Vehicle - 80% flared
-50
-108
-1255
-274
M8S
Flexible-Fueled Vehicle - 80% flared
-80
-113
-1595
-322
Methanol
Dedicated Vehicle - 80% flared
85
-1 14
-1420
-297
Coal
CNG
Dual-Fueled Vehicle
1 135
92
1370
90
CNG
Dedicated Vehicle
920
56
1065
48
M85
Flexible-Fueled Vehicle
940
58
1080
50
Methanol
Dedicated Vehicle
825
40
940
31
Methanol
Dedicated Vehicle w/Coproduclion
755
26
855
16
Electric
590
0
660
-8
Biomass
CNG
Dual-Fueled Vehicle
125
-79
290
-60
CNG
Dedicated Vehicle
102
-83
200
-72
M85
Flexible-Fueled Vehicle
215
-63
425
-41
Methanol
Dedicated Vehicle
130
-78
280
61
(com)
E8S
Flexible-Fueled Vehicle
635
8
795
10
Ethanol
Dedicated Vehicle
525
-1 1
670
-7
(wood)
Ethanol
Dedicated Vehicle
195
-68
305
-61
Electric
125
-79
180
-75
Municipal Waste
CNG
Dual-Fueled Vehicle
105
-82
285
-60
CNG
Dedicated Vehicle
82
-86
195
-73
M85
Flexible-Fueled Vehicle
170
-71
345
-52
Methanol
Dedicated Vehicle
80
-86
210
-71
Electric
60
-90
95
-87
Domestic LPG
LPG
Vehicle Eff = -5%
505
-15
530
J I)
-------
In the sections below, each fuel/feedstock combination is considered
seperately, with a complete discussion of the emissions associated with the
feedstock used and the entire fuel production process and use cycle. All
alternative fuels are compared to gasoline from imported crude.
Production of domestic oil has been dropping in recent years, and, absent
major new oil discoveries, imports will likely supply the majority of U.S.
petroleum needs in the future. Since the introduction of alternative fuels
will likely offset growth in imported rather than domestic oil, it is
appropriate to compare the greenhouse gas emissions of alternative fueled
vehicles against those of gasoline vehicles fueled with gasoline made from
imported oil. The global warming impact of gasoline derived from
domestic oil is also presented for illustration purposes, however.
The energy efficiency of each step in the fuel use chain (processes
such as fuel refining, fuel distribution, etc.) is an important factor. The
energy efficiency of each step relates to CO2 emissions, since any fuel
energy consumed in that step will have CO2 emissions associated with it.
The amount of C02 emissions in any step is determined by a carbon mass
balance (i.e. the carbon contained in fuel consumed in a step will be
emitted as C02, CO, HC, etc.).
Emissions of other greenhouse gases, CH4 and N2O, are evaluated as
well. Except where noted, methane emissions from stationary sources
were based on EPA's compilation of air pollution emission factors (AP-
42).[10] In all cases except tailpipe vehicle emissions, emissions of N2O
were determined from estimates presented by Kavanaugh.1 [11] For all
steps employing electrical energy, the greenhouse gas emissions associated
with electrical power generation (from coal, natural gas, nuclear,
hydroelectric, and petroleum) were included.
I. Gasoline
A. Petroleum Withdrawal and Transport
The energy efficiency of oil well pumping and crude oil transport via
pipeline has been estimated to be 97 and 97.5 percent, respectively.[12]
In addition to CO2 produced from fuel consumed during production, some
additional carbon is released by natural gas venting and flaring at the well.
Mt is now believed that these N2O emission estimates may be too high, due to an SO2
artifact effect which is emphasized by the sampling method used. N2O emissions from
stationary sources may be considerably lower; however, no new emission factors
have been developed and so the previously accepted emission data is used here.
7-A-3
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The EI A reports that 124 bcf of natural gas were vented or flared in the
U.S. during 1987, while U.S. field production of crude oil totaled 3.05 billion
barrels during the same year.[13] Relating these two figures, 40.7 cubic
feet of natural gas are released per barrel of U.S. crude produced. EIA also
reports that foreign countries vented or flared 2,765 bcf of natural gas
while producing 17.5 billion barrels of crude oil (158.0 cubic feet of
natural gas released per barrel of crude produced).[ 13] These
relationships were used in determining the global warming impacts of
using domestic and foreign crude. Little work has been done to determine
the fraction of this gas which is vented versus that which is flared. One
source has estimated this ratio to be 20 percent vented/80 percent flared,
although this estimate should be considered highly uncertain.[14] A 20/80
ratio of vented/flared gas was used as a baseline in this analysis.
B. Petroleum Refining
An incremental gasoline refining efficiency of 82 percent was used in
this analysis, based on modelling work performed by Amoco Oil Co.[15]
Several studies examining the global warming impacts of gasoline use an
overall petroleum refining efficiency which is somewhat higher. Use of an
average refinery efficiency is inappropriate however, due to the more
energy intensive processes (reforming, catalytic cracking, etc.) involved in
producing the gasoline portion of petroleum products. Using the
aforementioned study, the incremental crude requirements required to
produce an incremental quantity of gasoline (and thus the energy
efficiency) were determined. The efficiency reported here is based on a
gasoline-to-distillate ratio of 1.6 and an estimated pool octane number of
88.4.
C Transportation and Distribution
Fuel consumption data on product tankers were used to predict
crude oil ocean transport efficiencies.[16] Depending on the size of vessel
used, transport efficiencies range from 97.6 to 99.5 percent. An average
value of 98.5 percent for crude oil transport was used in this analysis.
The Oak Ridge National Laboratory documents energy requirements
for transportation of petroleum and products during 1984.[17] Reported
energy requirements for water, rail and pipeline transport were used n
yield an average transmission efficiency of 98.9 percent (99.1 percent with
7-A-4
-------
respect to liquid fuel, and 99.8 percent with respect to electrical energy
use2).
In a paper prepared by Deluchi, Johnston, and Sperling of the
University of California, Davis, it was stated that trucks delivering
petroleum products consumed about 1 percent of the total energy
consumed on the nation's highways.! 18] The efficiency of gasoline
distribution by truck can thus be estimated as 99 percent.
D. Vehicle Use
Tailpipe emissions are based on the vehicle efficiencies discussed in
Appendix 4. An in-use gasoline passenger car fuel economy of 23.1 mpg
was used as the baseline in this analysis. This is based on the actual on-
road performance of vehicles certified at a CAFE of 27.5 mpg.[19]
A substantial body of test data exists documenting regulated
pollutants from gasoline vehicles. The low-altitude, 50,000-mile methane
emission factor is available in AP-42.[10] Projected in-use non-methane
hydrocarbon emissions from gasoline vehicles are based on 9 psi RVP
fuel.[20] In-use emissions of CO and NOx were taken from recent EPA
publications.[21, 22] Emissions of N2O were assumed to be 4.37 percent of
total NOx emissions.[23] This average ratio is for catalyst equipped
vehicles, and seems to be dependent on a range of driving conditions, such
as speed, ambient temperature, and mileage accumulation.
II. Compressed Natural Gas
A. Natural Gas Production
1. Extraction and Processing
The energy efficiency for natural gas extraction and processing
has been estimated at 94 percent.[4] For produced gas, an average CO2
concentration of 3.0 percent in natural gas was assumed.[24]
2. Synthetic Natural Gas from Coal
The thermal efficiency of coal mining has been reported to be
approximately 98.3 percent.[12] In addition to C02. some methane is
2Not including electrical energy generation and distribution losses.
7-A-5
-------
emitted during- coal mining. Based on a recent Bureau of Mines (BOM)
report describing methane liberations from all U.S. coal mines, on average,
about 1.3 grams of methane are liberated for each pound of coal
produced.[25] For this analysis, it was assumed that the coal conversion
facility will be located within 100 miles of the coal mine. A thermal
efficiency of 99.7 percent (HHV) for the transport of coal to the end-use
facility was calculated.[4]
The gasification of coal to produce synthetic natural gas has been
commercially proven, at the Great Plains Coal Gasification Plant. In this
case, coal is gasified, CO shifted to produce the proper synthesis gas
composition, and then synthesized into product methane. The thermal
efficiency of the process is estimated to be 59 percent (HHV).[26]
3. Synthetic Natural Gas from Biomass
As stated in Appendix 4, the production of SNG by anaerobic
digestion of biomass is well documented from a technological point of view.
For the purposes of this analysis, the efficiency of the biomass
development process must be approximated. Studies indicate that the
planting and cultivation of the biomass is estimated to use 581.6 Btu of
diesel fuel to produce 1 MMBtu of SNG.[27] Fertilization of the crop
requires 9,459 Btu of electric energy. Harvesting the crop uses 5,452.2 Btu
of diesel energy. Transportation of the crop to the conversion plant
requires 24,427 Btu diesel energy. A total of approximately 40,000 Btu
are used to develop and transport the biomass necessary to produce 1
MMBtu of SNG. This results in an average collection efficiency of 96
percent.
As the result of photosynthesis, growing biomass for fuel use also
provides a significant greenhouse gas sink. For this reason, a biomass
credit is also included in the analysis.
4. Synthetic Natural Gas from Municipal Waste
As part of this analysis, the collection of municipal waste must be
considered. It has been determined that a diesel garbage truck travels 0.1
miles per 1 MMBtu SNG produced by the production plant.[28] Assuming a
diesel garbage truck gets 6.7 miles per gallon, this converts to a transport
efficiency of 99.8 percent.[10]
There are two methods for producing SNG from municipal waste
One is the generation of methane through anaerobic digestion, which
7-A-6
-------
occurs naturally though slowly in landfills, or can be induced in a plant.
The second method for producing SNG from municipal wastes is
gasification. For this analysis, the gasification process, with a thermal
efficiency of 40 percent, was assumed. Both methods are discussed fully in
Appendix 4.
Currently most municipal waste is deposited in landfills, which are a
source of greenhouse gas emissions, particularly methane. By using the
municipal waste for fuel production, these gases are not emitted at the
landfill. This emission reduction is counted as a credit in this analysis.
B. Fuel Transportation and Distribution
1. Natural Gas Liquefaction. Transport, and Regasification
Remote (overseas) natural gas resources must be transported into
the U.S. by ship in order to be consumed domestically. Since the
volumetric energy density of a gaseous fuel is substantially less than that
of liquid fuels, it is economical to transport natural gas overseas in the
liquid phase. This requires cryogenic refrigeration. The overall efficiency
of natural gas liquefaction is approximately 86 percent.[29]
Many factors are involved in assessing the energy requirements of
the ocean transport of fuel, including the length of voyage, ship size, time
spent in port, etc. For this analysis, a 10,000 nautical mile round trip
length was assumed. Information on carrying capacity, speed, and fuel
consumption of LNG tankers and liquid product tankers was obtained from
the US Department of Transportation.! 16] Using specifications on the
largest LNG tanker reported, a transport efficiency of 95.1 percent was
calculated. Regasification of the natural gas has an efficiency of 97
percent.[30]
2. Natural Gas Transmission and Distribution
Whether the natural gas used in CNG vehicles is made from coal or is
imported via LNG tanker, the domestic gas transportation and distribution
system should be similar to that of today. Total energy efficiency is
estimated to be 96.7 percent (96.9 percent with respect to natural gas and
99.8 percent with respect to electricity).[31,32] Local natural gas
distribution companies ideally have no energy requirements involved with
supplying natural gas. Gas is taken off high pressure transmission lines
and regulated down to lower pressures for customer use.
7-A-7
-------
A distribution efficiency of 99.98 percent was used, based on data
received from one gas distribution company.[33] Efficiencies for other
distribution companies should be similar, although slightly higher or lower
depending on climate conditions. A recent study for EPA estimated total
losses from natural gas transmission, distribution, and processing systems
to be about 0.6 percent of total natural gas consumption.[34] This value
was used to estimate emissions of methane from natural gas systems in
this analysis. Other sources have estimated these losses to be as high a 3
percent on a world-wide basis, with U.S. losses assumed to be lower. More
research is needed in this area to better quantify natural gas losses.
1. CNG Compression and Refueling
The refueling of natural gas vehicles is a well established technology
in widespread use in some foreign countries, as well as with certain fleets
(primarily gas utility fleets) in the U.S. Gas outlet pressures at CNG
refueling stations are typically on the order of 3,600 psig. The energy
requirements for the compressor station depends on the inlet gas pressure
available, which can range from as low as a few inches of water (gage) to
as high as 200-300 psig. In urban areas, for safety reasons and design
considerations, main gas line pressures are regulated down from
transmission pipeline pressure of several hundred psig to pressures of 200
psig or less. Given that the likely inlet gas pressures available to refueling
stations will be around 15-50 psig, an average compression efficiency of
97 percent was used in this analysis.3[35]
2. Vehicle Emissions
CNG vehicle fuel efficiency is discussed in Appendix 4. This report
assumes efficiencies of -10 percent for dual fuel vehicles and +10 percent
for dedicated vehicles.
EPA testing of dual-fuel CNG retrofit vehicles yielded the dual-fuel
emissions data.[22] There has not yet been enough testing of equivalent
performance/equivalent range CNG vehicles to determine actual NOx
emissions. While several CNG vehicles tested have had low NOx emissions,
these vehicles have exhibited poorer performance and shorter driving
ranges than gasoline vehicles. Improving drivability and range would
likely increase NOx emissions. Therefore, in this analysis NOx emissions
3 Not including electrical energy generation and distribution losses.
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were assumed to be the same as those of gasoline vehicles. For dedicated
CNG vehicles relative emissions of non-methane HC and CO from dedicated
CNG and gasoline Ford Rangers were used to estimate 50,000 mile
emissions. For dedicated CNG vehicles, the CO emissions tested were
extremely low. As is the case with NOx, it is questionable whether these
low emission rates could be maintained by vehicles with equivalent range
and drivability. Methane was assumed to be 90 percent of total HC
emissions measured. As with gasoline and methanol vehicles, N2O
emissions were assumed to be 4.37 percent of total NOx.4
III. Electric Vehicles
A. Electric Utility Feedstocks
As discussed in Appendix 7, the electrical energy needed to charge
electric vehicles (EVs) can be supplied by power plants fueled by a variety
of feedstocks. According to EI A reports for 1989, approximately 71
percent of electricity is generated at fossil fuel plants (57 percent coal, 5
percent petroleum, 9 percent natural gas) while the remainder is produced
at nuclear and hydroelectric facilities. [4] Less than 1 percent of electricity
is produced from geothermal, wood, waste, wind, photovoltaic and solar
thermal energy. Biomass and municipal wastes are also considered as
future power plant feedstocks. Greenhouse gas emissions from each type
of fossil fuel electrical plant have been calculated. Greenhouse gas
emissions from nuclear, solar and hydroelectric plants have been assumed
to. be negligible.5
The assumptions and efficiencies assumed for the production and
transport of coal, natural gas, petroleum products, biomass and municipal
waste as feedstocks have all been discussed in the sections above. The
same processes and efficiencies are assumed here as well.
4 It should be noted that the use of a catalyst seems to have a significant effect on N20
emission levels. Limited test data indicate that, in vehicles operating without a
catalyst, N20 constitutes only about 0.55 percent of total NOx emissions, nearly an
order of magnitude lower than from catalyst equipped vehicles. This is important,
since the lean combustion projected to be possible in future methanol and CNG
vehicles, the need for a catalyst could be eliminated. Thus, future methanol and CNG
vehicles may actually exhibit much lower N20 levels than those predicted in this
analysis. Tliis possibility is not considered here, however.
5There would be some emission from nuclear power plants due to enrichening,
but these are not likely to be large.
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B. Electricity Generation
The EIA documents power produced and fuel consumed in coal fired
electric utility plants.[4] An overall electricity-from-coal efficiency of 28
percent was calculated. Similar calculations were performed for natural
gas and petroleum products, yielding efficiencies of 29 percent for each.
These efficiencies include a transmission loss of 14 percent, as estimated
by the EIA.[4] Heavy fuel oil is the dominate petroleum product used to
fuel power plants, though EIA reports trace percentages of light fuel oil
and petroleum coke are also used.[4] Heavy fuel oil was assumed in the
calculations done for this report.
If renewable energy resources become more common as a power
plant fuel in the future, this would have a significant impact on the
greenhouse emissions associated with EV use. Therefore, the efficiencies of
electricity from biomass and municipal wastes have also been calculated.
An overall electricity-from-biomass efficiency of 20 percent has been
estimated.[28] Production of electricity from municipal waste was
estimated to have an overall efficiency of 30 percent.[28]
C Vehicle Use
Any emissions directly from the electric vehicle are expected to be
small. For this analysis, there were assumed to be no emissions directly
associated with the use of an electric vehicle.
IV. Ethanol Vehicles
A. Ethanol Production
The primary feedstock for ethanol is com, which is quite energy
intensive to produce. For this analysis, cellulosic biomass was also
considered as an ethanol feedstock. The development and transport of this
feedstock is similar to that discussed for CNG from biomass.
A number of studies have investigated energy requirements for
ethanol production via fermentation.[36,37] For the purposes of this study,
a range of 40,000 to 60,000 Btu/gallon ethanol production is used to
represent large, integrated plants versus smaller, less energy-efficient
facilities. Two levels of energy efficiency are also considered, the first
assuming coal is used to provide process heat and electricity is purchased
commercially, while the second incorporates energy efficiencies available
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from cogeneration. This is discussed in more detail in Appendix 4. Based
on these assumptions, the following efficiencies were assumed. For a
40,000 Btu/gallon plant, 80 percent efficiency with cogeneration and 69
percent without it. For a 60,000 Btu/gallon plant, 74 percent without and
87 percent with cogeneration.
The assumptions and calculations made to estimate the energy used
to produce the biomass are similar to those discussed for biomass
development. The analysis included energy use and related emissions
from maintaining, harvesting and transporting the biomass crop. An
emissions credit was taken to account for photosynthesis by the biomass
crop. An additional credit was given for the byproducts yielded in the
conversion process.
B. Distribution
For this analysis, it was assumed that the energy requirements for an
ethanol distribution system would be substantially similar to those for
gasoline, per volume of fuel transported. Due to the fact that the
volumetric energy of ethanol is lower than that of gasoline, transmission
energy requirements are proportionally higher. An overall transmission
efficiency of 97.8 percent was estimate.
C Vehicle Use
The efficiency of an ethanol fueled vehicle is discussed in Appendix
4, For this analysis, efficiencies of +5 percent and +30 percent with respect
to gasoline vehicles are expected for flexible fuel and dedicated ethanol
vehicles, respectively.
The emission factors used for ethanol vehicles are based on limited
testing of in-use fleets. The impacts of land use changes on C02 are not
considered here but are potentially important when considering the long
term global warming benefits associated with ethanol use.
V. Liquefied Petroleum Gas
A. Feedstocks
As stated in Appendix 4, approximately 70 percent of the LPG
produced in the U.S. comes from natural gas, with the remainder supplied
by refineries. In this analysis, only LPG from domestic natural gas is
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considered. The extraction and transport of natural gas has been discussed
previously.
Usually, natural gas is stripped of liquid components at the wellhead
before being transported to the end-user. However, it can also be
transported to the processing plant wet. It is reported that a negligible
amount of energy is required for transportation. There is, however, some
loss of methane during transport. As mentioned in the CNG section, a small
amount of natural gas is lost during transmission and distribution. Since
there is no loss of methane during LPG distribution, it is assumed that only
half the amount reported is lost during transportation to a LPG processing
plant.
B. LPG Production
LPG may be stripped from natural gas by absorption, adsorption, or
compression. The most current technology is cryogenic seperation using a
turboexpander.[38,39] The amount of LPG in natural gas can vary from as
much as 1 gallon LPG per 1000 cf for lean gas, to 10-12 gallons LPG per
1000 cf for rich gas. Therefore, the energy required for processing the gas
also varies, being higher for leaner gas. An average energy efficiency for
this process is estimated to be 86.5 percent.[38]
C Distribution
LPG is transported and distributed by tank car, truck, and pipeline.
Since it is transported in a closed system, minimal leakage of LPG to the
atmosphere is expected. The energy efficiencies for transportation and
distribution of LPG have been estimated to be 96.5 and 98.6 percent,
respectively.[38]
D. Vehicle Use
As discussed in Appendix 4, the fuel efficiency of an LPG vehicle is
assumed to be 5 percent less than that of an equivalent gasoline vehicle.
The data on LPG vehicle emissions is obtained from the May 19, 1989 State
of California ARB report. [40]
LPG is normally stored and transferred in its liquid form. At normal
temperatures, it only requires approximately 160 psi to keep it in its
liquid state. Assuming that the refuelling station pumping configuration
for LPG is the same as that for gasoline, LPG dispensing efficiency is
approximately 99.3 percent. Since the energy density of LPG is only 80
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percent of that for gasoline, its dispensing efficiency is slightly lower than
that of gasoline.
The feedstocks considered for methanol include natural gas, coal,
biomass and municipal waste. These are discussed in more detail in
Appendix 4. As these are the same feedstocks considered for the other
alternative fuels, and feedstock development is the same regardless of the
resulting fuel. A discussion of the process energy consumption during
feedstock preparation is provided above.
B. Methanol Production
1. Natural Gas to Methanol
Several new improved efficiency processes have been developed and
proven at the pilot plant stage, and are in the process of commercial
testing. One such process, the catalytic partial oxidation process developed
by Davy KcKee, uses a catalytic fixed-bed reactor is used to make syngas.
Natural gas is reacted with minimum steam and oxygen over a catalyst to
produce a synthesis gas with composition close to stoichiometric for the
methanol synthesis. Less heat is lost in this method of synthesis gas
production than is in reforming, and shift conversion of the synthesis gas is
not required. Capital investment required for the plant is also reduced
substantially.
Based on data provided by Davy McKee Corporation, the efficiency of
a 2000 ST/day plant was calculated to be about 66.7 percent (HHV
basis).[41] This compares favorably with conventional steam reforming,
the efficiency of which is about 61.3 percent (HHV).[41] Since several of
these new processes are likely to become commercially proven within the
next few years, the corresponding efficiency of 66.7 percent was used in
this comparative study.
2. Coal to Methanol
As discussed in Appendix 4, methanol can be produced from coal by
indirect liquefaction, a process in which the coal is first gasified (producing
a synthesis gas of CO and H2) and then synthesized into methanol. This
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production technology is currently available, but is not able to compete
economically with natural gas based methanol. The thermal efficiency of
producing methanol from bituminous coal has been estimated to be from
49 to 59 percent.[42] A conversion efficiency of 55 percent HHV was used
as the basis of calculations in this analysis.[26]
3. Biomass to Methanol
Several processes for converting biomass to methanol have been
studied.[43,44] The DOE recently evaluated methanol production from
biomass using present and near-future technology.[45] These conversion
processes are discussed in more detail in Appendix 4. Based on these
studies, an average thermal efficiency of 43 percent was estimated.
4. Municipal Waste to Methanol
Methanol can be produced from municipal waste through indirect
liquefication processes similar to those used for coal and biomass, as
discussed in Appendix 4. An average thermal efficiency of 40 percent was
calculated for the conversion process. [46]
C Methanol Transportation and Distribution
Requirements for the ocean transport of natural gas have been
discussed in detail in the CNG section of this appendix. The same
efficiencies apply to the methanol calculations as well. Calculations yielded
95.8 percent for 40,000 deadweight ton vessels for methanol transport,
and 99.0 percent for 250,000 deadweight ton vessels. An average value of
97.4 percent was used for this analysis.
Domestic transmission and distribution of natural gas was also
discussed in detail in the CNG section. A total transmission efficiency of
96.7 percent, and distribution efficiency of 99.98 percent were used.
Emissions due to natural gas leakage and fuel combustion throughout the
process were also considered.
To distribute a quantity of methanol equivalent in energy to current
deliveries of petroleum product, trucks would have to transport twice as
much fuel and so would also consume twice as much fuel as in the gasoline
case. The resultant efficiency of methanol distribution can thus be
calculated as 98.0 percent.
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D. Vehicle Use
The efficiency of a methanol fueled vehicle is discussed in Appendix
4. For this analysis, efficiencies of +5 percent and +30 percent with respect
to gasoline vehicles were expected for flexible fuel and dedicated methanol
vehicles, respectively. The energy efficiency of fuel dispensing was
estimated for methanol in a 1982 DOE report.[47] In that report, methanol
fuel dispensing was determined to be 99 percent energy efficient.
Emission factors for methanol vehicles were obtained from a much
smaller data base than that for gasoline. Two types of vehicle are
included: flexible fueled vehicles and optimized dedicated vehicles. The
projected in-use HC emissions for both FFV and dedicated methanol
vehicles were taken from the EPA report on methanol as an alternative
fuel.[48] Methane emissions were estimated to be roughly 10 percent of
total hydrocarbon emissions, based on testing performed at the Southwest
Research Institute on a methanol VW Rabbit and Ford Escort.[49]
Emissions of CO and NOx from dedicated and flexible fueled methanol
vehicles were assumed to be the same as those of gasoline vehicles.[21]
Emissions of CO from dedicated methanol vehicles employing lean burn
technology could be considerably lower.[21] This potential improvement
was not considered here, however. As with gasoline vehicles, N2O
emissions were once again estimated to be 4.37 percent of total NOx.
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References
1. "Gasohol: Technical, Economic, or Political Panacea?," Thomas C.
Austin and Gary Rubenstein, SAE Paper 800891, August, 1980.
2. "Natural Gas (Methane), Synthetic Natural Gas, and Liquefied
Petroleum Gases as Fuels for Transportation," R.D. Fleming, R.L. Bechtold,
SAE Paper 820959, August 1982.
3. "The Performance of a Spark-Ignition Engine Fuelled with Natural
Gas and Gasoline," R.L. Evans, F. Goharian, and P.G. Hill, SAE Paper 840234,
February, 1984.
4. Energy Information Administration, "Monthly Energy Review," July,
1987.
5. "Engine Performance and Exhaust Emissions: Methanol versus
Isooctane," G. Ebersole, Phillips Petroleum Co.; and F. Manning, The
University of Tulsa, SAE Paper no. 720692.
6. "A Technical Assessment of Alcohol Fuels," Alternate Fuels
Committee of the Engine Manufacturers Association, SAE Paper
No. 820261.
7.- "Economic Feasibility Study, Fuel Grade Methanol From Coal For
Office of Commercialization of the Energy Research and Development
Administration," McGeorge, Arthur, E.I. Dupont Company, For U.S. ERDA,
1976 TID-27606.
8. Marks' Standard Handbook for Mechanical Engineers. 8th edition,
McGraw-Hill Book Co.
9. Assessment of Methane-Related Fuels for Automotive Fleet Vehicles,
Vol. 3. DOE/CE/50179-1, February 1982.
10. "Compilation of Air Pollutant Emission Factors, (AP-42)," US.EPA,
Fourth Edition, September 1985.
11. "EPA Workshop on Emission From Combustion (Durham, NC,
February 13-14, 1986)," ORD, U.S. EPA, EPA/600/8-86/035.
7-A-16
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12. "Alternate Portable Fuels for Internal Combustion Engines," Alternate
Fuels Committee of the Engine Manufacturers Association, SAE Paper No.
790426.
13. EIA International Energy annual, 1988. DOE/EIA-O219(88), Tables 1
& 22
14. Impacts of World Development on Selected Characteristics of the
Atmosphere: An Integrative Approach, Volume 2 - Appendices. Oak Ridge
National laboratory, ORNL/Sub/86-22033/l/V2
15. Memorandum: to Charles Gray, EPA/ECTD, from Susan Stefanek,
EPA/SDSB, RE: Effect of Incremental Reduction of Gasoline Production on
Crude Oil Purchased. 9/90.
16. "Assessment of Costs and Benefits of Flexible and Alternative Fuel
Use in the U.S. Transportation Sector, Technical Report Three: Methanol
Production and Transportation Costs," United States Department of Energy,
November, 1989
17. "Transportation Energy Data Book: Edition 9," Holcomb, Mary C.,
Floyd, Stephanie D., Cagle, Stacy L., prepared by Oak Ridge National
Laboratory for the U.S. Department of Energy, April 1987.
18. "Transportation Fuels and the Greenhouse Effect," Mark A. DeLuchi,
Robert A. Johnson, Daniel Sperling, University of California, Davis, October
1,. 1987.
19. MOBILE3 Fuel Consumption Model, Draft, Jan. 1989. U.S.
Environmental Protection Agency.
20. Office of Air & Radiation Analysis of the Clean Alternative Fuels
Program. EPA Special Report, July 1989.
21. "The Motor Vehicle Emission Characteristics and Air Quality Impacts
of Methanol and Compressed Natural Gas," Jeff Alson, Jonathan Adler,
Thomas Baines, U.S. EPA, July, 1988.
22. Analysis of the Economic & Environmental Effects of Compressed
Natural Gas as a Fuel For Passenger Cars and Light Trucks, EPA Special
Report. December 1989.
7-A-17
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23. "Motor Vehicles as Sources of Compounds Important to Tropospheric
and Stratospheric Ozone," F.M. Black, US EPA.
24. Gas Engineers Handbook. First Edition, Industrial Press Inc., New
York, 1965.
25. Coal Data: A Reference. DOE/EIA-0064, 1985, p.31
26. Increased Automobile Fuel Efficiency and Synthetic Fuels-
Alternatives for Reducing Oil Imports," Congress of the United States, Office
of Technology Assessment, September, 1982.
27. "Biomass and Wastes as Energy Resources: Update" D.L. Klass, from
Symposium Papers: Clean Fuels from Biomass and Wastes. January 25-28,
1977.
28. "Biofuels, A Survey" J.R. Benemann, Electric Power Research
Institute, June 1978.
29. Private Communication With Phillips Petroleum Company Staff,
October 1, 1987.
30. Letter from Max M. Levy, Columbia Gas System Service
Corporation, to Timothy Sprik, US EPA, August 3, 1987.
31. Bolin, B., Doos, B., Jager, J., and Warrick, R., eds., SCOPE 29: The
Greenhouse Effect. Climatic Change, and Ecosystems. John Wiley & Sons,
New York, 1986.
32. "Energy Information Administration, Natural Gas Annual 1985,"
DOE/EIA-O131(85).
33. Letter from T. Miller, Michigan Consolidated Gas Company, to Tim
Sprik, US EPA, August 6, 1987.
34. "Annual Methane Emission Estimate of the Natural Gas and
Petroleum Systems in the United States," prepaid by B.H. Tilkicioglu, D.R.
Winters, Pipeline Systems Incorporated for ICF Incorporated, December,
1989.
35. "CNG Compressor Operations Monitoring," prepared by B.C. Research
for Department of Energy, Mines, and Resources, January 1986.
7-A-18
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36. S. P. Ho, Amoco Oil Company
37. Marland and Turhollow, Oakridge National Laboratory
38. "Global Warming Impact of Gasoline vs. Alternative Transportation
Fuels", SAE #901489, August 13-16, 1990.
39. Per conversation with Ron Cannon, October 29, 1990.
40. "Definitions of a Low-Emission Motor Vehicle In Compliance with the
Mandates of Health and Safety Code Section 39037.05", State of California
Mobile Source Division/ARB, May 1989.
41. Letter From Joseph Korchnak, Davy McKee Corporation to T. Sprik, US
EPA, July 8, 1987.
42. Indirect Liquefaction Processes," John McGuckin,
SDSB/ECTD/OMS/OAR/US EPA, EPA-AA-SDBS-82-5, February, 1982.
43. "New Transportation Fuels, A Strategic Approach to Technological
Change", D. Sperling, University of California Press, 1988.
44. "Thermochemical Production of Methanol from Biomass in Hawaii",
V.P. Phillips, et.al. abstract in "Sythesis Gas Conversion", DOE, Vol. 90, No.
12.
45. "Assessment of Cost of Production of Methanol from Biomass", for
Solar Energy Research Institute, DOE, by Chem Systems, December, 1989.
46. "Fuel Alcohol. An Energy Alternative for the 1980s. Appendix", U.S.
National Alcohol Fuels Commission, Washington, D.C., 1981.
47. "Assessment of Methane-Related Fuels for Automotive Fleet
Vehicles," prepared by The Aerospace Corporation for US Department of
Energy, DOE/CE/50179-1, February, 1982.
48. "Analysis of the Economic and Environmental Effects of Methanol as
an Automotive Fuel", EPA Special Report, September, 1989.
49. "Characterization of Exhaust Emissions From Methanol- and Gasoline-
Fueled Automobiles," prepared by Southwest Research Institute for U.S.
EPA, EPA460/3/82-004, August, 1982.
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Appendix 7-B
Options and Economics for CO*? Control
In the case of fuels where the potential for an increase in C02
emissions exists (such as those based on coal), it may be possible to control
or capture much of the C02 that will be emitted. While the collection of
CO2 should be technically feasible at any point of emission along the
energy-use chain, the most promising point of control is at the fuel
production facility. At the facility where a fossil fuel resource is converted
to a transportation fuel, CO2 emissions are plentiful, highly concentrated
(at least in some coal conversion processes, due to the use acid gas removal
units), and at a high pressure (which makes recovery relatively easy). The
economics of installing CO? control equipment, therefore, should be most
favorable at this location, and the global warming contribution of these
fuels will be greatly reduced when compared with production without CO2
control options.
This appendix will explain in greater detail the potential markets for
CO2 and will address more fully the economics of the options to recover
CO2 from a coal-to-methanol or coal-to-(synthetic) natural gas plant that
were presented in Appendix 7. In addition, the environmental impacts of
the recovery options will be discussed.
I. Markets for CO?
Technology exists for recovery of much of the C02 emitted in coal
conversion processes, but options to use or dispose of this gas must be
available before these control options can be implemented. Several
markets currently exist for CO2, as discussed in Section A. The potential
for these markets to use additional C02 is limited, however. Hence,
alternative markets must be explored and developed before C02 recovery
can be implemented on a large scale. One potentially major use of CO2
could be in enhanced oil recovery, as will be addressed in Section B.
Alternately, if a commercial use cannot be found for the C02, then disposal
methods will have to be evaluated and compared with other types of CO2-
control strategies. Two potential methods of disposal, in depleted oil and
gas wells and in the deep ocean, are discussed in Sections C and D,
respectively.
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A. Existing Markets
Carbon dioxide currently has several commercial uses. The beverage
industry uses it for carbonation and it is used in the production of dry ice
and soda ash. These markets are small relative to the amount of C02
emitted yearly, however, and could not absorb significant quantities of
additional C02 recovered from fuel production. In addition, higher costs
could be incurred if purification of the CO2 was required before use in one
of these applications. A new market for C02 that is. currently being
researched is the use of CO2 from landfills or coal gasification as an
agricultural fertilizer^ 1] The CO2 is cleaned, mixed with water, and used to
irrigate crops via a "drip system" where the carbonated water is allowed to
seep into the ground around the plants (as opposed to traditional row
irrigation methods). Initial tests have produced "successful" yields of
tomatoes and cotton, but no detailed technical or economic information is
available on the process to date. Many questions exist regarding this
process, including whether it has widespread application potential or must
be limited to crops which can survive in and thrive on an acidic soil.
With the exception of these small industries, the best new options for
the use or disposal of recovered CO2 are enhanced oil recovery, disposal in
depleted gas and oil wells or other underground caverns, or disposal in the
deep ocean. The following sections will look at these two potential markets
in greater detail.
B. Enhanced Oil Recovery
Enhanced oil recovery (EOR) is defined as the incremental production
of crude oil from a reservoir, using a variety of methods, after the original
rate of production from the reservoir begins to decline. Secondary
recovery methods usually involve injecting water into the reservoir (a
"water flood") to aid oil production. Tertiary recovery methods include
any one, or a combination, of thermal (steam), gas (hydrocarbon, C02, N2,
flue gas), chemical (alkaline, polymer, foam), or other processes, often used
in conjunction with or alternating with water. Each reservoir must be
examined for depth, porosity, pressure, viscosity, and other factors before
a tertiary recovery method is chosen; because of the great variability that
occurs between reservoirs, not all methods work well for all reservoirs,
even neighboring ones. There are several processes for injecting C02,
including miscible flooding, immiscible flooding, and "huffn'puff"; most
projects today use either miscible flooding or huffn'puff.[18]
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Carbon dioxide is used widely for EOR, with 56 projects currently
operating in rhe U.S. and 18 more planned to begin operation in 1990-
1992.[2] These projects are located in Texas, Oklahoma, Wyoming,
Louisiana, Colorado, Alaska, New Mexico, Mississippi, Montana, and Utah.1
The oldest C02 flood was started in 1972 and is still operating.
There are three sources of CO2 currently used for EOR: natural
reservoirs, pure process vents, and flue gases. Colorado, New Mexico, and
Mississippi have large natural CO2 reserves. About 30 trillion cubic feet
(tcf) of C02 is estimated to be under Colorado and New Mexico; Mississippi
may have as much as 7 tcf.[3,4] Process vents from hydrogen production
plants are essentially pure CO2 and are thus an attractive CO2 source. Flue
gases from many chemical industries and power plants also contain CO2;
however, these gases contain less than 15 percent by volume C02, while
CO2 used for EOR must be 90-95 percent by volume C02-[5] The expense
of recovering and purifying these flue gases makes their use less desirable
when compared to other sources.
Most current carbon dioxide flood EOR projects use C02 from natural
reserves, although other sources are used, depending on the location of the
oil reservoir. A pipeline has been built to carry C02 from the reserves in
Colorado to the oil fields in western Texas. Costs estimates for a similar
pipeline in Mississippi have also been made.[4]
The price of CO2 delivered to the well varies depending on the source
and on the distance the gas must be transported, while the volume of CO2
used for EOR varies greatly between projects due to the unique properties
of each reservoir. Currently, delivered prices range from $0.85-1.50 per
thousand cubic foot (Mcf) of CO2. Most projects report C02 consumption
rates ranging from 0.4 to 11 Mcf per barrel of oil recovered, depending on
the type of CO2 injection used, and have varying degrees of success as
measured by the volume of oil recovered.[6,18] One project in Hansford
County, Texas uses about 9.2 Mcf of purchased CO2 per barrel of oil
recovered, plus additional recycled C02- This project has enabled recovery
of about 1.5 million barrels of oil [12 percent of the original oil in place
(OOIP)] since the CO2 flood began in 1980.[7] Because the amount of CO2
retained by the reservoir varies, it is difficult to determine how much CO2
will be needed and how much can be recycled. One estimate puts C02
1 Many of these states have significant coal reserves of varying sulfur content
Gasification of coal, which is the easiest way to recover C02 emissions from coal
conversion, is particularly attractive for high sulfur coals.
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recovery at 30 percent of that injected, but this does not apply to all
reservoirs.
Over 95,000 barrels per day of oil produced in the U.S. result from
the use of C02 in EOR.(2] This accounts for 35 percent of the total
production in the oil fields using this recovery method. It is estimated that
if CO2 EOR were used in 400 Mississippi oil reservoirs that have been
evaluated as good candidates for this process, up to 120 million
incremental barrels of oil could be produced in that state.[4] At average
rates of CO2 consumption (6.7 Mcf/barrel oil recovered for miscible
flooding and 1,7 Mcf/barrel for huffn'puff), the current projects in this
country could use between 4 and 14 million tons of CO2 per year (65 to
230 million Mcf/year). This volume of C02 is equivalent to 20 to 60
percent of the CO2 that would be released annually from coal-based SNG or
methanol production under alternative fuel market Scenario 1 (and
obviously a smaller fraction of the amount produced under Scenarios 2 and
3), Since more floods are planned for the future, this market could grow to
absorb an even greater fraction of the CO2 recovered from the production
of alternative fuels from coal under the scenarios presented in this report.
C P?ptet
-------
pressure is 2000 psia and the well temperature is 180°F, the volume made
available in depleted gas fields by historic withdrawals could hold 97
billion tons of C02 (at 3000 psia and 180°F). This volume of CO2 is enough
to satisfy the recovery needs under Scenario III for several hundred years
(recognizing the same concerns regarding feasibility that were discussed in
the preceding paragraph). Combining oil and gas well storage would
provide many years of CO2 storage under this scenario.
Additional study into the feasibility of long term storage of CO2 tn
depleted oil or gas wells is desirable, since the global warming benefits of
this process would be minimal if the retention time were short. However,
it appears that retention of CO2 would be quite successful, at least in
depleted gas wells, since these wells held natural gas for thousands of
years at pressures greater than 2000 psi. If CO2 can be retained
indefinitely in the reservoirs, this method could prove to be attractive as
part of a strategy to mitigate the release of CO2 from the production of
coal-based alternative fuels.
D. Ocean Disposal
According to Steinberg and Cheng, the largest potential storage site
for CO2 is in the deep oceans, at depths of 75 meters or greater.[8] Since
the mixing rate between ocean layers at that depth is low, retention times
of hundred of years could be realized if a means to deliver CO2 to those
depths is developed. Retention times could be even lower if reactions
between the C02 and minerals in ocean sediments occurred.
Steinberg and Cheng explored two systems for disposal of liquefied
CO2. The first system involved discharging CO2 at 2000 psi at a depth of
500 meters by piping the liquefied CO2 100 miles out to sea. The natural
thermocline circulation of the ocean would provide the dissolution
necessary. The second system involved discharging the CO2 at depths of
3000 meters. At this depth, the CO2 would be more dense than the water
(it would be at a pressure of about 4400 psia) and would form a pool that
would sink to the floor of the ocean. In this case, the CO2 would need to be
compressed to 4000 psia and piped about 200 miles out to sea, a more
costly process.
Obviously, in the long term this disposal method is only temporary,
as some of the C02 would eventually be released to the atmosphere.
Before the costs and benefits of this method are compared from a global
warming viewpoint, however, further study of the ecological impact of
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such a disposal system is needed to insure that no damage is done to the
ecosystems of the ocean. As with depleted well disposal, this method could
have potential if the process proves to be environmentally safe.
11. Discussion and Economics of CCb Control Options
The following is an analysis of the costs, feasibilities, and global
warming benefits of several options for controlling CO2 emissions from
coal-based alternative fuel production. Recovery of C02 by scrubbing the
gas from power plant stack gases has been analyzed in the past. The
energy requirements and costs of these proposals appear prohibitive due
to the dilute volumes of CO2 contained in these streams. In contrast, most
of the CO2 emissions from the production of coal-based alternative fuels
would be in concentrated streams; thus, recovery of this C02 would be less
energy and capital intensive. This analysis is a preliminary study based on
an evaluation of existing designs for coal conversion plants. Two plant
designs were evaluated: a design for a dedicated coal-to-methanol plant
and a design for a methanol/electricity coproduction plant.[ 10,15]
Estimates of CO2 recovery costs are based on the removal and
recovery of C02 contained in the flue gases of a 100 MW power plant.[8]
The author's cost estimates were escalated to 1989 dollars using the
Marshall & Swift Equipment Cost Index for capital equipment and scaled to
the larger capacity using an exponential capacity ratio scaling factor of
0.67.[11,12,13] A disposal site, whether an oil field where the C02 would
be used for EOR or one of the other options (such as depleted oil or gas
wells) discussed in Section I, was assumed to be located 100 miles from
the methanol plant. This distance appears to be reasonable for a plant
location in the Midwest (where high sulfur coal is located), which would be
100 miles from many depleted oil and gas wells.
Since the analysis performed for this report was not a rigorous
engineering evaluation, some uncertainty exists regarding the costs of
implementing the CO2 recovery methods. A more detailed analysis
involving the design of a grass-roots plant (as opposed to proposing
modifications to an existing design) would be desirable in order to more
precisely determine actual CO2 control costs. In spite of these
uncertainties, however, this analysis will provide a basis for evaluating the
economic feasibility of these methods.
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A. Dedicated Production of Methanol from Coal
Carbon dioxide is emitted primarily from three locations in a
dedicated coal-to-methanol plant: the acid gas removal system, the sulfur
removal plant, and the heat recovery/steam generation system (boiler)
stacks. In the specific plant evaluated, the majority of C02 (about 80
percent of the total emissions by the plant) is released from of the acid gas
removal unit (Stream 2 of Figure 7-2).[10] Another 6 percent leaves with
the tail gases from the tailgas treating units which are downstream of the
sulfur recovery plant (Stream 3). The remaining 13 percent of total C02
released leaves the boiler stacks after methanol synthesis (Stream 5).
Possible options for recovering the C02 emitted by such a plant
include:2
1. Recovery from the acid gas removal unit (81 percent of C02 emitted).
Although the C02 contained in this stream could be stripped
from the other components (mainly N2), this could be a
costly process. Eliminating the use of N2 in the acid gas
removal process by regenerating the solvent thermally
would result in an essentially pure CO2 stream that would
simply need to be compressed.3
2. Recovery from the sulfur plant tail gas (6 percent of CO2 emitted).
If oxygen is used instead of air in the sulfur plant, the tail gas
would contain almost pure CO2. No stripping would be
needed; recovery would be simplified.
2The options posed here are specific to the plant design evaluated (as depicted in
Figure 7-2). For plant designs using other types of equipment, the modifications
needed to recover the CO2 may differ from those discussed here.
3Some coal-to-methanol plant designs employ other acid gas removal systems that do
not use N2 for solvent regeneration. Hence, a pure CO2 stream is produced and no
modifications to the plant design are needed before recovery of the CO2 can be
accomplished. The coproduction plant discussed in Section B is an example of such a
design.
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3. Recovery from the boiler stack gases (Stream 5) (13 percent of CC>2
emitted).
Since the concentration of C02 in this stream is low (about 36
percent), absorption and stripping would be needed to
recover it from this stream. The economic attractiveness of
this option would likely be the least of the three.
C02 recovery from each of these streams will be discussed in more
detail below. Cost estimates for plant modifications and for the recovered
CO2 will also be provided.
1. Recovery from the Acid Gas Removal Unit
The plant design of Figure 7-2 uses a Rectisol acid gas removal
process, in which raw syngas is passed through an absorber where cold
methanol absorbs the acid gases (H2S, COS, and CO2). The methanol
solvent is regenerated by stripping out the acid gases from the methanol
with nitrogen in a second absorber. The N2 diffuses into the gas, reducing
the concentration of CO2 in the stream.
Since 81 percent of all the CO2 released by the plant (about 17,800
tons/day) is contained in Stream 2, and since it contains almost 90 mole
percent CO2, plans for potential emission recovery modifications to the
plant should concentrate on this stream. An option for recovery of this
CO2 would be to eliminate the use of nitrogen by the Rectisol unit. If N2 is
not used to regenerate the solvent, the purity of the C02 stream would
increase to 99.8 percent. Since stripping of the C02 would not be needed,
the recovery costs would include only the cost of compression and piping.
The total capital cost of the equipment needed to compress and transport
this C02 stream 100 miles is estimated to be $200 million (assuming a
recovery efficiency of 98 percent to account for potential system leaks).4
The total operating costs, including the costs of operating the pipeline and
the operating costs for compression, are estimated to be about $75
million,5 or about $13 per ton of C02 recovered. If the recovery costs were
4If greater transportation distances are required, costs would obviously increase,
capital costs could increase approximately 20 percent, for every 100 miles of
additional pipeline required.
5Based on an estimated cost of SO.Ol/mcf for pipeline operation [17]
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passed along to the methanol instead of the C02, an additional $0.07 per
gallon would be added to the production cost of the methanol.
2. Recovery from the Sulfur Plant Tail Gas
Of the remaining 19 percent of C02 emitted plant wide, 6 percent
(about 1,200 tons/day) is contained in the tail gas of the sulfur treatment
section, which includes a sulfur removal plant and a tail gas treatment unit
(TGTU) (Stream 3). Based on the composition of the gases entering these
units, removal of the H2S and COS should leave an almost pure C02 stream.
However, this stream gets diluted because the plant burns one-third of the
acid gas stream in air to convert H2S to S02 so that the proper ratio (2:1)
of H2 to SO2 is present for conversion to elemental sulfur in the reactor.
The TGTU unit, where residual sulfur is removed, also uses air. These
combined processes introduce impurities into the tail gas, resulting in a tail
gas stream that is reduced to about 62 percent CO2.
An option for C02 recovery from this stream would be to increase its
purity in the tail gas by using oxygen instead of air in the sulfur plant and
TGTU units. This would require a capital investment of about $6 million
for increasing the capacity of the air separation plant and increased
operating costs of approximately $2 million. Making this modification to
the plant would increase the purity of the CO2 in the stream to 98 percent.
Compression and transportation of this CO2 would cost about $5 million in
capital (assuming an incremental cost for compression and transportation
over the cost of recovering the C02 from the Rectisol process). The total
operating costs for option 2 would translate to a cost of about $15 per ton
of CO2 recovered. If costs were allocated to the methanol produced, the
net increase would be about $0.01 per gallon.
3. Recovery from the Boiler Stack Gases
The remaining 13 percent (about 2,800 tons/day) of CO2 released is
contained in the boiler stack gases (Stream 5). The main components of
the stack gases are CO2, H2, N2, and Ar. The fuel gases are burned in the
gas fired boilers; even more impurities are added to this stream at this
point. The gas leaving the boilers is only about 36 percent CO2. Recovery,
compression, and transportation of 90 percent of the C02 from this stream
would cost approximately $45 million for the capital equipment.6 Total
6According to Steinberg and Cheng, 90 percent is a reasonable rate of recovery for
low purity streams.
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operating expenses would be about $21 million. This step alone would cost
$25 per ton of CO2 recovered; much higher than the costs of either of the
other options discussed. The methanol cost would increase $0.02 per
gallon if the cost of option 3 were allocated to the methanol.
Modification of the boilers to burn 02 instead of air would not yield
any additional C02- According to the original plant design, N2 and Ar are
present in the coal and remain in the syngas after gasification. Hence, the
concentration of C02 in Stream 5 could not be increased enough by burning
with O2 instead of air to enable direct recovery without absorbing it from
the stack gases. Therefore, the added expense of enlarging the oxygen
plant to increase the concentration of Stream 5 would probably not be
justified and this option was not analyzed for this report.
4. Economic Summary
Recovery and transportation of 79 percent (98 percent of 81 percent)
of the CO2 emitted by a coal-to-methanol plant of a design such as the one
of Figure 7-2, assuming the plant incorporates an acid gas removal unit
that does not regenerate with nitrogen, would require an additional capital
investment of about $200 million per plant. This would result in a net cost
of approximately $13 per ton of CO2 recovered. If the costs -were allocated
to the methanol instead, the methanol cost would rise $0.07 per gallon.7
If all of the modifications for CO2 recovery proposed in Sections 1-3
for the dedicated plant were implemented, the price of the recovered C02
(or, alternatively, the methanol cost) would not rise substantially more
than it would for recovery of 79 percent of the emitted C02. The total
increase in capital cost is estimated to be approximately $260 million. The
net operating cost of $100 million would result in a total cost of about $14
per ton of C02 recovered. If the costs were allocated to the methanol, a net
increase of about $0.09 per gallon would be seen in the production costs.
As noted in Appendix 7, if the recovered CO2 were sold to the oil
industry for use in enhanced oil recovery, and a byproduct credit of $1.18
per Mcf of C02 (the average selling price) was applied to the price of
methanol, the methanol price could be reduced by $0.10 per gallon if 79
percent of the CO2 emitted were recovered, or $0.13 per gallon if
essentially all of the CO2 emitted were recovered. Obviously, these credits
7As noted previously, some uncertainties exist regarding this analysis, hence these
costs should be viewed as estimates.
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would make either control option economically reasonable, since the
recovered C02 would more than cover the added capital investment,
provided the plant were located within 100 miles of a suitable EOR project.
If the distance between the plant and the disposal location increased,
capital costs would increase approximately 20 percent for every 100 miles,
leading to an increase of about SO.05 per gallon for each 100 miles of
additional pipeline.
5. Global Warming Impacts
Emissions of CO2 from a dedicated coal to methanol plant could be
greatly reduced if the options discussed above were used. Recovery of 79
percent of the emissions from a dedicated plant such as the design of
Figure 7-2 would result in a reduction from 13.3 lb. CO2 emitted per gallon
of methanol produced to 2.7 lb. CO2 emitted per gallon of methanol
produced. However, some of this would be offset by an increase in the
amount of electricity (or other power) needed to operate the CO2 removal
equipment. The plant is designed to produce 65 MW electricity for
internal use; none is imported. Recovery of 79 percent of the CO2 emitted
would require an additional 88 MW; this incremental electricity would add
to the global warming impact of methanol production from this source.
Based on data contained in a recent EPA report and assuming the
additional electricity is generated in a conventional coal fired plant, this
additional 88 MW electricity would increase emissions by 1.3 lb. CO2 per
gallon of methanol produced.[91 Therefore, total emissions would be 4.3 lb.
C02 per gallon of methanol. The net effect of recovering this C02, including
the added emissions from electricity, would be a decrease of 330 g CO2 per
mile from the emissions for a dedicated methanol vehicle shown in Table
7-8 (825 g/mile CO2 equivalent), a 40 percent reduction for the overall
fuel production and use cycle. Net C02-equivalent emissions would be 495
grams per mile, roughly 15 percent lower than those of a comparable
gasoline-fueled vehicle.
Recovery of essentially all (98 percent) of the CO2 emissions from a
dedicated plant would lower the emission rate to 0.3 lb. C02 emitted per
gallon of methanol produced. This process would require an additional 87
MW, which would add 1.6 lb. CO2 emitted per gallon of methanol produced
it came from a coal fired utility for a net emission rate of 1.9 lb. C02 per
gallon of methanol produced. This translates to a savings of 395 g CO2 per
mile for a dedicated methanol vehicle, which is an 87 percent reduction in
grams C02 emitted per mile for the plant, and a 50 percent reduction for
the overall fuel cycle. Using the recovery options presented above to
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recover essentially all the plant's emissions results in net C02-equivalent
emissions of 430 grams per mile (25 percent less than a gasoline vehicle).
B. Coproduction of Methanol and Electricity from Coal
Coproduction of methanol and electricity by an integrated
gasification combined-cycle/once-through methanol (IGCC/OTM) plant may
prove to be a reasonable means of methanol production from both
economic and global warming points of view. In spite of the slightly
higher capital investment for a coproduction plant compared to a dedicated
plant with the same feed capacity, this method is attractive because it can
satisfy a relatively small demand for methanol and at the same time
produce a high demand product, electricity, which would supplement the
price of the methanol.
Possible options to recover C02 from the coproduction of methanol
and electricity by plants such as the one in Figure 7-3 include:
1. Recovery from the acid gas unit (50 percent of C02 produced).
An essentially pure CO2 stream is removed from the acid gas
removal unit and routed to the heat recovery/steam
generation portion of the plant. This is the same stream that
is vented to the atmosphere in the dedicated methanol plant
design of Figure 7-2. Recovery of this CO2 instead of
sending it further along in the process would allow one half
of the total CO2 produced by the plant to be recovered at a
lower cost than if it were recovered downstream. If a larger
amount of carbon monoxide was shifted to CO2, increasing
the concentration of CO2 in the stream entering acid gas
removal, a much greater fraction of the total C02 emissions
from the plant could be recovered at this location.
2. Recovery from the sulfur plant tail gas (8 percent of CO2 emitted).
As was discussed for the dedicated plant, if the sulfur plant
were modified to use 02 instead of air, a relatively pure
stream containing CO2 and H2O would result. After
removing the H2O with "knock out" drums, the C02 could be
recovered without a need for absorption.
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3. Recovery from the boiler stack gas (42 percent of C02 emitted).
The remaining CO2 emitted by the plant results from
combustion of the fuel gas, which is high in H2 and CO, for
electricity generation. If this fuel gas were combusted in 02
(instead of air) and steam were used to cool the gas
turbines, the stack gas would contain CO2 and H2). Removal
of the H2O would yield an easily recoverable CO2 stream.
The details of each of these options, including the economics, will be
discussed in the following sections. Costs are presented on a dollar per ton
of C02 recovered. Since it may be desirable to allocate the costs to
products other than the C02 (for instance, to increase sales of CO2) these
costs are also presented. Electricity and methanol are both products of this
plant; the increased costs could be allocated to both the electricity rates
and the methanol costs. One way to allocate the recovery costs between
the methanol produced and the electricity generated is to divide the costs
on an energy equivalent basis. Because so much electricity is generated by
the plants, the methanol cost would not increase as much under this cost
allocation method as it would if the full cost of recovery were passed on to
the methanol production costs. This method of analysis was used in
evaluating the costs of recovery CO2 from a methanol/electricity
coproduction plant.
1. Recovery from the Acid Gas Removal Unit
As occurs in a dedicated methanol plant, the syngas in a coproduction
plant passes through an acid gas removal process before methanol
synthesis. The coproduction plant analyzed here (Figure 7-3) uses a
Selexol acid gas removal process instead of the Rectisol process described
earlier.[15] In this process, a solvent other than methanol is used to
absorb the acid gases from the syngas. Heat and steam, instead of
nitrogen, are used to regenerate and solvent. Unlike the case of the
dedicated plant, the gas streams are not contaminated by nitrogen. The
excess CO2, instead of being vented, is sent to the turbines for generation
of additional electricity (Stream 2 of Figure 7-3). Fifty percent of the CO2
produced in the plant is contained in this stream. Although this stream
contains 99 percent C02, the final concentration of the boiler stacks is
much lower because of the addition of other streams. One obvious way to
recover a significant amount of C02 from this electricity/methanol
coproduction plant without incurring high stripping costs would be to
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collect the C02 in this compressed stream instead of routing it further in
the plant.
The capital cost to compress this C02 and pipe it 100 miles is
estimated to be about $175 million.8'9 Operating costs would total
approximately $63 million per year. This would yield a net cost of about
$13 per ton of C02 recovered. If, as discussed above, the costs were
passed along to the electricity and the methanol instead, methanol
production costs would rise about $0.08 per gallon and electricity costs
would rise about $0,003 per kWh.
2. Recovery from the Sulfur Plant Tail Gas
As described for a dedicated methanol plant, the acid gas from a
methanol/electricity coproduction plant passes through sulfur removal
before being released to the atmosphere. Only 8 percent of the total CO2
released comes out from the sulfur recovery unit (Stream 3 in Figure 7-3).
This stream has a low concentration of CO2 because it gets diluted by air
introduced in the sulfur plant. If oxygen were used in the sulfur recovery
process instead of air, the resulting stream would contain only C02 and
H2O. The water could easily be removed, leaving pure C02- Making this
switch to oxygen would require approximately $7 million for the capital
investment to increase the capacity of the air separation plant. Operating
costs for this process would be about $2.4 million. The equipment to
remove the water from this stream would require an additional capital
investment of around $14,500; operating costs would be minimal.
If these changes are made to the oxygen and sulfur removal plants,
the capital cost to compress and dispose of the CO2 contained in the tail
gases would be about $20 million, assuming 98 percent overall collection
efficiencies.10 Operating costs would total over $9 million annually.
Combining the costs of enlarging the oxygen plant, removing the H2O, and
compressing and disposing of the CO2 would yield a cost of about $14 per
ton of C02 recovered. However, if the costs are allocated to the electricity
8These costs may actually be lower since the stream is already compressed higher
than the streams of Steinberg and Cheng's design, and hence, compression costs
could be reduced somewhat over those estimated for this analysis.
9 As discussing in the footnotes of Section A, these costs would increase about 20
percent for every 100 miles of additional pipeline needed.
^This assumes an incremental cost for compression and piping over the cost to
recover the CO2 from the acid gas removal unit.
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and methanol, option 2 would raise methanol costs $0.02 per gallon and
electricity costs about $0,001 per kWh.
3. Recovery from the Boiler Stack Gases
The C02 that is not removed in the acid gas removal unit has only a
small role in methanol synthesis; most of it is released to the atmosphere
after heat recovery (Stream 5 of Figure 7-3). An obvious way to recover
more CO2 from this plant at a relatively low cost would be to use the
existing acid gas removal system to remove as much carbon (in the form of
CO2) as possible. This could be accomplished by shifting all the CO that is
not needed for methanol production to CO2 and H2, then removing all the
CO2 in Stream 2. An analysis of the cost of shifting a larger volume of CO
and recovering the resulting CO2 was outside the scope of this study.
However, this option should be explored in greater detail if serious
consideration is given to minimizing emissions of C02 from a
methanol/electricity coproduction plant. For this report, it was assumed
that all of the C02 not removed by through acid gas removal is released in
the boiler stack gases.
The boiler stack gas (Stream 5) contains about 42 percent of all the
CO2 released (assuming the compressed CO2 stream noted on the Figure is
recovered at the acid gas removal unit, as discussed in Section 1). Since
this CO2 is highly diluted (the stream contains about 3 percent CO2),
recovery would require significant investment in recovery equipment.
One option for maximizing the recovery of CO2 from Stream 5 would be to
increase the concentration of CO2 in the stream by combusting the fuel gas
in oxygen instead of air. This would insure that almost pure CO2 and H2O
leave the boiler stacks, and, after condensing out the steam, recovery of
the C02 would be easy. The gas turbine could be cooled with steam
generated by the plant or recycled C02 instead of air to insure a pure C02
stream would result. The capital cost of this design probably would be
similar to that of the design using an air-cooled gas turbine.
Enlarging the oxygen plant to provide enough 02 for complete
combustion of the fuel gas is estimated to cost about $312 million.
Operating costs, assuming that the additional electricity required was
provided by increasing the amount generated by the plant, would be
approximately $80 million. The water removal equipment would cost
about $320,000. Recovery of the C02 in Stream 5 after H2O is removed
would require investment in compression equipment and piping totalling
about $85 million (incremental over the cost of recovering the C02 from
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the acid gas removal unit). Operating costs would be $40 million for this
equipment. Combining the costs for increased oxygen production, water
removal, and compression and piping would result in a cost of about $32
per ton of C02 recovered. Since this equipment does not affect methanol
production, these modifications would have no affect on the methanol cost
if costs were allocated to the other products of the plant; however, if the
costs were passed along to the electricity instead of the CO2, the cost would
rise less than $0.02 per kWh.
4. Economic Summary
The capital cost to recover 50 percent of the CO2 (at an efficiency of
98 percent) emitted by a coproduction plant is estimated to be $175
million. The cost of the C02 would be approximately $13 per ton of C02
recovered. If these costs were allocated instead to the methanol and
electricity on an energy content basis, the cost of methanol would increase
S0.08 per gallon and the cost of electricity would increase less than $0.01
per kWh.
If all the CO2 recovery options discussed in Sections 1, 2 and 3 were
applied, the net result would be about a $600 million increase in capital
over the cost to construct the plant as originally designed. Operating costs
would increase $275 million annually. Recovery of this C02 would cost a
total of about $21 per ton of C02 recovered.
If the recovered CO2 were used for enhanced oil recovery, then
another way to allocate the costs would be to pass the entire recovery cost
along to the methanol, then take a credit for the recovered C02- In this
case, the cost to recover all the C02 from a methanol/electricity
coproduction plant would raise the methanol cost about $0.70 per gallon
However, the sale of the recovered CO2 for EOR would yield a credit ot
about $0.60 per gallon.11 The net increase in methanol cost would then be
$0.10 per gallon; this could prove to be attractive, depending on the
market price for the methanol.
4. Global Warming Impacts
From a global warming standpoint, coproduction is an ideal
alternative to existing methods of electricity generation if C02 is recovered
^Assuming a piping distance of 100 miles; greater distances would increase costs
decreasing the credit available from the sale of the CO2.
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rather than released to the atmosphere. Many new designs for power
plants incorporate coal gasification/combined cycle power generation, an
option that is attractive because it is more efficient than conventional
designs and because it would make removal of C02 relatively easy. In
spite of the attractive features of this technology, few utilities to date have
plans to use this technology when increasing capacity, and it appears
unlikely that coal gasification will make any significant contributions to the
nation's electric power capacity over the next twenty years.
If, however, some of the approximately 17 GW of coal-fired capacity
that is planned for construction by the year 2010 were
methanol/electricity coproduction plants employing C02 recovery, C02
emissions due to the power industry could be reduced by up to 3
percent. [14] 12»13 Use of the methanol which could be coproduced with this
electricity (up to 5 billion annual gallons) in place of gasoline would reduce
the C02 emissions due to the transportation industry by 2 percent.14
Obviously, these emissions reductions rely on the existence of markets that
can absorb the recovered CO2, such as an expanded EOR market, or other
feasible methods of disposal, as well as the construction of the
methanol/electricity coproduction plants. However, these estimates
provide an illustration of the potential global warming impact that
coproduction plants could have on both the electric power and the
transportation industries.
A coproduction plant releases approximately 53 lb. C02 per gallon
methanol produced (based on Figures 7-3). If essentially all the CO2
emitted during the production of methanol were recovered, the net
emission rate would be 8 lb. C02 per gallon methanol produced. This
estimate includes the increase in emissions which would result from the
increase in the amount of electricity required by the plant.
Recovery of most of the emissions from methanol produced from coal
in a methanol/electricity coproduction plant would reduce the vehicular
emissions by 310 grams C02 emitted per mile, based on a dedicated
12Obviously, this is a very optimistic estimate since gasification technology is
expected to have little market penetration into coai-based power generation in the
near future. However, it does provide an estimate of what could be accomplished
using this technology if it proves to be economically feasible.
13 Assuming recovery of 50 percent of the CO2 emissions from the plant.
14Currently, conventional design coal based utilities emit a total of 1.7 quadrillion
grams of CO2 per year and the transportation industry contributes an additional 1.3
quadrillion grams C02-[9]
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vehicle using-this methanol, assuming the C02 emission reduction costs
were allocated between the methanol and the electricity on an energy
basis. This reduction would result in net emissions of 445 grams CO2-
equivalent emissions per mile. Although the amount of electricity
available for sale would decrease, the increased demand would be a small
fraction of the total amount produced and hence would have no net effect
on the price of electricity from these plants.
C Production of Natural Gas from Coal
1. Recovery Options
The options to recover CO2 from a coal-to-(synthetic) natural gas
plant are very similar to those for a coal-to-methanol plant, since many
components of the plant designs are identical. The only major source of
CO2 emissions is the vent gas from the acid gas removal/sulfur recovery
process. The sulfur compounds and excess CO2 are removed before the gas
goes on to methanation and conversion to natural gas. This is the point at
which most of the C02 is released in the plant, so recovery of this CO2
simply requires compressing and transporting the C02 contained in this
stream.
2. Economics
The total capital cost to recover most of the CO2 emissions from a
coal-to-natural gas plant would be about $325 million. Total operating
costs would be approximately $120 million annually. Implementation of
this equipment would cost about $11 per ton of C02 recovered. If the costs
were allocated to the natural gas, the cost would be about $2.40 per million
Btu.
3. Global Warming Impacts
Recovery of the emissions from a coal-to-natural gas plant would
reduce C02 emissions by 505 grams per mile, based on a dedicated CNG
vehicle using this natural gas. Net emissions would then be 420 grams per
mile, down from 925 C02-equivalent grams per mile.
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References
1. Personal Communication with Chris Peterson, Peterson Associates,
July 23, 1990.
2. "C02 and HC Injection Lead EOR Production Increase," Guntis Montis,
Drilling/Production Editor, Oil & Gas Journal. April 23, 1990.
3. "Coal-Oxygen Process Provides C02 for Enhanced Recovery,"
Abraham, B.M., J.G. Asbury, E.P. Lynch, and A.P.S. Teotia, Argonne National
Laboratory, Oil & Gas Journal. March 15, 1982.
4. "Use of Mississippi C02 Reserves for Enhance Oil Recovery," Moring,
Jane A., and Rudy E. Rogers, prepared for presentation at 1990 AIChE
Spring National Meeting Symposium on EOR, January 1990.
5. "Feasibility and Economics of By-Product CO2 Supply for Enhanced Oil
Recovery, Final Report. Vol. 1: Technical Report," Anada, H., D. King, A.
Seskus, M. Fraser, and J. Sears, for the Department of Energy,
DOE/MC/08333--3-VOL.1, January, 1982.
6. "Design and Results of a Shallow, Light Oilfield-Wide Application of
C02 Huffn'Puff Process," Miller, B.J., Bretagne, SPE/DOE 20268, from
Proceedings of the SPE/DOE Seventh Symposium on Enhanced Oil Recovery.
April 22-25, 1990.
7. "Sewer Water: An Alternative Water Source For A CO2 EOR Project,"
Flanders, W.A., Transpetco Engineering, and N. Grahmann and G. Green,
Champion Chemical Co., SPE/DOE 20289, from Proceedings of the SPE/DOE
Seventh Symposium on Enhanced Oil Recovery. April 22-25, 1990.
8. "A Systems Study for the Removal, Recovery, and Disposal of Carbon
Dioxide from Fossil Fuel Power Plants in the U.S.," Steinberg, Meyer and
Hsing C. Cheng, Brookhaven National Laboratory, BNL35666, February
1985.
9. "Alternative Transportation Fuels and the Greenhouse Effect," Sprik,
Timothy L., and Debra W. Adler, Technical Report for U.S. EPA, March 1990
DRAFT.
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10. "Coal-to:Methanol: An Engineering Evaluation of Texaco Gasification
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7-B-20
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