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6
Comparison of Options and Market Penetration
Chapters 2, 3, and 4 provide estimates of costs of fuel products and life-cycle
carbon dioxide (CO2) emission from liquid transportation fuels produced from biomass,
coal, and coal and biomass via different conversion pathways.1 This chapter compares the
life-cycle costs, CO2 emission, and potential supply of the alternative fuel options by
analyzing the supply chain beginning with the biomass (Chapter 2) and coal feedstocks,
ending with conversion to alternative liquid fuels (Chapters 3 and 4), including carbon
balances. The result of the panel’s analysis is a potential supply curve related to
alternative liquid fuels that use biomass, coal, or combined coal and biomass as
feedstocks. However, the actual supply in 2020 could well be smaller than the potential
supply because there are important lags in decisions to construct new conversion plants
and in construction. In addition, some of the biomass supply that appears to be
economical might not be made available for conversion to alternative fuels because of
logistical, infrastructure, and agricultural-organization issues. The analysis shows how
the potential supply curve might change with alternative CO2 prices and alternative
capital costs. The comparisons in this chapter are based on a point in time estimate of
costs and the panel’s judgment of technological advancement in the next 10-15 years.
The conclusions are drawn from consistent comparisons among alternative liquid-fuel
options, but they are not predictions of what the fuel costs or market penetration would be
in 2020 or 2035 inasmuch as such factors as technological changes, policies that
encourage development of one option rather another, and market forces could alter the
conclusions.
1
This chapter assessed only CO2 emission because the panel was not able to determine changes in other
greenhouse gases throughout the life-cycle of fuel production. Changes in greenhouse gases other than CO2
are likely to be small or none.
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COMPARISON OF COSTS, GREENHOUSE-GAS EMISSIONS, AND
POTENTIAL FUEL SUPPLY
To examine the potential supply of liquid transportation fuels from nonpetroleum
sources, the panel developed estimates of the unit costs and quantities of various
cellulosic biomass sources that could be produced sustainably as discussed in Chapter 2.
The panel’s analysis was based on land that is not now used for growing foods although
the panel cannot ensure that none of that land will be used for food production in the
future. The estimates of biomass supply were combined with the amount of corn grain
that would probably be used to produce fuels to satisfy the current legislative requirement
to produce 15 billion gallons of ethanol per year. The panel’s analysis allowed it to
estimate a supply function for biomass that shows the quantities of cellulosic biomass
feedstocks that would potentially be available at the various unit costs. The panel
assumed that coal would not be limiting in that it would be available in sufficient
quantities at a constant unit cost if used with biomass in thermochemical conversion
processes. The panel developed quantitative comparative analyses of alternative
pathways to convert biomass, coal, or combinations of coal and biomass to liquid fuels
(either ethanol or synthetic diesel and gasoline). Pathways, in principle, could include any
combination of the various biomass feedstocks and coal and could include either
thermochemical or biochemical conversion processes.2 However, rather than treating all
possible combinations, the panel first examined the cost of and the CO2 emissions
associated with each of the various thermochemical and biochemical conversion
processes that would use one biomass feedstock and then examined the costs, supplies,
and CO2 emissions associated with one thermochemical conversion process and one
biochemical conversion process that would use each of the biomass feedstocks.
The first set of analyses compared the costs and greenhouse-gas emissions from
fuels produced by biochemical and thermochemical conversion. The panel recognizes
that the cost of fuel and the greenhouse-gas emissions from biofuels vary with feedstock.
Because the purpose of the first set of analyses was to compare biochemical and
thermochemical conversion, using one biomass feedstock in the analyses would better
illustrate the differences between the conversion processes. Miscanthus, a high-yield
perennial grass, was the biomass feedstock used for each conversion process (except
those using only coal) because its cost and chemical composition are about the medians
of the estimated costs and chemical composition of different cellulosic feedstocks. That
analysis allowed the panel to estimate unit costs of each of the thermochemical and
biochemical conversion processes on the assumption that Miscanthus was the biomass
feedstock used for each process.
For the second set of comparisons, the panel chose two generic conversion
processes—conversion of each of the lignocellulosic biomass feedstocks to produce
ethanol and thermochemical conversion of a combination of coal with each of the
lignocellulosic biomass feedstocks (in a coal:biomass ratio of 60:40 on an energy basis)
to produce synthetic diesel and gasoline. The estimated supply function for biomass
provided information about feedstock quantities and costs. That information was
combined with information about conversion costs to obtain supply functions for
2
The panel also included biochemical conversion of corn grain to ethanol but did not focus the quantitative
analysis on this process.
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alternative fuels produced via either thermochemical or biochemical conversion and the
assumed corn grain ethanol.
In its analyses, the panel made the following assumptions. Changes in the
assumptions would normally change the estimated potential supply function. And
because uncertainty is associated with each of the assumptions, the collection of
uncertainties translates to important uncertainties in the potential supply curve.
• All available land discussed in Chapter 2 will be made available for growing
biomass for liquid fuels; none will be used for stand-alone electricity production. This
assumption implies that renewable portfolio standards for electricity production will not
result in the use of biomass to satisfy the requirements for renewable supplies of
electricity.
• Prices of biomass correspond to the costs of producing the biomass, including the
opportunity cost of land. (See Chapter 2 for cost estimation.) All available biomass will
be priced at those costs. As in Chapter 4, a coal price of $42/ton was used.
• Conversion plants that use biomass as feedstock will have the capacity of using it
at about 4,000 dry tons per day, and all plants will run at 90 percent of capacity.
• Biochemical-conversion plants use 0.45-0.51 dry tons of biomass for each barrel
of ethanol produced, with variations among different feedstocks based on their chemical
compositions.
• Capital costs for all investment are based on a 7 percent pretax, no-subsidy real
discount rate. Possible variations in discount rate are ignored.
• Where specified, carbon capture and storage (CCS) will be used to dispose of CO2
permanently. The CCS costs represent estimates of engineering costs to implement CCS.
Although there is considerable uncertainty in CCS costs because of potential social, legal,
and political issues, these issues are not included in the analyses. Thus, the full cost of
CCS could be higher than used in the analyses and will not be known until CCS is
implemented on a commercial scale. (See Chapter 4 and Appendix K.)
• If a greenhouse-gas price is imposed, it applies to the entire life-cycle CO2 net
emission, including emission released in growing biomass, in the conversion processes,
and in the ultimate combustion of the liquid fuels, minus CO2 removed from the
atmosphere in growing the biomass.3 A process that removes more CO2 from the
atmosphere than it produces would receive a net payment for CO2.
• The panel cannot project the carbon price. When a carbon price is included, it is
assumed to be $50/tonne of CO2 in 2020 and in the years shortly thereafter. The actual
carbon price could be larger or smaller than that.
3
Emissions released in growing biomass included estimates of petroleum, natural gas, and fertilizer used for
growing, harvesting, and transporting the biomass. Increases in carbon in soil were subtracted. For waste,
there is no such reduction for growing biomass, because any such reductions would be independent of
whether waste was used as feedstock or permanently stored in landfill. Carbon emissions of the conversion
process included total carbon inputs—biomass, coal, and electricity—minus carbon remaining in the fuel.
For processes that generated electricity, electricity input was negative number that reduced the calculated
carbon release. This carbon credit for electricity generation was based on 0.61 tonne of CO2 per megawatt-
hour of electricity generated by the process. It was assumed that on combustion all carbon remaining in the
fuel would be released into the atmosphere as CO2.
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• To be consistent with the analysis in Chapter 2, these analyses assume that no
indirect greenhouse-gas emissions result from land-use changes in the growing and
harvesting of cellulosic biomass. All biomass volumes in Chapter 2 were estimated under
the constraint that they could be grown and harvested without creating indirect
greenhouse-gas emissions.
• Production of corn grain has indirect greenhouse-gas emissions, but the panel’s
cost analyses assume that a U.S. carbon price will not be imposed on such indirect
emissions.
• Electricity produced as a coproduct has a value of $80/MWh4 in the absence of
any price placed on greenhouse gases. If a greenhouse-gas price is imposed, the value of
coproduct electricity includes, in addition to $80/MWh, the cost of the CO2 emission for
electricity generation on the basis of the average of all U.S. electricity generation.
• The biomass and cofed coal and biomass conversion plants are sized for biomass
feed rates of about 4,000 dry tons per day.
• The high-yield perennial grass is Miscanthus at $101 per dry ton.
Chapter 2 discusses the projected costs and availability of the various biomass
feedstocks in 2020. The data from Chapter 2 have been combined to estimate a supply
function for biomass to show the quantities of biomass feedstocks available at the various
unit costs. That supply function is shown in Figure 6-1. As discussed in Chapter 2, the
unit costs of most of the feedstocks—straw, woody biomass, corn stover, Miscanthus,
native and mixed grasses, and switchgrass—are built up from estimates of the various
costs of growing and transporting them. The costs of two feedstocks—corn grain and
hay—are based on recent market prices. In particular, the panel assumed that by 2020 the
corn price will have dropped sharply from the 2008 high of $7.88/bushel to $3.17/bushel,
corresponding to $130 per dry ton, a price more consistent with historical prices. The
panel assumed that the price of dryland or field-run hay will be $110/ton, which is similar
to historical prices. Finally, the cost of using wastes is based on a rough estimate of the
costs of gathering, transporting, and storing municipal waste. Such costs can be expected
to be highly variable, but the panel assumed that gathering, transporting, and storing will
add up to $51 per dry ton.
The costs of producing alternative liquid fuels via the various pathways were
estimated on the basis of the costs of feedstocks, capital costs, operating costs, conversion
efficiencies, and the assumptions outlined above. Figure 6-2 shows the estimate of the
gasoline-equivalent5 cost of alternative liquid fuels, without a CO2 price, produced from
coal, biomass, or combined coal and biomass. As indicated above, liquid fuels would be
produced by using biochemical conversion of Miscanthus to ethanol (biochemical
ethanol) or by using thermochemical conversion via the Fischer-Tropsch process (FT) or
a methanol-to-gasoline process (MTG). For thermochemical conversion, FT and MTG
are shown both with and without CCS. As discussed in Chapter 4, the cost of CCS was
based on engineering estimates of expenses for transport, land purchase, permitting,
4
This is the value at bus bar. $80/MWh is the assumed wholesale price of electricity in 2020 in the absence
of any carbon prices. The panel did not estimate the feedback from changes in policy options on that
electricity price, other than the effects of including carbon prices.
5
Costs per barrel of ethanol are divided by 0.67 to put ethanol costs on an energy-equivalent basis with
gasoline. For Fischer Tropsch liquids, the conversion factor is 1.0.
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drilling, all required capital equipment, storing, capping wells, and monitoring for an
additional 50 years. The full cost of CCS could be higher as a result of uncertainty about
the regulatory environment of CO2 storage. The supply of ethanol produced from corn
grain is also included in the figure. For comparison, costs of gasoline are shown in Figure
6-2 for two different crude oil prices: $60 per barrel and $100 per barrel.
Figure 6-3 shows the net CO2 emission per gasoline-equivalent barrel produced
by various production pathways. Figure 6-4 shows the detailed flows of CO2 underlying
the net flows in Figure 6-3. The CO2 released on combustion is similar among the various
pathways, with ethanol releasing less CO2 on combustion than either gasoline or
synthetic diesel and gasoline. The large variation in net releases is the result of the large
variations in the CO2 taken from the atmosphere in growing biomass and the large
variations in the CO2 released into the atmosphere in the conversion process.
The results in Figure 6-2 show that FT and MTG coal-to-liquid (CTL) fuel
products with and without CCS are cost-competitive at crude prices below $70/bbl
(equivalent crude-oil price of about $55/bbl), but Figure 6-3 shows that without CCS the
process vents a large amount of CO2, almost twice that of petroleum gasoline on a life-
cycle basis. With CCS, the CO2 life-cycle emission is about the same as that of petroleum
gasoline. The biochemical conversion of biomass produces fuels that are more expensive
than CTL fuels because the conversion plants are smaller and the feedstock more
expensive: biomass costs 3-4 times as much as coal on an energy-equivalent basis.
Because of the lower capital cost of the biochemical-conversion plants, even the smaller
plant produces cellulosic ethanol competitively, at about $120/bbl of gasoline equivalent.
CO2 emission from the corn grain ethanol is slightly lower than that from gasoline. In
contrast, CO2 emission from cellulosic ethanol without CCS is close to zero.
The cost of liquid fuel from thermochemical conversion of biomass, with CO2
venting and without coal, is about $140 and is higher than that from biochemical
conversion. Most of the difference in cost results from the greater electricicity sales to the
grid in connection with the biochemical conversion process. Thermochemical conversion
of biomass has the potential of large negative net releases of CO2 with CCS; that is, the
process leads to a net removal of CO2 from the atmosphere. Particularly interesting is the
results from the relatively small (8,000 tons/day total feed) cofed coal and biomass plant
with CCS. The fuel costs are below $100/bbl of gasoline equivalent, and CO2
atmospheric releases from plants with CCS are negative. Those results point to the
importance of that option in the U.S. energy strategy.
The important influence of a carbon price on fuel price is shown in Figure 6-5 and
Table 6-1. The figure and table show that a $50/tonne CO2 price increases the costs of the
fossil-fuel options, including the costs of petroleum-based gasoline, substantially. The
carbon price brings the cost of biochemical-conversion options to $105/bbl of gasoline
equivalent. The large amount of CO2 vented in the CTL process almost doubles the cost
of product once the carbon price of $50/tonne of CO2 is imposed.
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TABLE 6-1 Comparison of Costs of Alternative Liquid Fuels Produced from Coal,
Biomass, or Coal and Biomass with and without a $50/tonne CO2 Price
Cost of Fuel ($/bbl of gasoline equivalent)
Thermochemical Thermochemical Biochemical
Conversion Without CCS Conversion With CCS Conversion
Without
CCS
Carbon Feedstock FT MTG FT MTG
Price
($/tonne of
CO2
equivalent)
00 Coal 068 059 074 067 117
00 Coal and 101 092 115 102 Not
biomass applicable
00 Biomass 138 Not 151 Not Not
estimated estimated applicable
00 Crude oil At crude-oil price of $60, cost of gasoline = $73/bbl
At crude-oil price of $100, cost of gasoline = $113 /bbl
50 Coal 121 104 095 088 104
50 Coal and 126 116 105 095 Not
biomass applicable
50 Biomass 132 Not 114 Not Not
estimated estimated applicable
50 Crude oil At crude-oil price of $60, cost of gasoline = $94/bbl
At crude-oil price of $100, cost of gasoline = $134 /bbl
Inclusion of a carbon price does not increase the total costs for all pathways
(Table 6-1). For example, thermochemical conversion of biomass costs about $140/bbl of
gasoline equivalent without CCS, but the produced fuels with the carbon price and CCS
are competitive with petroleum-based fuels in the range of $115/bbl of gasoline
equivalent (or a crude oil price of $100/bbl). In general, if any pathway takes more CO2
from the atmosphere than it releases in other parts of its life cycle, the inclusion of a
carbon price reduces the total cost of producing liquid fuel via that pathway.
In reading the graphs, it is important to note that Figures 6-5, 6-6, and 6-7 shows
the breakdown of all costs, including negative costs, such as credit from electricity
generation or from carbon uptake. The negative costs must be subtracted from the
positive costs to obtain the actual costs. For example, BTL/CCS cost is $152/bbl –
$38/bbl = $114/bbl.
Those estimates are all based on costs of small gasification units operating with a
feed rate of 4,000 dry tons per day. Each unit is capital-intensive. Therefore, larger units
can be expected to be deployed in regions where potential biomass availability is large—
for example, 10,000 dry tons per day. Such units could result in much lower costs.
The panel also conducted a sensitivity analysis to assess the effect of uncertainty
in capital costs on the cost of fuel products. A variation of a 30 percent increase to a 20
percent decrease in capital costs was evaluated. Results are shown in Figures 6-6 and 6-7.
The capital-cost variations affect fuel costs of the capital-intensive gasification processes
more than those of the biochemical conversion processes, but the variations do not have a
major effect on the costs of fuel products relative to each other, particularly in light of the
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wide swings in crude-oil price in 2008. Although it is not shown in the figures, another
less-developed concept is biochemical conversion with CCS. The panel made a rough
first-pass estimate of the cost reduction in bioconversion ($125/ bbl of gasoline
equivalent) and found that with a CO2 price of $50/tonne cost could be reduced
substantially through CCS. That cost, however, was not fully quantified.
As noted previously, the cost estimates for biochemical conversion and
thermochemical conversion are based on only one biomass feedstock, Miscanthus.
Figures 6-5 through 6-7 do not show how much fuel could be produced at the estimated
costs. To provide a complete supply function for alternative liquid fuels, the supply
function from Figure 6-1 for all biomass feedstocks has been combined with the
conversion cost estimates. The results are shown in Figures 6-8 through 6-10. Figure 6-8
shows the potential gasoline-equivalent supply of ethanol from biochemical conversion
of lignocellulosic biomass with 2020 deployable technology. It shows potential supply,
not the panel’s projected penetration of cellulosic ethanol in 2020, because it does not
incorporate lags in implementation of the technology that will result from the need to
permit and build the infrastructure to produce and transport the alternative fuels. Figure
6-9 shows the potential gasoline-equivalent supply of ethanol from biochemical
conversion of both lignocellulosic biomass and ethanol distilled from corn, again with
2020 deployable technology. The estimated supply of synthetic gasoline and diesel
derived from coal and biomass as feedstocks is shown in Figure 6-10. Two supply
functions are shown: one with CCS and the other without CCS. The comparison shows
that if the CCS technologies are viable and if a CO2 price of $50/tonne is implemented,
for each feedstock it will cost less to use CCS than to release the CO2 into the
atmosphere.
Either of the production processes underlying Figure 6-8 or 6-9 and Figure 6-10
would use the same supplies of biomass. Therefore, the quantities cannot be added. If all
the production (in addition to ethanol produced from corn grain) is based on cellulosic
conversion, Figure 6-8 would be potentially applicable. If all production is based on
thermochemical conversion, the quantities in Figure 6-10 would be potentially applicable.
Most likely, some production would be based on biochemical processes and some on
thermochemical processes, so the actual potential supply function would lie between the
supply functions of Figures 6-8 and 6-10. In addition, ethanol would be produced from
corn grain at roughly 0.67 million barrels per day of gasoline equivalent.
To put the results into perspective, light-duty vehicle gasoline and diesel use in
the United States in 2008 is estimated to be about 9 million barrels of oil equivalent per
day (EIA, 2008); 1 bbl of crude oil produces about 0.85 bbl of gasoline and diesel. Total
oil used in the United States was 20 million barrels per day, of which 14 million barrels
was used for transportation and 12 million barrels was imported (EIA, 2008). Thus, 2
million barrels of gasoline-equivalent ethanol produced from cellulosic biomass and 0.7
million barrels of gasoline-equivalent ethanol produced from corn grain have the
potential to replace about 30 percent of the petroleum-based fuel consumed in the United
States by light-duty vehicles or 20 percent of all transportation fuels. The difference
between current technology and 2020 technology shows the importance of reductions in
feedstock costs and increase in yield to achieving the supply target.
The potential supply of gasoline or diesel from thermochemical conversion of a
combination of coal and biomass (with CCS) is greater than that from biochemical
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conversion that uses only biomass. The thermochemical costs are similar to or smaller
than the biochemical conversion costs. The costs differ because coal costs less than
biomass. In addition, using a combination of coal and biomass allows a larger plant to be
built and reduces capital costs per volume of product.
The combination of coal and biomass allows more alternative fuel to be produced
than would be possible with biomass alone. The quantity of biomass limits the overall
production in either case. Thus, the addition of coal increases the total amount of liquids
that could be produced from a given quantity of biomass. Using the combination of coal
and biomass, oil potentially can be displaced from transportation at almost 4 million
barrels per day (40 percent of gasoline and diesel used by light-duty vehicles in 2008). As
noted above, this analysis assumes that all cellulosic biomass sustainably grown for fuel
will be used for liquid transportation fuel. See Box 6-1 for further discussion.
BOX 6-1
Preferential Use of Biomass—Power Generation or Liquid Transportation Fuels
A number of factors can be expected to influence the use of biomass to support U.S.
energy requirements. The major options are use of biomass to generate power and to produce
liquid transportation fuels. Biomass can be expected to be used for both options according to
policies that mandate a minimum requirement for renewable energy and fuels. Those include
minimum requirement for renewable power generation and coal power-plant permits that
mandate that a given percentage of biomass be fed with coal. Mandating minimum requirement
for renewable transportation fuels will drive the use of biomass to produce fuels. Other factors will
also be influential in determining the use of biomass.
First, the lack of feedstock options other than biomass for producing liquid transportation
fuels with reduced CO2 emission means that biomass will have to be a component. The use of
coal with CCS can provide liquid transportation fuels and move the United States away from
reliance on petroleum, but it does not reduce CO2 emission from the transportation sector. At its
best, it is neutral relative to conventional gasoline from the point of view of climate change. Power
generation has a number of options other than biomass that can provide electricity with reduced
CO2 emission. From a renewables point of view, there are wind and solar sources. Nuclear power
also has low CO2 emission. Furthermore, the use of coal with CCS can produce electricity with
marked reductions in CO2 emission—by, say, 80 or 90 percent—and in mercury and sulfur
emissions. Thus, power generation truly has options other than biomass to address greenhouse
gas and other environmental issues. That points to the use of biomass for liquid transportation
fuels as an essential component in any greenhouse-gas management program. In addition,
biomass for liquid transportation fuels provides diversity of supply and enhances energy security.
If biomass is to be used as a component in a CO2-management approach, it should be
used in a way that provides the lowest cost of CO2 reduction in terms of dollars per tonne of CO2
avoided. The avoided cost of CO2 is projected to be much lower when biomass is used to
produce liquid fuels than when it is used to produce power.
That leads to the conclusion that the use of biomass to produce liquid transportation fuels
has more societal advantages than its use to generate electricity because it is an effective route
to reducing CO2 emission from the transportation sector where few other options exist and it does
so at a much lower cost per tonne of CO2 avoided.
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MARKET PENETRATION
The discussion above has focused on biomass supply and fuel technology
deployable by 2020, but a potential supply of alternative liquid fuel does not translate to
the supply that would actually be available in 2020. The following section discusses
issues that might limit the rate of market penetration. For biochemical conversion, two
scenarios of potential biochemical penetration are presented. The actual penetration could
be slower or faster, depending on crude-oil price, expectations of future prices, federal
and state policy, the U.S. construction industry, and other variables.
Biochemical Conversion
Production of ethanol from grain is fully commercial. U.S. production capacity
grew from 0.28 million barrels per day at the end of 2004 to 0.38 million barrels per day
by the end of 2006 and to about 0.46 million barrels per day by the end of 2007. (Those
figures correspond to 4.3, 5.9, and about 7 billion gallons per year by the end of 2007.6)
The capacity-build rate of grain ethanol averaged 25 percent per year over a 6-
year period. At the maximum build-rate, 1-2 billion gallons of annual ethanol-production
capacity was added per year or an annual addition of 0.065-0.13 million barrels per day;
at an average plant size of 3,300 bbl of ethanol per day or 50 million gallons per year,
that means 20-40 plants/year at the maximum. Considering current plant construction that
was under way, ethanol-production capacity would have been about 0.5 million barrels
per day by the end of 2008. However, 12-15 billion gallons of grain ethanol per year (0.8-
1.0 million barrels per day) is probably the limit with respect to corn availability,
assuming that corn yields and acreage increase modestly.
Production of ethanol from cellulose has yet to be demonstrated on a commercial
scale, and there remain questions about the economic and commercial viability of the
technology. Within the next 3-5 years, five or six technology-demonstration plants (on a
noncommercial scale) are expected. The plants will provide valuable information on cost,
engineering design, technology robustness, and particularly commercial viability on the
scale required to warrant large-scale cellulosic-ethanol production. That information
should be available by 2012. The commercial and economic issues potentially will be
gradually resolved as cellulosic-ethanol production technology matures and development
of new strains of organisms and manufacturing methods reach commercial
implementation. As commercially proven technology for cellulosic-ethanol production
evolves in scale and efficiency, growth in cellulosic-ethanol production capacity could
approach or even exceed the growth experienced in grain ethanol. Cellulosic-ethanol
plants are similar to grain-ethanol plants but somewhat more complex; and because of the
dispersed nature of biomass, they might be comparable in size with to twice as large as
typical grain-ethanol plants. For the rest of this discussion, it is assumed that cellulosic
ethanol will be commercially demonstrated by 2012 and that it will be either
economically competitive with petroleum-based fuels or made competitive through the
use of subsidies or policy so that capacity will be built with private funds. The U.S.
6
In oil-equivalent figures, these rates—adjusted for energy content—correspond to 0.19, 0.26, and 0.31 oil-
equivalent barrels per day.
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Department of Energy roadmap for cellulosic ethanol proposes “to accelerate cellulosic
ethanol research, helping to make biofuels practical and cost-competitive by 2012.”
Here, cellulosic-ethanol plants with a collective capacity of 1 billion gallons per
year are assumed to be in operation by 2015 as a result of overall commercial
development and demonstration activities and that the capacity-build beyond 2015 will
track one of two scenarios based on the capacity-build experienced by grain ethanol (1-2
billion gallons of new capacity per year) (Figure 6-11). One scenario tracks the maximum
capacity-build experienced for grain ethanol, and the second scenario is more aggressive
and reaches about twice the capacity achieved for grain ethanol. The two scenarios
project 7-12 billion gallons of cellulosic ethanol per year by 2020 (0.5-0.8 million barrels
per day). Continued aggressive capacity-building could achieve the renewable fuel
standard (RFS) mandate capacity of 16 billion gallons of cellulosic ethanol per year by
2022, but it would be a stretch. The RFS was created by the 2005 U.S. Energy Policy
Act. However, the 2007 U.S. Energy Independence and Security Act amended the RFS to
set forth “a phase-in for renewable fuel volumes beginning with 9 billion gallons in 2008
and ending at 36 billion gallons in 2022” (0.6 and 2.4 million barrels per day,
respectively). If the more aggressive scenario plays out, capacity-building could yield
1.5-2 million barrels of cellulosic ethanol per day by 2030 and up to 2.6 million barrels
per day shortly thereafter, consuming about 440 million dry tons of biomass per year.
However, it should be stressed that whether the production capacity expands more
rapidly or less rapidly will depend heavily on economic incentives and policies and on
the actual and projected prices of crude oil.
Thermochemical Conversion
For coal plants, the gasification, FT, and MTG technologies are developed.
However, there is no experience with integrated plants that would use all the technologies
combined with CCS. To have CTL ready to supply fuels in the shortest time possible to
improve energy security, an immediate start on the design and construction of
commercial demonstration plants with CCS is critical. CO2 capture is built in to the FT
and MTG processes, but learning from demonstration-plant operations is critical for
decreasing cost and improving performance. CO2 storage will require adding compressors
to the plants and locating the demonstrations close to CO2 repositories (for example,
saline aquifers, geological formations, or sites of enhanced oil-recovery opportunities).
Experience from the demonstrations is also needed to resolve scientific and regulatory
issues to make CCS viable. If the demonstrations are started immediately and CCS is
proved viable and safe by 2015, economically viable commercial plants could be starting
up before 2020.
For thermochemical processing of biomass and cofed coal and biomass plants, a
timeline similar to that for CTL applies. CCS is not necessary for biomass-to-liquid fuel
plants to produce carbon-neutral fuels, and commercial demonstration can start
immediately if society places a high enough value on carbon-neutral fuels (fuels with
zero greenhouse-gas life-cycle emissions). Although CCS may not be required in coal-
and-biomass-to-liquid (CBTL) fuel plants if the proportion of biomass to coal is high in
the feedstock, such plants will have to deal with the problems of feeding biomass to
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gasifiers and locating the plants in a region that could supply sufficient biomass (about
3,500 dry tons of biomass per day) and have access to sufficient coal (about 3,000
tons/day as received). For CBTL plants, the technology is close to developed, and several
commercial demonstration plants are in operation or being built with and without CCS.
However, gaining operational experience in the plants with CCS is critical because cost
reductions will result from the experience. Because CTL fuel has twice the CO2 life-cycle
emission of gasoline unless it uses CCS, CCS will probably be required. Penetration rates
of the CBTL plants could be expected to be similar to or slightly less than that of the
cellulosic-ethanol build-out case that follows the experience of grain ethanol discussed
earlier. Penetration rates for biomass plants can be expected to be similar to that for the
cellulosic-ethanol case, but both plants depend heavily on the ability to reduce fuel-
production costs and on the presence of a substantial carbon policy. The biomass-
gasification penetration rate will depend heavily on getting the biomass supply up to
about a million dry tons per year per site or higher. Cellulosic ethanol could be applied on
a smaller scale of biomass availability.
To get some perspectives on capacity growth for CBTL and CTL plants, the panel
presents the following analysis. The capacity growth rates could be higher or lower,
depending on such factors as government policy, oil prices, carbon price, and the labor
and commodity markets.
Consider a CBTL plant integrated with CCS that uses about 40 percent biomass
and 60 percent coal on an energy basis. Such a plant produces liquid transportation fuels
that are essentially carbon-free and, to the extent that it produces electricity for the grid,
the electricity is also carbon-free. In the recycle case designed to maximize the liquid-
fuels production with CCS, the plant produces about 10,000 bbl of liquid hydrocarbon
transportation fuels per day. The size of the plant considered in this case is 3,500 dry tons
of biomass per day. The CBTL plant is more complex and its capital cost is substantially
higher on the basis of a barrel of fuel produced than is a biochemical-conversion plant of
comparable biomass feed capacity. When the difference is put on the basis of energy-
equivalent fuels, it is reduced but is still important. As mentioned above, the build-out of
grain ethanol for fuel capacity averaged 25 percent per year over a 6-year period and was
the basis of the estimation of the build-out rate of cellulosic ethanol at sites of 1.1 million
dry tons per year. The cellulosic-ethanol build-out had 225 plants producing 1.5 million
barrels of ethanol per day (1 million barrels of gasoline equivalent per day) in 2030 at a
total running sum cost of about $100 billion for the base case and 370 plants producing
2.4 million barrels per day (1.6 million barrels of gasoline equivalent per day) and
consuming about 440 million dry tons of biomass per year.
For CBTL plants, the panel used a slightly lower build-out rate of because of
issues of accessing sites with about 1.1 million dry tons of biomass per year and a similar
availability of coal. In this case, a total of 200 plants were in place by 2030 and
producing 2 million barrels of gasoline equivalent per day at a running sum cost of about
$260 billion. It was assumed that three plants were commissioned in 2015 and that
growth is expanded as capacity to build them increases; this largely follows the
cellulosic-ethanol projection to achieve the numbers summarized above. That would
consume about 220 million dry tons of biomass and about 200 million tons of coal per
year. If that growth rate could be continued to 2035, an estimated 2.5 million barrels of
gasoline-equivalent fuels could be, consuming less than the projected biomass
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availability, but siting plants to access both biomass and coal is probably the limiting
factor for CBTL plants. The analysis shows that the capacity growth rates would have to
exceed historical rates considerably if 550 million dry tons of biomass per year is to be
converted to liquid fuels in 2030.
For CTL plants with CCS, consider a plant build-out rate of two to three plants
per year each with 50,000-bbl/day capacity for 20 years starting in 2015 (when the first
plants are commissioned). This scenario would reduce dependence on imported oil, but it
would not reduce CO2 emission from transportation. At a build-out rate of two plants per
year, 2 million barrels of liquid fuels per day would be produced from 390 million tons of
coal per year by 2035 at a total cost of about $ 200 billion for all the plants built. At a
build-out rate of three plants per year, 3 million barrels of liquid fuels per day would be
produced from about 580 million tons of coal per year. The latter case would replace
about one-third of U.S. oil use in light-duty transportation and increase U.S. coal
production by 50 percent.
FINDINGS AND RECOMMENDATION
Finding 6-1
Alternative liquid transportation fuels from coal and biomass have the potential to
play an important role in helping the United States to address issues of energy
security, supply diversification, and greenhouse-gas emissions with technologies that
are commercially deployable by 2020.
• With CO2 emissions similar to those from petroleum-based fuels, a
substantial supply of alternative liquid transportation fuels can be produced with
thermochemical conversion of coal with geologic storage of CO2 at a gasoline-
equivalent cost of $70/bbl.
• With CO2 emissions substantially lower than those from petroleum-
based fuels, up to 2 million barrels per day of gasoline-equivalent fuel can be
technically produced with biochemical or thermochemical conversion of the
estimated 550 million dry tons of biomass available in 2020 at a gasoline-
equivalent cost of about $115-140/bbl. Up to 4 million barrels per day of gasoline-
equivalent fuel can be technically produced if the same amount of biomass is
combined with coal (60 percent coal and 40 percent biomass on an energy basis) at
a gasoline-equivalent cost of about $90-100/bbl. However, the technically feasible
supply does not equal the actual supply inasmuch as many factors influence the
market penetration of fuels.
Finding 6-2
If commercial demonstration of cellulosic-ethanol plants is successful and
commercial deployment begins in 2015 and if it is assumed that capacity will grow
by 50 percent each year, cellulosic ethanol with low CO2 life-cycle emissions can
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replace up to 0.5 million barrels of gasoline equivalent per day by 2020 and 1.7
million barrels per day by 2035.
Finding 6-3
If commercial demonstration of coal-and-biomass-to-liquid plants with carbon
capture and storage is successful and the first commercial plants start up in 2020
and if it is assumed that capacity will grow by 20 percent each year, coal-and-
biomass-to-liquid fuels with low CO2 life-cycle emissions can replace up to 2.5
million barrels of gasoline equivalent per day by 2035.
Finding 6-4
If commercial demonstration of coal-to-liquid plants with carbon capture and
storage is successful and the first commercial plants start up in 2020 and if it is
assumed that capacity will grow by two to three plants each year, coal-to-liquid fuels
with CO2 life-cycle emissions similar to those of petroleum-based fuels can replace
up to 3 million barrels of gasoline equivalent per day by 2035. That option would
require an increase in U.S. coal production by 50 percent.
Recommendation 6-1
Detailed scenarios of market penetration rates of biofuels, coal-to-liquid fuels, and
associated biomass and coal supply options should be developed to clarify hurdles
and challenges to achieving substantial effects on U.S. oil use and CO2 emissions.
The analysis will provide policy-makers and business leaders with the information
needed to establish enduring policies and investment plans for accelerating the
development and penetration of alternative-fuels technologies.
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REFERENCE
EIA, Energy Information Administration. 2008. Annual Energy Outlook 2008 with
Projections to 2030 Washington: U.S. Department of Energy.
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