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Summary
Growing worldwide energy demand, high commodity prices, high economic
growth in developing countries, and growing scientific evidence that atmospheric carbon
dioxide (CO2) is an important contributor to global climate change make it urgent to
increase energy supply and reduce worldwide greenhouse-gas emissions at the same time.
Achieving the first goal will require increasingly efficient energy production and use and
expanded development of alternative sources of energy supplies that have low
greenhouse-gas emissions. In the United States today, the transportation sector relies
almost exclusively on oil. Although domestic energy sources can supply all U.S.
electricity needs, the United States is unable by itself to satisfy transportation sector and
petrochemical industry demand for oil and so currently imports about 60 percent of the
petroleum used in the United States. Moreover, volatile crude-oil prices and recent
tightening of global supplies relative to demand, combined with fears that oil production
will peak in the next 10-20 years, have aggravated concerns over oil dependence. The
second goal is reduction of greenhouse-gas emissions from the transportation sector,
which accounts for one-third of the total emissions in the United States. Those two
objectives have motivated the search for new vehicle power trains and alternative
domestic sources of liquid fuels that can substantially lower greenhouse-gas emissions.
Coal and biomass are abundant in the United States and can be converted to
liquid fuels that can be combusted in existing and future vehicles with internal-
combustion and hybrid engines. Their abundance makes them attractive candidates to
provide non-oil-based liquid fuels for the U.S. transportation system. However, there are
important questions about their economic viability, carbon impact, and technology status.
Coal liquefaction is a potentially important source of alternative liquid transportation
fuels, but the technology is capital-intensive. More important, fuel from liquefaction
produces about twice as much greenhouse-gas emissions on a life-cycle basis1 as does
1
Life-cycle analysis yields an estimate of the emissions that will occur over the life cycle of the fuel. For
example, life-cycle estimates cover the period from the time when the resource for the fuel is obtained
(from the oil well in the case of petroleum-based gasoline, from the coal mine in the case of coal-to-liquid
fuel) to the time when the fuel is combusted. In the case of biomass, the life cycle starts with the growth of
biomass in the field and ends when the fuel is combusted. Greenhouse-gas emissions that result from
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petroleum-based gasoline if the process CO2 is vented to the atmosphere. Capture of the
process CO2 and its geologic storage in the subsurface, often referred to as carbon capture
and storage (CCS), will be required for producing coal-based liquid fuels in a carbon-
constrained world. Thus, the viability, costs, and safety of lifetime geologic CO2 storage
could be barriers to commercialization.
Biomass is a renewable resource and, if properly produced and converted, can
yield biofuels that have lower greenhouse-gas emissions than do petroleum-based
gasoline and diesel. Biomass production on already-cleared fertile land might compete
with food, feed, and fiber production. If ecosystems are cleared directly or indirectly to
produce biomass for biofuels, the resulting release of greenhouse gases from the cleared
lands could negate for decades to centuries any greenhouse-gas benefits of using biofuels.
Thus, there are questions about how much biomass could be used for fuel without
competing with food, feed, and fiber production to an important degree and without
having adverse environmental effects.
STUDY SCOPE AND APPROACH
As part of its America’s Energy Future (AEF) study (see Appendix A), the
National Research Council appointed the 16-member Panel on Alternative Liquid
Transportation Fuels to assess the potential for using coal and biomass to produce liquid
fuels in the United States; provide thorough and consistent analyses of technologies for
the production of alternative liquid transportation fuels; and prepare a report addressing
the potential for use of coal and biomass to substantially reduce U.S. dependence on
conventional crude oil and also reduce greenhouse-gas emissions in the transportation
sector. The full statement of task is given in Appendix B. Although the report is the
product of this independent panel, the results it presents will contribute to the larger AEF
study mentioned in Appendix A.
The panel focused on technologies for converting biomass and coal to alternative
liquid fuels that will be commercially deployable by 2020. Technologies that will be
deployable after 2020 were also evaluated but in less depth because they are associated
with greater uncertainty than are the more developed technologies. For the purpose of this
study, commercially deployable technologies are ones that have been scaled up from
research and development to pilot-plant scale and then to several commercial-size
demonstrations. Thus, the capital and operating costs of plants using commercially
deployable technologies have been optimized so that the technologies can compete with
other options. Commercial deployment of a technology—the rate at which it penetrates
the market—depends on market forces, capital and human resource availability,
competitive technologies, public policy, and other factors.
Because the choices for alternative liquid fuels are so many and so complex, the
panel was unable to assess every potential biomass or conversion technology in the time
available for this study. Instead, it focused on biomass supply and technologies that could
potentially be commercially deployable over the next 15 years, be cost-competitive with
petroleum fuels, and result in substantial reductions in U.S. oil consumption and
indirect land-use change, however, are not included in the estimates of life-cycle greenhouse-gas emissions
presented in this report.
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greenhouse-gas emissions. Other potential alternative fuels are reviewed at the end of the
report (Chapter 9).
This study was initiated at a time (November 2007) when the prices of fossil fuels
and other raw materials and the capital costs for infrastructure were rising rapidly. As the
study progressed, those prices reached a peak (for example, the crude-oil price reached
$147/bbl on July 11, 2008) and then began to fall steeply. Currently, there is continuing
uncertainty about some of the factors that will directly influence the rate of deployment
of technologies and the costs of new transportation-fuel supplies. The panel also
recognized early in its deliberations the extent of the considerable debate reported on coal
and biomass conversion technologies and biomass feedstock potential.
To decrease the uncertainty in its analysis and to ensure consistency among
models used for comparison, the panel—with input from the Princeton Environmental
Institute, the Massachusetts Institute of Technology, Purdue University, the University of
Minnesota, Iowa State University, and the Renewable Energy Assessment Project team
of the U.S. Department of Agriculture’s Agricultural Research Service—developed
methods for estimating the costs and greenhouse-gas impacts of supplying biomass,
biochemical conversion, thermochemical conversion, and the potential quantity of fuel
supply. Because of pervasive levels of uncertainty, however, the energy supply and cost
estimates provided in this report should be considered as important first-step assessments
rather than forecasts. The panel’s estimates of the total costs of fuel products—including
the feedstock, technical, engineering, construction, and production costs—were derived
on a consistent basis and on the basis of a single set of conditions.
U.S. public policies related to energy have been introduced over the years. The oil
crises of the 1970s sparked a number of energy-policy changes at the federal, state, and
local levels. Price controls and rationing were instituted nationally, along with a reduced
speed limit to save gasoline. The Energy Policy and Conservation Act of 1975 created the
Strategic Petroleum Reserve and mandated the doubling of fuel efficiency for
automobiles from 13 to 27.5 miles/gal according to the Corporate Average Fuel Economy
(CAFE) standards. Alternative fuels have been promoted in several other government
incentives and mandates, including the Synthetic Liquid Fuels Act of 1944, the Energy
Security Act of 1980 (which contained the U.S. Synthetic Fuels Corporation Act), the
Alternative Motor Fuels Act of 1988, the Energy Policy Act of 1992, the Energy Policy
Act of 2005, and the recent Energy Independence and Security Act of 2007 (which aims
to increase the use of renewable fuels to at least 36 billion gallons by 2022 and set a new
CAFE standard of 35 miles per gallon by 2020). In addition, the American Jobs Creation
Act of 2004 provided a tax credit of $0.51/gal of ethanol blended to companies that blend
gasoline and a tax credit of $0.50-$1.00/gal of biodiesel to biodiesel producers.
Even though many public policies have addressed transportation-energy supply
and use over the last 60 years and large amounts of public money have been spent, the
use of alternative transportation fuels in the U.S. market today is still proportionately
small. Many factors are involved in this low market penetration, such as generally low oil
prices, but the fact that many of the policies have not been durable and sustainable has
played an important role.
In its report, the panel identifies what it judged to be “aggressive but achievable”
deployment opportunities for alternative fuels. Over the course of its study, it became
clear to the panel that given the costs of alternative fuels and the volatility of fuel prices,
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significant deployment of alternative fuels in the market will probably require some
realignment of public policies and regulations and the implementation of other incentives,
such as substantial investment by both the public and the private sectors.
This summary includes some of the panel’s key findings and recommendations;
details of the panel’s assessment and additional findings and recommendations are
presented in subsequent chapters of the report. Quantities are expressed in standard units
that are commonly used in the United States, except that greenhouse-gas emissions are
expressed in tonnes of CO2 equivalent (CO2 eq), the common unit used by the
Intergovernmental Panel on Climate Change.
TECHNICAL READINESS FOR 2020 DEPLOYMENT
Biomass Supply
Responsible development of feedstocks for biofuels and expansion of biofuel use
in the transportation sector must be socially, economically, and environmentally
sustainable. The social, economic, and environmental effects of producing and using
domestic biofuels have been mixed. In 2007, the United States consumed about 6.8
billion gallons of ethanol, mostly made from corn grain, and 491 million gallons of
biodiesel, mostly made from soybean. The combined total of those two biofuels is less
than about 3 percent of the fuels consumed for U.S. transportation. Diverting corn,
soybean, or other food crops to biofuel production induces competition between food,
feed, and fuel. Producing corn-grain ethanol and soybean biodiesel involves substantial
use of fossil-fuel and other resources, and the improvements in greenhouse-gas emissions
compared with emissions associated with petroleum-based gasoline are small at best.
Thus, the panel judges that corn-grain ethanol and soybean biodiesel are intermediate
fuels in the transition from oil to cellulosic biofuels or other biomass-based liquid
hydrocarbon transportation fuels, such as biobutanol and algal biofuels. In contrast, liquid
biofuels made from lignocellulosic biomass can offer major improvements in
greenhouse-gas emission relative to that from petroleum-based fuels if the biomass
feedstock is a residual product of some forestry and farming operations or if it is grown
on marginal lands that are not used for food and feed production.
Lignocellulosic feedstocks can be derived from both forestry and farming
operations, including some production on marginal lands where commodity production
often results in increased environmental problems because of erosion, runoff, and nutrient
leaching. Therefore, the panel focused on the lignocellulosic resources available for
biofuel production and assessed the costs of different biomass feedstocks delivered to a
biorefinery for conversion. It considered societal needs, using recent analyses that have
examined tradeoffs between land use for biofuel production and land use for food, feed,
fiber, and ecosystem services. Corn stover, wheat and seed-grass straws, hay crops,
dedicated perennial grass crops, woody biomass, waste paper and paperboard, and
municipal solid waste are the biofuel feedstocks considered in this report.
The panel estimated the amount of cellulosic biomass that could be produced
sustainably in the United States and result in fuels with substantially lower greenhouse-
gas emissions than petroleum-based fuels. For the purpose of this study, the panel
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considers biomass to be produced in a sustainable manner (1) if croplands would not be
diverted for biofuels and land therefore would not be cleared elsewhere to grow crops
displaced by fuel crops and (2) if growing and harvesting of cellulosic biomass would
incur minimal or even reduce such adverse environmental effects as erosion, excessive
water use, and nutrient runoff. The panel estimated that about 400 million dry tons per
year of biomass can potentially be made available for production of liquid transportation
fuels with the technologies and management practices of 2008 (Table S-1). The
cellulosic-biomass supply could increase to about 550 million dry tons per year by 2020.
Key assumptions in the analysis are that 18 million acres of land currently enrolled in the
Conservation Reserve Program (CRP) would be used to grow perennial grasses or other
perennial crops for biofuel production and that the acreage would increase to 24 million
by 2020 as knowledge increases. Other key assumptions are that harvesting methods
would be developed for efficient collection of forestry or agricultural residues; that
improved management practices and harvesting technology would increase agricultural
crop yield; that yield increases could continue at the historical rates seen for corn, wheat,
and hay; and that all the cellulosic biomass estimated to be available for energy
production would be used for liquid fuels (this leads to an estimate of the potential
amount of fuels produced).
The panel presented a scenario in which 550 million dry tons of cellulosic
feedstock could be harvested or produced sustainably in 2020. That estimate is not a
prediction of what would be available for fuel production in 2020. The supply of biomass
could exceed the panel’s estimate if croplands are used more efficiently or if genetic
improvement of dedicated fuel crops exceeds the panel’s estimate. In contrast, the panel’s
estimate could be lower if producers decide not to harvest agricultural residues or not to
grow dedicated fuel crops on their CRP land.
TABLE S-1 Estimated Amount of Lignocellulosic Feedstock That Could Be Produced
for Biofuel in 2008 with Technologies Available in 2008 and 2020
Feedstock Type Millions of Tons
With Current With
Technologies Technologies
Available by 2020
Corn stover 076 112
Wheat and grass straw 015 018
Hay 015 018
a
Dedicated fuel crops 104 164
Woody biomass 110 124
Animal manure 006 012
Municipal solid waste 090 100
TOTAL 416 548
a
CRP land has not been used for dedicated fuel-crop production as of 2008. The panel
assumed that two-thirds of the CRP land would be used for dedicated fuel production as
an illustration.
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The panel also estimated the costs of biomass delivered to a conversion plant
(Table S-2). In that analysis, the price that the farmer or supplier would be willing to
accept was assumed to include (1) land rental cost and other forgone net returns from not
selling or not using the cellulosic material for feed or bedding and (2) all other costs
incurred in sustainably producing, harvesting, and storing the biomass and transporting it
to the processing plant. The willingness-to-accept price or feedstock price is the long-run
equilibrium price that would induce suppliers to deliver biomass to the processing plant.
Because an established market for cellulosic biomass does not exist, the panel’s analysis
relied on published estimates. However, the panel’s estimates are higher than those in
published reports because transportation and land rental costs are included.
TABLE S-2 Biomass Suppliers’ Willingness-to-Accept Prices in 2007 Dollars for 1 Dry
Ton of Delivered Cellulosic Material
Willingness-to-Accept Price (dollars per ton)
Biomass Estimated in 2008 Projected in 2020
Corn stover 110 086
Switchgrass 151 118
123 101
Miscanthus
Prairie grasses 127 101
Woody biomass 085 072
Wheat straw 070 055
The geographic distribution of biomass supply is also an important factor in the
potential for development of a biofuels industry in the United States. The panel estimated
the quantities of biomass that could, for example, be available within a 40-mile radius
(which is about a 50-mile driving distance) of a given fuel-conversion plant in the United
States (Figure S-1). An estimated 290 sites could supply 1,500-10,000 tons of biomass
per day (0.5 million-2.4 million dry tons per year) to conversion plants within a 40-mile
radius. The wide variation in the geographic distribution of the biomass potentially
available for processing at plants will affect processing-plant size and is a factor in the
potential to optimize each conversion plant to decrease costs and maximize
environmental benefits and supply in a given region. For example, increasing the distance
of delivery could result in larger conversion plants with economies of scale that could
lower fuel production costs.
To attain the panel’s projected sustainable biomass supply, incentives would
have to be provided to farmers and developers to use a systems approach for
comprehensively addressing biofuel feedstock production; soil, water, and air quality;
carbon sequestration; wildlife habitat; and rural development. The incentives would
encourage farmers, foresters, biomass aggregators, and those operating biorefineries to
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work together to enhance technology development and ensure that the best management
practices were used for different combinations of landscape and potential feedstock.
Finding S-1 (see finding 2-1 in Chapter 2)
An estimated annual supply of 400 million dry tons of cellulosic biomass could be
produced sustainably with technologies and management practices already
available in 2008. The amount of biomass deliverable to conversion facilities could
probably be increased to about 550 million dry tons by 2020. The panel judges that
this quantity of biomass can be produced from dedicated energy crops, agricultural and
forestry residues, and municipal solid wastes with minimal effects on U.S. food, feed, and
fiber production and minimal adverse environmental effects.
Finding S-2 (see finding 2-5 in Chapter 2)
Biomass availability could limit the size of a conversion facility and thereby
influence the cost of fuel products from any facility that uses biomass irrespective of
the conversion approach. Biomass is bulky and difficult to transport. The density of
biomass growth will vary considerably from region to region in the United States, and the
biomass supply available within 40 miles of a conversion plant will vary from less than
1,000 tons/day to 10,000 tons/day. Longer transportation distances could increase supply
but would increase transportation costs and could magnify other logistical issues.
Recommendation S-1 (see recommendation 2-3 in Chapter 2)
Technologies that increase the density of biomass in the field to decrease
transportation cost and logistical issues should be developed. The densification of
available biomass enabled by a technology such as field-scale pyrolysis could facilitate
transportation of biomass to larger-scale regional conversion facilities.
Finding S-3 (see finding 2-2 in Chapter 2)
Improvements in agricultural practices and in plant species and cultivars will be
required to increase the sustainable production of cellulosic biomass and to achieve
the full potential of biomass-based fuels. A sustained research and development (R&D)
effort in increasing productivity, improving stress tolerance, managing diseases and
weeds, and improving the efficiency of nutrient use will help to improve biomass yields.
Recommendation S-2 (see recommendation 2-1)
The federal government should support focused research and development
programs to provide the technical bases for improving agricultural practices and
biomass growth to achieve the desired increase in sustainable production of
cellulosic biomass. Focused attention should be directed toward plant breeding,
agronomy, ecology, weed and pest science, disease management, hydrology, soil physics,
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agricultural engineering, economics, regional planning, field-to-wheel biofuel systems
analysis, and related public policy.
Finding S-4 (see finding 2-3 in Chapter 2)
Incentives and best agricultural practices will probably be needed to encourage
sustainable production of biomass for production of biofuels. Producers need to grow
biofuel feedstocks on degraded agricultural land to avoid direct and indirect competition
with the food supply and also need to minimize land-use practices that result in
substantial net greenhouse-gas emissions. For example, continuation of CRP payments
for CRP lands when they are used to produce perennial grass and wood crops for biomass
feedstock in an environmentally sustainable manner might be an incentive.
Recommendation S-3 (see recommendation 2-2 in Chapter 2)
A framework should be developed to assess the effects of cellulosic-feedstock
production on various environmental characteristics and natural resources. Such an
assessment framework should be developed with input from agronomists, ecologists, soil
scientists, environmental scientists, and producers and should include, at a minimum,
effects on greenhouse-gas emissions and on water and soil resources. The framework
would provide guidance to farmers on sustainable production of cellulosic feedstock and
contribute to improvements in energy security and in the environmental sustainability of
agriculture.
Coal Supply
Deployment of coal-to-liquids technologies would require the use of large
quantities of coal and thus an expansion of the coal-mining industry. For example, a
50,000-barrels/day (50,000-bpd) plant will use about 7 million tons of coal per year, and
100 such plants producing liquid transportation fuels at 5 million bpd would use about
700 million tons of coal per year, which would mean a 70 percent increase in coal
consumption. That would require major increases in coal-mining and transportation
infrastructure for moving coal to the plants and moving fuel from the plants to the
market. Those issues could represent major challenges, but they could be overcome. A
key question is the availability of sufficient coal in the United States to support such
increased use while supporting the coal-based power industry. A National Research
Council evaluation of domestic coal resources concluded that
federal policy makers require accurate and complete estimates of national coal
reserves to formulate coherent national energy policies. Despite significant
uncertainties in existing reserve estimates, it is clear that there is sufficient coal at
current rates of production to meet anticipated needs through 2030. Further into
the future, there is probably sufficient coal to meet the nation’s needs for more
than 100 years at current rates of consumption. . . . A combination of increased
rates of production with more detailed reserve analyses that take into account
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location, quality, recoverability, and transportation issues may substantially
reduce the number of years of supply. Future policy will continue to be developed
in the absence of accurate estimates until more detailed reserve analyses—which
take into account the full suite of geographical, geological, economic, legal, and
environmental characteristics—are completed.2
Recently, the Energy Information Administration estimated the proven U.S. coal
reserves to be about 270-275 billion tons. A key conclusion was that there are sufficient
coal reserves in the United States to meet the nation’s needs for over 100 years at current
rates of consumption, and possibly even with increased rates of consumption. The
primary issue probably is not the reserves but increased mining of coal and the opening
of many new mines. Increased mining has numerous environmental effects that will need
to be dealt with, and there will probably be public opposition to it. Increasing use of coal
will undoubtedly increase the cost of coal, which is low relative to the cost of biomass.
Finding S-5 (see finding 4-1 in Chapter 4)
Despite the vast coal resource in the Unites States, it is not a foregone conclusion
that adequate coal will be mined and be available to meet the needs of a growing
coal-to-fuels industry and the needs of the power industry.
Recommendation S-4 (see recommendation 4-1 in Chapter 4)
The U.S. coal industry, the U.S. Environmental Protection Agency, the U.S.
Department of Energy, and the U.S. Department of Transportation should assess
the potential for a rapid expansion of the U.S. coal-supply industry and delineate the
critical barriers to growth, environmental effects, and their effects on coal cost. The
analysis should include several scenarios, one of which assumes that the United States
will move rapidly toward increasing use of coal-based liquid fuels for transportation to
improve energy security. An improved understanding of the immediate and long-term
environmental effects of increased mining, transportation, and use of coal would be an
important goal of the analysis.
Conversion Technologies
Two key technologies, biochemical and indirect thermochemical conversion, that
are required for the conversion of biomass and coal to fuels are illustrated in Figure S-2
Biochemical conversion typically uses enzymes to transform starch (from grains) or
lignocelluloses into sugars as intermediates (saccharification), and the sugars are
converted to ethanol by microorganisms (fermentation). Indirect thermochemical
conversion uses heat and steam to convert biomass or coal into primarily a mixture of
carbon monoxide (CO) and hydrogen (H2)—syngas—which can be cleaned and
converted to have the right CO:H2 ratio (now referred to as synthesis gas) and then be
2
NRC. 2007. Coal: Research and Development to Support National Energy Policy. Washington, D.C.: The
National Academies Press, p. 4.
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catalytically converted to liquid fuels, such as diesel and gasoline. The CO2 from the
fermentation process in biochemical conversion or from the off-gas streams of the
thermochemical processes can be captured and stored geologically. Direct liquefaction of
coal, which involves adding H2 directly to slurried coal at high temperatures and
pressures in the presence of suitable catalysts, represents another route from coal to liquid
fuels but is less developed than indirect liquefaction. That route is not shown.
Biochemical Conversion
Biochemical conversion of starch from grains to ethanol (as shown on the left side
of Figure S-2) has been deployed commercially. Grain-based ethanol, although important
for initiating public awareness and industrial infrastructure for fuel ethanol, is considered
by the panel to be a transition to cellulosic ethanol and other advanced cellulosic biofuels.
The biomass supplies likely to be available by 2020 technically could be converted to
ethanol by biochemical conversion, displace a substantial fraction of petroleum-based
gasoline, and reduce greenhouse-gas emissions, but the conversion technology has to be
demonstrated first and be developed to a commercially deployable state.
Cellulosic ethanol could be the main biochemical route of converting biomass to
fuels over the next decade or two. Further R&D could lead to commercial technologies
that convert sugars to such other biofuels as butanol and alkanes, which have higher
energy densities and could be distributed in the existing infrastructure. Although the
panel focused on cellulosic ethanol as the most deployable technology for the next 10
years, it sees a long-term transition to cellulosic conversion to higher alcohols or
hydrocarbons—so-called advanced biofuels—as having important long-term potential.
The challenge in biochemical conversion of biomass to fuels is first to break
down the recalcitrant structure of the plant cell wall and then to break down the cellulose
to five-carbon and six-carbon sugars that can be fermented by microorganisms. The
effectiveness of this sugar generation is important for economical biofuel production. The
process of production of cellulosic ethanol includes (Figure S-2) preparation of feedstock
to achieve size reduction by grinding or other means; pretreatment of feedstock with
steam, hot water, or acid or base to release cellulose from the lignin shield;
saccharification—cellulase to hydrolyze cellulose polymers to cellobiose (a disaccharide)
and glucose (a monosaccharide) and hemicellulase to break down hemicellulose to
monosaccharides; fermentation of the sugars to ethanol; and distillation to separate the
ethanol. The CO2 generated in the conversion process and in combustion of the fuel is
mostly offset by the CO2 taken up during the growth of the biomass. The unconverted
materials are burned in a boiler to generate steam for the distillation; some excess
electricity can thus be generated.
As of 2008, no commercial-scale cellulosic ethanol plants were operational.
However, the Department of Energy announced in February 2008 that it would invest up
to $385 million for six biorefinery projects (two based on gasification) over 4 years to
move cellulosic ethanol to the market. When they are fully operational, the total
production of the six plants would be 8,000 bpd. In addition, a number of private
companies are actively pursuing commercialization of cellulosic-ethanol plants.
Technologies for cellulosic ethanol will continue to evolve over the next 5-10 years as
challenges are overcome and experience is gained in the first technology-demonstration
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and commercial-demonstration plants. The panel expects deployable, commercialized
technology to be in place by 2020 if technology-demonstration plants continue to be built
despite the current economic crisis and are rapidly followed by commercial-
demonstration plants. Because of lack of commercial experience, the cost of initial
commercial plants could well be higher than estimated by the modeling but decrease as
commercial experience is gained.
An expanded transport and distribution infrastructure will be required to replace
gasoline with a larger proportion of ethanol produced by biochemical conversion because
ethanol cannot be transported in pipelines used for petroleum transport. Ethanol is
currently transported by rail or barges and not by pipelines, because it is hydroscopic and
can damage seals, gaskets, and other equipment and induce stress-corrosion cracking in
high-stress areas. Gasoline vehicles can tolerate gasoline blends with up to 20 percent
ethanol. If ethanol is to be used in a fuel at concentrations higher than 20 percent (for
example, E85, which is a blend of 85 percent ethanol and 15 percent gasoline), the
number of refueling stations will have to be increased to support alternative-fuel vehicles
designed for alcohol fuels. The transport and distribution of synthetic diesel and gasoline
produced with thermochemical conversion do not pose the same challenge because they
are compatible with the existing infrastructure for petroleum-based fuels.
The key process-related challenges in R&D and demonstration that need to be
addressed before widespread commercialization are as follows: to improve the
effectiveness of pretreatment to remove and hydrolyze the hemicellulose, separate the
cellulose from the lignin, and loosen the cellulose structure; to reduce the production cost
of the enzymes for converting cellulose to sugars; to reduce operating costs by
developing more effective enzymes and more efficient microorganisms for converting the
sugar products of biomass deconstruction to biofuels; to demonstrate the biochemical-
conversion technology on a commercial scale; and to begin to optimize capital costs and
operating costs. The size of a biorefinery will probably be limited by the supply of
biomass available from the surrounding regions. That size limitation could result in loss
of potential economies of scale that characterize large plants.
Finding S-6 (see finding 3-2 in Chapter 3)
Process improvements in cellulosic-ethanol technology are expected to be able to
reduce the plant-related costs associated with ethanol production by up to 40
percent over the next 25 years. Over the next decade, process improvements and cost
reductions are expected to come from evolutionary developments in technology, from
learning gained through commercial experience and increases in scale of operation, and
from research and engineering in advanced chemical and biochemical catalysts that will
enable their deployment on a large scale.
Recommendation S-5 (see recommendation 3-2 in Chapter 3)
The federal government should continue to support research and development to
advance cellulosic-ethanol technologies. R&D programs should be pursued to resolve
the major technical challenges facing ethanol production from cellulosic biomasss:
pretreatment, enzymes, tolerance to toxic compounds and products, solids loading,
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emission from corn-grain ethanol is slightly lower than that from gasoline. In contrast,
CO2 emission from cellulosic ethanol without CCS is close to zero.
Figure S-6 shows that a CO2 price of $50/tonne significantly increase the costs of
the fossil-fuel options, including the costs of petroleum-based gasoline. The carbon price
brings the cost of biochemical-conversion options down to around $104/bbl (crude price,
about $90/bbl).The large amount of CO2 vented in the CTL process without CO2 storage
almost doubles the cost of product once the carbon price of $50/tonne of CO2 is imposed.
Inclusion of a carbon price does not increase the total costs of all pathways. For
example, although thermochemical conversion of biomass costs about $140/bbl of
gasoline equivalent without CCS, the produced fuels become competitive with
petroleum-based fuels at $115/bbl of gasoline equivalent with the carbon price and CCS.
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 by that pathway. Those estimates are all based on costs of small gasification
units operating at a feed rate of 4000 tpd. Each of those units is capital-intensive.
Therefore, larger units can be expected to be deployed in regions where potential biomass
availability is large—for example, 10,000 tpd. Such units could result in much lower
costs.
TABLE S-3 Estimated Costs of Various Fuel Products with and without a CO2
Equivalent Price of $50/tonnea
Fuel Product Cost without CO2 Cost with CO2 Equivalent
Equivalent Price ($/bbl Price of $50/tonne
gasoline equivalent) ($/bbl gasoline equivalent)
Gasoline at crude-oil price 075 095
of $60/bbl
Gasoline at crude-oil price 115 135
of $100/bbl
Cellulosic ethanol 115 105
BTL without CCS 140 130
BTL with CCS 150 115
CTL without CCS 065 110
CTL with CCS 070 090
CBTL without CCS 095 120
CBTL with CCS 110 100
a
Numbers are rounded to nearest $5. Estimated costs of fuel products for coal-to-liquids
conversion represent the mean costs of fuels produced via Fischer-Tropsch and MTG.
Costs and Supply
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As noted previously, the cost estimates for biochemical conversion and
thermochemical conversion are based on one generic biomass source. Figures S-4 and S-
6 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 S-3
for all biomass feedstocks has been combined with the conversion cost estimates. (The
potential supply of gasoline and diesel from CTL technology is discussed below in the
section “Deployment of Alternative Liquid Transportation Fuels.”) The results are shown
in Figures S-7 and S-8. Figure S-7 shows the potential gasoline-equivalent supply of
ethanol from bioconversion of lignocellulosic biomass and corn grain with 2020-
deployable technology. The supply of grain ethanol satisfies the current legislative
requirement to produce 15 billion gallons of ethanol in 2022. That figure shows potential
supply, not the panel’s projected penetration of cellulosic ethanol in 2020; it does not
incorporate lags in implementation of the technology that result from the need to permit
and build the infrastructure to produce and transport the alternative liquid fuels. The
estimated supply of synthetic gasoline and diesel (G/D) derived from coal and biomass is
shown in Figure S-8. Two supply functions are shown: one with CCS and the other
without CCS. The comparison shows that if the CCS technologies are viable and a CO2
eq price of $50/tonne is implemented, for each feedstock it will be less expensive to use
CCS than to release the CO2 into the atmosphere.
Either of the production processes underlying Figures S-7 and S-8 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 S-7 would be potentially applicable. If all production is based on thermochemical
conversion cofed with biomass and coal, Figure S-8 would be potentially applicable.
Most likely, some of the production would be based on cellulosic processes and some on
thermochemical processes, so the potential supply function would lie between the two
supply functions shown. If corn-grain ethanol has not been phased out by then, it would
add about 0.67 million barrels/day of gasoline-equivalent production to the supply.
To put the results in perspective, the 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 (1 bbl of crude oil produces about 0.85 bbl of gasoline equivalent). Total oil used in
the United States in 2008 was 20 million barrels/day, of which 14 million was used for
transportation and 12 million was imported. Thus, 2 million barrels of gasoline-
equivalent ethanol produced from cellulosic biomass and the 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.
The potential supply of gasoline or diesel fuel from thermochemical CBTL with
CCS is greater than that from biochemical or thermochemical conversion of cellulosic
biomass. The costs of thermochemical CBTL are lower than those of either biochemical
or thermochemical conversion of biomass. The cost difference occurs because coal is a
lower-cost feedstock than biomass. In addition, cofeeding coal and biomass allows a
larger plant to be built and reduces capital costs per unit volume of product. Thus, the
combination of coal with biomass allows a larger amount of alternative fuels to be
produced than would be possible with biomass alone because the quantity of biomass
limits overall production. The addition of coal increases the total amount of liquids that
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could be produced from a fixed quantity of biomass. Using coal and biomass at 60 and 40
percent, respectively, on an energy basis, almost 4 million barrels per day of gasoline
equivalent can potentially be displaced from transportation (60 billion gallons of gasoline
equivalent per year or 40 percent of gasoline and diesel used by light-duty vehicles in
2008). That assumes that all of the 550 million dry tons of cellulosic biomass sustainably
grown for fuel will be used for CBTL fuel production, so the estimates represent the
maximum potential supply.
Finding S-15 (see finding 6-1 in Chapter 6)
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
technically be 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.
DEPLOYMENT OF ALTERNATIVE LIQUID TRANSPORTATION FUELS
The discussion above has focused on the potential supply of alternative fuels from
technologies ready to be deployed commercially by 2020, but the potential supply does
not translate to the alternative supply that could be available by 2020. Apart from
technological readiness, the penetration rates of alternative liquid fuels into the market
will depend on many factors, including oil price, carbon taxes, construction environment,
and labor availability. The panel developed a few plausible scenarios to illustrate the lag
between when technology becomes commercially deployable, and substantial market
penetration.
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Deployment of Cellulosic-Ethanol Plants
For biochemical conversion to cellulosic ethanol, the panel developed two
scenarios on the basis of the current activities of demonstration plants, the announced
commercial plants, the U.S. Department of Energy roadmap, and the rate of construction
of grain-ethanol plants. The two scenarios assume that the cellulosic-ethanol capacity by
2015 will be 1 billion gallons per year, resulting from overall commercial development
and demonstration activities, and that capacity-building beyond 2015 tracks one of two
scenarios based on the capacity-building experienced by grain ethanol. One scenario
assumes the maximum capacity-building experienced for grain ethanol (about a 25
percent yearly increase in capacity over a 6-year period); the second is a scenario of
aggressive capacity-building of about twice that achieved for grain ethanol. The two
scenarios project 7-12 billion gallons of cellulosic ethanol per year by 2020. Continued
aggressive capacity-building could achieve the Renewable Fuel Standard7 mandate
capacity of 16 billion gallons of cellulosic ethanol per year by 2022, but it would be a
stretch. Continued aggressive capacity-building could yield 30 billion gallons of
cellulosic ethanol per year by 2030 and up to 40 billion gallons per year by 2035,
consuming about 440 million dry tons of biomass per year and replacing 1.7 million
barrels of petroleum-based fuels per day.
Deployment of Alternative Liquid Fuels from Coal-to-Liquids Plants with Carbon
Capture and Storage
If commercial demonstrations of CTL with CCS are started immediately (as
discussed in Recommendations S-10 and S-12) and CCS is proved viable and safe by
2015, commercially viable plants could be starting up before 2020. The growth rate after
that could be about two or three plants per year. That would reduce dependence on
imported oil but would increase CO2 emission from transportation. At a buildout rate of
two plants per year, liquid fuel would be produced at 2 million barrels per day from 390
tons of coal per year by 2035 at a total cost of about $200 billion for all the plants built.
At a buildout rate of three plants per year, liquid fuels would be produced at 3 million
barrels per day from about 580 million tons of coal per year. The latter case would
replace about one-third of the current U.S. oil use in light-duty transportation and
increase U.S. coal production by 50 percent. At a buildout of three plants starting up per
year, five or six plants would be under construction at any time.
Deployment of Alternative Fuels from Coal-and-Biomass-to-Liquids Plants
For cofed biomass and coal plants, the technology is close to being developed,
and several commercial plants without CCS have started cofeeding biomass. However,
7
The Renewable Fuel Standard (RFS) was created by the 2005 U.S. Energy Policy, and the 2007 U.S.
Energy Independence Act (EISA) 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”. The 36 billion gallons
would include 16 billion gallons of cellulosic ethanol.
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gaining operational experience in the plants with CCS is critical; CCS will probably be
required, and plants are going through early commercialization to gain operating
experience and to reduce costs. Because coal-and-biomass plants are much smaller than
CTL plants (plant size, one-fifth the size of CTL plants, or fuel at 10,000 bpd) and
biomass feed rates are similar to those in cellulosic bioconversion plants, penetration
rates should follow the cellulosic-plant buildout more closely. But mostly likely, the coal-
and-biomass buildout will be much slower than the aggressive cellulosic-plant buildout
presented above because of issues of siting the plants near both biomass and coal
production and because plant design is more complex. The panel assumed that
penetration rates for the coal-and-biomass plants would be slightly less than the rate for
the cellulosic-ethanol buildout case that follows the experience of grain ethanol discussed
above (which has experienced a 25 percent growth rate). At a 20 percent growth rate until
2035 with 280 plants in place, 2.5 million barrels of gasoline equivalent would be
produced per day. That would consume about 300 million dry tons of biomass and about
250 million tons of coal per year—less than the projected biomass availability. Siting to
have access to both biomass and coal is probably the limiting factor for CBTL plants.
This analysis shows that the rates of capacity growth would have to exceed historical
rates considerably if 550 million dry tons of biomass per year is to be converted to liquid
fuels by 2035.
Finding S-16 (see finding 6-2 in Chapter 6)
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
replace up to 0.5 million barrels of gasoline equivalent per day by 2020 and 1.7
million barrels per day by 2035.
Finding S-17 (see finding 6-3 in Chapter 6)
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 S-18 (see finding 6-4 in Chapter 6)
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.
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Finding S-19 (see finding 7-2 in Chapter 7)
The deployment of alternative liquid transportation fuels aimed at diversifying the
energy portfolio, improving energy security, and reducing the environmental
footprint by 2035 would require aggressive large-scale demonstration in the next
few years and strategic planning to optimize the use of coal and biomass to produce
fuels and to integrate them into the transportation system. Given the magnitude of
U.S. liquid-fuel consumption (14 million barrels of crude oil per day in the transportation
sector) and the scale of current petroleum imports (of the petroleum used in the United
States is imported), a business-as-usual approach is insufficient to address the need to
find alternative liquid transportation fuels, particularly because development and
demonstration of technology, construction of plants, and implementation of infrastructure
require 10-20 years per cycle.
Recommendation S-13 (see recommendation 7-8 in Chapter 7)
The U.S. Department of Energy should partner with industry in the aggressive
development and demonstration of cellulosic-biofuel and thermochemical-
conversion technologies with carbon capture and storage to advance technology and
to address challenges identified in the commercial demonstration programs. The
current government and industry programs should be evaluated to determine their
adequacy to meet the commercialization timeline required to reduce U.S. oil use and CO2
emissions over the next decade.
Recommendation S-14 (see recommendation 6-1 in Chapter 6)
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.
Finding S-20 (see finding 7-1 in Chapter 7)
A potential optimal strategy for producing biofuels in the United States could be to
locate thermochemical conversion plants that use coal and biomass as a combined
feedstock in regions where biomass is abundant and locate biochemical-conversion
plants in regions where biomass is less concentrated. Thermochemical plants require
larger capital investment per barrel of product than bioconversion plants and thus benefit
to a greater extent from economies. This strategy could maximize the use of cellulosic
biomass and minimize the costs of fuel products.
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Recommendation S-15 (see recommendation 7-6 in Chapter 7)
The U.S. Department of Energy and the U.S. Department of Agriculture should
determine the spatial distribution of potential U.S. biomass supply to provide better
information on the potential size, location, and costs of conversion plants. The
information would allow determination of the optimal size of conversion plants for
particular locations in relation to the road network and the costs and greenhouse-gas
effects of feedstock transport. The information should also be combined with the logistics
of coal delivery to such plants to develop an optimal strategy for using U.S. biomass and
coal resources for producing sustainable biofuels.
ENVIRONMENTAL EFFECTS OTHER THAN GREENHOUSE-GAS
EMISSIONS
Biomass Supply
Although greenhouse-gas emissions have been the central focus of research
concerning the environmental effects of biomass production for liquid fuels, other key
effects must be considered. On the whole, lignocellulosic-biomass feedstocks present
distinct advantages over food-crop feedstocks with respect to water-use efficiency,
nutrient and sediment loading into waterways, enhancement of soil fertility, emissions of
criteria pollutants that affect air quality, and habitat for wildlife, pollinators, and species
that provide biocontrol services for crop production. But dedicated fuel crops have the
potential to become invasive, and many of the ideal traits of biomass crops have been
shown to contribute to invasiveness.
Biochemical Conversion
The biochemical conversion of cellulosic biomass to ethanol requires process
water for mixing with fermentation substrates and for cooling, heating, and making
reagents that are associated with hydrolysis and fermentation. The amount of water
required for processing biomass into ethanol or other biofuels is estimated to be 2-6
gallons per gallon of ethanol produced. The lower levels would be approached if a plant
were designed to recycle process water. The processing of cellulosics to ethanol will
result in a residual water stream that would need to undergo treatment. However, an
efficient process, by definition, will ferment most of the sugars to ethanol and leave only
small amounts of organic residue.
Air emissions resulting from bioprocessing include CO2, water vapor, and
possibly sulfur and nitrogen. Fermentation processes release CO2 as a result of microbial
metabolism. Water vapor is released particularly if the lignin coproduct is dried before
being shipped from the plant for use as boiler fuel at an off-site power-generation facility.
The sulfur and nitrogen content of fermentation residues would be expected to be low
unless chemicals are used in the pretreatment of the biomass materials. The chemicals
used in pretreatment can be recovered.
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Thermochemical Conversion
CTL plants can be configured to minimize their effects on the environment.
Clean-coal technologies have been developed for the electric-power industry but can be
used in CTL applications. CTL plants need to produce clean synthesis gas from coal by
using gasification and gas-cleaning technologies. As a result, concerns over emission of
criteria pollutants and toxicants—such as sulfur oxides, nitrogen oxides, particulates, and
mercury—would be minimal because CTL plants will use clean-coal technologies.
The sulfur compounds in coal are converted into elemental sulfur, which can be
sold as a byproduct. The ammonia in synthesis gas can be recovered and sold as fertilizer
or sent to waste-water treatment, where it is absorbed by bacteria. All the mercury,
arsenic, and other heavy metals in the syngas are adsorbed on activated charcoal. The
mineral matter (or ash) in the coal has been exposed to extremely high temperatures
during gasification and has become vitrified into slag; the slag is nonleachable and finds
use in cement or concrete for buildings, bridges, and roads. Nitrogen oxide emissions are
reduced to about 3 ppm by using existing conversion technologies.
Water use in thermochemical-conversion plants depends primarily on the water-use
approach used in designing the plants. For the conversion of coal and combined coal and
biomass to transportation fuels with all water streams recycled or reused, the major
consumptive uses of water are for cooling, producing hydrogen, and handling solids. If
water availability is unlimited because of access to rivers, conventional forced- or
natural-draft cooling towers would be used. In arid areas, air cooling would be used as
much as possible. Depending on the magnitude of air cooling, water consumption could
range from about 1 to 8 bbl/bbl of product. CTL plants will have environmental effects
associated with the mining of additional coal, as discussed in the National Research
Council reports Evolutionary and Revolutionary Technologies for Mining and Coal
Research and Development to Support National Energy Policy8.
BARRIERS TO DEPLOYMENT
The development of a biomass-supply industry for the production of cellulosic
biofuels faces substantial challenges. The technological and sociological issues are not
trivial, but they can be successfully overcome. They are as follows.
8
NRC. 2002. Evolutionary and Revolutionary Technologies for Mining. Washington, D.C.: The National
Academies Press.
NRC. 2007. Coal: Research and Development to Support National Energy Policy. Washington, D.C.: The
National Academies Press.
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Challenge 1
Issues related to cellulosic-feedstock production include
• Developing a systems approach through which farmers, biomass integrators, and
those operating biofuel-conversion facilities can develop a well-organized and
sustainable cellulosic-ethanol industry that will address multiple environmental concerns
(for example, biofuel; soil, water and air quality; carbon sequestration; wildlife habitat;
rural development; and rural infrastructure) without creating unintended consequences
through piecemeal development efforts.
• Determining the full greenhouse-gas life-cycle emissions of various biofuel crops.
• Certifying the greenhouse-gas benefits for different potential biofuel scenarios.
Those issues, although formidable, can be overcome by developing a systems approach
with multiple end points that collectively can provide a variety of credits or incentives
(for example, carbon sequestration, water quality, soil quality, wildlife habitat, rural
development) and thus contribute to a stronger U.S. agricultural industry. Failure to link
the various critical environmental, economic, and social needs and to address them as an
integrated system could reduce the availability of biomass for conversion to levels far
below the 550 million tons technically deployable by 2020.
Challenge 2
For thermochemical conversion of coal or combined coal and biomass to have any
substantial effect on U.S. reliance on crude oil and CO2 emissions in the next 20-30
years, CCS will have to be shown to be safe and economically and politically viable. The
capture of CO2 is proven, but commercial-scale demonstration plants are needed now to
both quantify and improve cost and performance. Separate large-scale programs will be
required to resolve storage and regulatory issues associated with geologic CO2 storage
approaching a scale of gigatonnes per year. In the analyses presented in this report, the
viability of CCS was assumed to be demonstrated by 2015 so that integrated CTL plants
could start up by 2020. In that scenario, the first coal or coal-and-biomass gasification
plant would not be in operation until 2020. That assumption is ambitious and will require
focused and aggressive government action to realize. Uncertainty about the regulatory
environment arising from concerns of the general public and policy-makers have the
potential to raise storage costs above the costs assumed in this study. Ultimate
requirements for selection, design, monitoring, carbon-accounting procedures, liability,
and associated regulatory frameworks have yet to be developed, so there is a potential for
unanticipated delay in initiating demonstration projects and, later, in licensing individual
commercial-scale projects. Large-scale demonstrations and establishment of procedures
for operation and long-term monitoring of CCS projects have to be pursued aggressively
in the next few years if thermochemical conversion of biomass and coal with CCS is to
be ready for commercial deployment by 2020.
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Challenge 3
Cellulosic ethanol is in the early stages of commercial development, and a few
commercial demonstration plants are expected to begin operations in the next several
years. Over the next decade, process improvements are expected to come from
evolutionary developments and learning gained through commercial experience and
increases in scale of operation. Incremental improvements in biochemical conversion
technologies can be expected to reduce nonfeedstock process costs by 25 percent by 2020
and 40 percent by 2035. It will take focused and sustained industry and government
action to achieve those cost reductions. The key technical barrier to achieving cost
reduction are
• More efficient pretreatment to free up celluloses and hemicelluloses and to enable
more efficient downstream conversion. Improved pretreatment is unlikely to reduce
product cost substantially because pretreatment cost is small relative to other costs.
• Better enzymes that are not subject to end-product inhibition to improve the
efficiency of the conversion process.
• Maximizing of solids loading in the reactors.
• Engineering organisms capable of fermenting the sugars in a toxic biomass
hydrolysate and producing high concentrations of the final toxic product biofuel;
improving microbial tolerance of toxicity is a key issue.
Challenge 4
If ethanol is to be used in large quantities in light-duty vehicles, an expanded
ethanol transportation and distribution infrastructure will be required. Ethanol cannot be
transported in pipelines used for petroleum transport. Ethanol is currently transported by
rail or barges and not by pipelines, because it is corrosive in the existing infrastructure
and can damage the seals, gaskets, and other equipment and induce stress-corrosion
cracking in high-stress areas. If ethanol is to be used in fuel at concentrations higher than
20 percent (for example, E85, which is a blend of 85 percent ethanol and 15 percent
gasoline), the number of refueling stations offering it will have to be increased. The
distribution challenges have to be addressed to enable widespread availability of ethanol
in the fuel system. However, if cellulosic biomass were dedicated to thermochemical
conversion with FT or MTG, the resulting fuels would be chemically equivalent to
conventional gasoline and diesel, and the infrastructure challenge associated with ethanol
would be minimized.
Challenge 5
The panel’s analyses provide a snapshot of the potential costs of liquid fuels
derived from biomass with biochemical or thermochemical conversion and from biomass
and coal with thermochemical conversion. Costs of fuels are dynamic and fluctuate as a
result of other externalities, such as the costs of feedstock, labor, and construction; the
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economic environment; and government policies. Given the wide variation in most
commodity prices, especially oil prices, investors will have to have confidence that such
policies as carbon caps, a carbon price, and tariffs on imported oil will ensure that
alternative liquid transportation fuels can compete with fuels derived from crude oil. The
price of carbon emissions or the existence of fuel standards that require specified
reductions in greenhouse-gas life-cycle emission will affect the economic choices.
OTHER TRANSPORTATION FUELS
Technologies for producing transportation fuels from natural gas are ready for
deployment by 2020. Compressed natural gas already fuels vehicles. Other liquid fuels
can be produced from syngas, including gas-to-liquid diesel, dimethyl ether, and
methanol. Only if large supplies of natural gas are available—for example, from natural-
gas hydrates—will the United States be likely to use natural gas as the feedstock for
transportation-fuel production.
Hydrogen has the potential to reduce U.S. CO2 emissions and oil use, as discussed
in two recent National Research Council reports, Transitions to Alternative
Transportation Technologies--A Focus on Hydrogen and The Hydrogen Economy:
Opportunities, Costs, Barriers, and R&D Needs9. Hydrogen fuel-cell vehicles can yield
large and sustained reductions in U.S. oil consumption and greenhouse-gas emissions, but
several decades will be needed to realize these potential long-term benefits.
9
NRC. 2008. Transitions to Alternative Transportation Technologies--A Focus on Hydrogen. Washington:
The National Academies Press.
NRC. 2004. The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs. Washington: The
National Academies Press.
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