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Summary G rowing worldwide energy demand, high commodity prices, high eco- nomic 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 world- wide greenhouse gas emissions at the same time. Achieving the first goal will require increasingly efficient energy production and use and expanded develop- ment of alternative sources of energy supplies that have low greenhouse gas emis- sions. 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 petro- chemical industry demand for oil and so currently imports about 56 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 inter- nal-combustion and hybrid engines. Their abundance makes them attractive can- didates to provide non-oil-based liquid fuels for the U.S. transportation system. However, there are important questions about their economic viability, carbon 

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 Liquid Transportation Fuels from Coal and Biomass 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 the amount of greenhouse gas emissions on a life-cycle basis1 as does 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 Transpor- tation Fuels to assess the potential for using coal and biomass to produce liquid fuels in the United States; provide thorough and consistent analyses of technolo- gies for the production of alternative liquid transportation fuels; and prepare a report addressing the potential for use of coal and biomass to substantially reduce 1Life-cycle analysis yields an estimate of the emissions that will occur over the life cycle of a 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 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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Summary  U.S. dependence on conventional crude oil and also reduce greenhouse gas emis- sions 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 pres- ents will contribute to the larger AEF study mentioned in Appendix A. The panel focused on technologies for converting biomass and coal to alter- native 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 technolo- gies. 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 tech- nologies 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 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 fos- sil fuels and other raw materials and the capital costs for infrastructure were ris- ing 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 Environ- mental Institute, the Massachusetts Institute of Technology, Purdue University, the University of Minnesota, Iowa State University, and the Renewable Energy Assess- ment Project team of the U.S. Department of Agriculture’s Agricultural Research

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0 Liquid Transportation Fuels from Coal and Biomass 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 nation- ally, 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/gal 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 sup- ply 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 achiev- able” 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 vola- tility of fuel prices, significant deployment of alternative fuels in the market will probably require some realignment of public policies and regulations and the

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Summary  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 recommenda- tions; details of the panel’s assessment and additional findings and recommenda- tions are presented in subsequent chapters of the report. Quantities are expressed in standard units that are commonly used in the United States, except that green- house gas emissions are expressed in tonnes of CO2 equivalent (CO2 eq), the com- mon 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 mil- lion 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. transpor- tation. Diverting corn, soybean, or other food crops to biofuel production induces competition among food, feed, and fuel. Producing corn-grain ethanol and soy- bean 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 emissions relative to those 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 pro- duction often results in increased environmental problems because of erosion, runoff, and nutrient leaching. Therefore, the panel focused on the lignocellulosic

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 Liquid Transportation Fuels from Coal and Biomass resources available for biofuel production and assessed the costs of different bio- mass 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, wastepaper 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 green- house gas emissions than petroleum-based fuels. For the purpose of this study, the panel 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 else- where to grow crops displaced by fuel crops and (2) if growing and harvesting of cellulosic biomass would incur minimal or even reduce adverse environmental effects such as erosion, excessive water use, and nutrient runoff. The panel esti- mated that about 400 million dry tons per year of biomass can potentially be made available for production of liquid transportation fuels with the technolo- gies 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 Conser- vation 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 harvest- ing 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.

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Summary  TABLE S.1 Estimated Amount of Lignocellulosic Feedstock That Could Be Produced for Biofuel in 2008 with Technologies Available in 2008 and 2020 Millions of Tons With Technologies With Technologies Feedstock Type Available in 2008 Available by 2020 Corn stover 076 112 Wheat and grass straw 015 018 Hay 015 018 104a Dedicated fuel crops 164 Woody biomass 110 124 Animal manure 006 012 Municipal solid waste 090 100 Total 416 548 aCRP land has not been used for dedicated fuel-crop production as of 2008. The panel assumed that two-thirds of the potentially suitable CRP land would be used for dedicated fuel production as an illustration. 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 will- ing 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 suppli- ers 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. 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

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 Liquid Transportation Fuels from Coal and Biomass 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 070 055 200 162 160 129 Number of Sites 120 82 80 40 17 0 800–2200 2200–4000 4000–7000 >7000 Biomass Availability Within 40-Mile Radius (Dry Tons per Day) FIGURE S.1 The number of sites in the United States with a potential to supply the indi- cated daily amounts of biomass within a 40-mile radius of each site. 3 R0120 Main Report 5-1

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Summary  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 qual- ity; carbon sequestration; wildlife habitat; and rural development. The incentives would encourage farmers, foresters, biomass aggregators, and those operating biorefineries to 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 mini- mal effects on U.S. food, feed, and fiber production and minimal adverse envi- ronmental effects. Finding S.2 (see Finding 2.5 in Chapter 2) Biomass availability could limit the size of a conversion facility and thereby influ- ence 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.

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 Liquid Transportation Fuels from Coal and Biomass Recommendation S.1 (see Recommendation 2.3 in Chapter 2) Technologies that increase the density of biomass in the field to decrease transpor- tation cost and logistical issues should be developed. The densification of avail- able 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 devel- opment (R&D) effort in increasing productivity, improving stress tolerance, man- aging 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 pro- grams to provide the technical bases for improving agricultural practices and bio- mass 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, agri- cultural 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.

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Summary  Recommendation S.3 (see Recommendation 2.2 in Chapter 2) A framework should be developed to assess the effects of cellulosic-feedstock pro- duction on various environmental characteristics and natural resources. Such an assessment framework should be developed with input from agronomists, ecolo- gists, 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 bbl/d) plant will use about 7 million tons of coal per year, and 100 such plants producing liquid transportation fuels at 5 million bbl/d 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 suf- ficient coal in the United States to support such increased use while supporting the coal-based power industry. A National Research Council evaluation (NRC, 2007) of domestic coal resources concluded as follows: 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 location, quality, recoverability, and transportation issues may sub- stantially reduce the number of years of supply. Future policy will continue to be devel- oped 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. (p. 4) Recently, the Energy Information Administration estimated the proven U.S. coal reserves to be about 260 billion tons. A key conclusion was that there are

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0 Liquid Transportation Fuels from Coal and Biomass Total liquid fuel used in the United States in 2008 was 21 million barrels per 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, cofeed- ing 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 could be produced from a fixed quantity of biomass. Using coal and biomass at 60 and 40 percent, respec- tively, 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 45 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 pro- duced 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

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Summary  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 $95–110/bbl. However, the technically feasible supply does not equal the actual supply inasmuch as many factors influ- ence 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, con- struction environment, and labor availability. The panel developed a few plausible scenarios to illustrate the lag between when technology becomes commercially deployable, and when substantial market penetration will be seen. Deployment of Cellulosic-Ethanol Plants For biochemical conversion to cellulosic ethanol, the panel developed two scenar- ios 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 con- struction 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 expe- rienced 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 gal- lons of cellulosic ethanol per year by 2020. Continued aggressive capacity-building

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 Liquid Transportation Fuels from Coal and Biomass could achieve the Renewable Fuel Standard5 mandate capacity of 16 billion gal- lons 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 dis- cussed 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 build-out rate of two plants (at 50,000 bbl/d of fuel) 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 build-out rate of three plants per year, liquid fuels would be produced at 3 million bar- rels 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 build out 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. How- ever, 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, 5The 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 renew- able 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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Summary  or fuel production at 10,000 bbl/d) and biomass feed rates are similar to those in cellulosic biochemical conversion plants, penetration rates should follow the cellulosic-plant build out more closely. But most likely, the coal-and-biomass build out 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 build-out case that follows the experience of grain ethanol dis- cussed 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 commer- cial 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

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 Liquid Transportation Fuels from Coal and Biomass 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. 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 foot- print 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 trans- portation sector) and the scale of current petroleum imports (about 56 percent 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 aggres- sive 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.

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Summary  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 com- bined 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 do biochemical conversion plants and thus benefit to a greater extent from economies of scale. This strategy could maximize the use of cellulosic biomass and minimize the costs of fuel products. 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 bet- ter 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 green- house 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 con- cerning the environmental effects of biomass production for liquid fuels, other key effects must be considered. On the whole, lignocellulosic-biomass feedstocks pres- ent distinct advantages over food-crop feedstocks with respect to water-use effi- ciency, nutrient and sediment loading into waterways, enhancement of soil fertil- ity, 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.

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 Liquid Transportation Fuels from Coal and Biomass Biochemical Conversion The biochemical conversion of cellulosic biomass to ethanol requires process water for mixing with fermentation substrates and for cooling, heating, and mak- ing reagents that are associated with hydrolysis and fermentation. The amount of water required for processing biomass into ethanol or other biofuels is esti- mated 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. 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 by-product. The ammonia in synthesis gas can be recovered and sold as fertilizer or sent to wastewater 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 parts per million (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

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Summary  combined coal and biomass to transportation fuels with all water streams recycled or reused, the major consumptive uses of water are for cooling, producing hydro- gen, 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 magni- tude of air cooling, water consumption could range from about 1 to 8 bbl per barrel 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 (NRC, 2002) and Coal Research and Development to Support National Energy Policy (NRC, 2007). . 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. The challenges are as follows. Challenge 1 Issues related to cellulosic-feedstock production include: • Developing a systems approach through which farmers, biomass inte- grators, 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 con- sequences through piecemeal development efforts. • Determining the full-life-cycle greenhouse gas emissions of various bio- fuel 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, wild- life habitat, rural development) and thus contribute to a stronger U.S. agricultural

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 Liquid Transportation Fuels from Coal and Biomass 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 deploy- able 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 politi- cally viable. The capture of CO2 is proven, but commercial-scale demonstration plants are needed now to both quantify and improve cost and performance. Sepa- rate 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 deploy- ment by 2020. 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 experi- ence and increases in scale of operation. Incremental improvements in biochemical conversion technologies can be expected to reduce nonfeedstock process costs by

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Summary  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 techni- cal barriers to achieving cost reduction are as follows: • More efficient pretreatment to free up celluloses and hemicelluloses and to enable more efficient downstream conversion. Improved pretreat- ment is unlikely to reduce product cost substantially because pretreat- ment 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 bio- mass 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 cur- rently 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 equip- ment 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 refuel- ing 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,

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0 Liquid Transportation Fuels from Coal and Biomass and construction; the 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 Alterna- tive Transportation Technologies—A Focus on Hydrogen (NRC, 2008) and The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs (NRC, 2004). 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. REFERENCES NRC (National Research Council). 2002. Evolutionary and Revolutionary Technologies for Mining. Washington, D.C.: National Academy Press. NRC. 2004. The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs. 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. NRC. 2008. Transitions to Alternative Transportation Technologies—A Focus on Hydrogen. Washington: D.C.: The National Academies Press.