6
Comparison of Options and Market Penetration

Chapters 2, 3, and 4 provide estimates of costs of fuel products and lifecycle carbon dioxide (CO2) emission from liquid transportation fuels produced from biomass, coal, and coal and biomass via different conversion pathways.1 This chapter compares the life-cycle costs, CO2 emission, and potential supply of the alternative fuel options by analyzing the supply chain beginning with the biomass (Chapter 2) and coal feedstocks, ending with conversion to alternative liquid fuels (Chapters 3 and 4), including carbon balances. The result of the panel’s analysis is a potential supply curve related to alternative liquid fuels that use biomass, coal, or combined coal and biomass as feedstocks. However, the actual supply in 2020 could well be smaller than the potential supply because there are important lags in decisions to construct new conversion plants and in construction. In addition, some of the biomass supply that appears to be economical might not be made available for conversion to alternative fuels because of logistical, infrastructure, and agricultural-organization issues. The analysis shows how the potential supply curve might change with alternative CO2 prices and alternative capital costs. The comparisons in this chapter are based on a point-in-time estimate of costs and the panel’s judgment of technological advancement in the next 10–15 years. The conclusions are drawn from consistent comparisons among alternative liquid-fuel options, but they are not predictions of what the fuel costs or market penetration would be in 2020 or 2035 inasmuch as such factors as

1

This chapter assesses only CO2 emission because the panel was not able to determine changes in other greenhouse gases throughout the life cycle of fuel production. Changes in greenhouse gases other than CO2 are likely to be small or nonexistent.



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6 Comparison of Options and Market Penetration C hapters 2, 3, and 4 provide estimates of costs of fuel products and life- cycle carbon dioxide (CO2) emission from liquid transportation fuels pro- duced from biomass, coal, and coal and biomass via different conversion pathways.1 This chapter compares the life-cycle costs, CO2 emission, and potential supply of the alternative fuel options by analyzing the supply chain beginning with the biomass (Chapter 2) and coal feedstocks, ending with conversion to alternative liquid fuels (Chapters 3 and 4), including carbon balances. The result of the pan- el’s analysis is a potential supply curve related to alternative liquid fuels that use biomass, coal, or combined coal and biomass as feedstocks. However, the actual supply in 2020 could well be smaller than the potential supply because there are important lags in decisions to construct new conversion plants and in construc- tion. In addition, some of the biomass supply that appears to be economical might not be made available for conversion to alternative fuels because of logistical, infrastructure, and agricultural-organization issues. The analysis shows how the potential supply curve might change with alternative CO2 prices and alternative capital costs. The comparisons in this chapter are based on a point-in-time esti- mate of costs and the panel’s judgment of technological advancement in the next 10–15 years. The conclusions are drawn from consistent comparisons among alternative liquid-fuel options, but they are not predictions of what the fuel costs or market penetration would be in 2020 or 2035 inasmuch as such factors as 1This chapter assesses only CO2 emission because the panel was not able to determine changes in other greenhouse gases throughout the life cycle of fuel production. Changes in greenhouse gases other than CO2 are likely to be small or nonexistent. 

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 Liquid Transportation Fuels from Coal and Biomass technological changes, policies that encourage development of one option rather than another, and market forces could alter the conclusions. COMPARISON OF COSTS, GREENHOUSE GAS EMISSIONS, AND POTENTIAL FUEL SUPPLY To examine the potential supply of liquid transportation fuels from nonpetroleum sources, the panel developed estimates of the unit costs and quantities of vari- ous cellulosic biomass sources that could be produced sustainably as discussed in Chapter 2. The panel’s analysis was based on land that is not now used for grow- ing foods although the panel cannot ensure that none of that land will be used for food production in the future. The estimates of biomass supply were combined with the amount of corn grain that would probably be used to produce fuels to satisfy the current legislative requirement to produce 15 billion gallons of ethanol per year. The panel’s analysis allowed it to estimate a supply function for biomass that shows the quantities of cellulosic biomass feedstocks that would potentially be available at the various unit costs. The panel assumed that coal would not be limiting in that it would be available in sufficient quantities at a constant unit cost if used with biomass in thermochemical conversion processes. The panel devel- oped quantitative comparative analyses of alternative pathways to convert bio- mass, coal, or combinations of coal and biomass to liquid fuels (either ethanol or synthetic diesel and gasoline). Pathways, in principle, could include any combina- tion of the various biomass feedstocks and coal and could include either thermo- chemical or biochemical conversion processes.2 However, rather than treating all possible combinations, the panel first examined the cost of and the CO2 emissions associated with each of the various thermochemical and biochemical conversion processes that would use one biomass feedstock and then examined the costs, supplies, and CO2 emissions associated with one thermochemical conversion pro- cess and one biochemical conversion process that would use each of the biomass feedstocks. The first set of analyses compared the costs and greenhouse gas emissions from fuels produced by biochemical and thermochemical conversion. The panel 2The panel also included biochemical conversion of corn grain to ethanol but did not focus the quantitative analysis on this process.

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Comparison of Options and Market Penetration  recognizes that the cost of fuel and the greenhouse gas emissions from biofuels vary with feedstock. Because the purpose of the first set of analyses was to com- pare biochemical and thermochemical conversion, using one biomass feedstock in the analyses would better illustrate the differences between the conversion pro- cesses. Miscanthus, a high-yield perennial grass, was the biomass feedstock used for each conversion process (except those using only coal) because its cost and chemical composition are about the medians of the estimated costs and chemical composition of different cellulosic feedstocks. That analysis allowed the panel to estimate unit costs of each of the thermochemical and biochemical conversion pro- cesses on the assumption that Miscanthus was the biomass feedstock used for each process. For the second set of comparisons, the panel chose two generic conversion processes—conversion of each of the lignocellulosic biomass feedstocks to produce ethanol, and thermochemical conversion of a combination of coal with each of the lignocellulosic biomass feedstocks (in a coal:biomass ratio of 60:40 on an energy basis) to produce synthetic diesel and gasoline. The estimated supply function for biomass provided information about feedstock quantities and costs. That infor- mation was combined with information about conversion costs to obtain supply functions for alternative fuels produced via either thermochemical or biochemical conversion and the assumed corn grain ethanol. In its analyses, the panel made the following assumptions. Changes in the assumptions would normally change the estimated potential supply function. And because uncertainty is associated with each of the assumptions, the collection of uncertainties translates to important uncertainties in the potential supply curve. • All available land discussed in Chapter 2 will be made available for growing biomass for liquid fuels; none will be used for stand-alone electricity production. This assumption implies that renewable portfolio standards for electricity production will not result in the use of biomass to satisfy the requirements for renewable supplies of electricity. • Prices of biomass correspond to the costs of producing the biomass, including the opportunity cost of land. (See Chapter 2 for cost estima- tion.) All available biomass will be priced at those costs. As in Chapter 4, a coal price of $42/ton was used. • Conversion plants that use biomass as feedstock will have the capacity of using it at about 4000 dry tons per day, and all plants will run at 90 percent of capacity.

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 Liquid Transportation Fuels from Coal and Biomass • Biochemical conversion plants use 0.45–0.51 dry tons of biomass for each barrel of ethanol produced, with variations among different feed- stocks based on their chemical compositions. • Capital costs for all investment are based on a 7 percent pretax, no-sub- sidy real discount rate. Possible variations in discount rate are ignored. • Where specified, carbon capture and storage (CCS) will be used to dispose of CO2 permanently. The CCS costs represent estimates of engineering costs to implement CCS. Although there is considerable uncertainty in CCS costs because of potential social, legal, and political issues, these issues are not included in the analyses. Thus, the full cost of CCS could be higher than that used in the analyses and will not be known until CCS is implemented on a commercial scale. (See Chapter 4 and Appendix K.) • If a greenhouse gas price is imposed, it applies to the entire life-cycle CO2 net emission, including emission released in growing biomass, in the conversion processes, and in the ultimate combustion of the liquid fuels, minus CO2 removed from the atmosphere in growing the bio- mass.3 A process that removes more CO2 from the atmosphere than it produces would receive a net payment for CO2. • The panel cannot project the carbon price. When a carbon price is included, it is assumed to be $50/tonne of CO2 in 2020 and in the years shortly thereafter. The actual carbon price could be larger or smaller than that. • To be consistent with the analysis in Chapter 2, these analyses assume that no indirect greenhouse gas emissions result from land-use changes in the growing and harvesting of cellulosic biomass. All biomass vol- umes in Chapter 2 were estimated under the constraint that they could 3Emissions released in growing biomass included estimates of petroleum, natural gas, and fertilizer used for growing, harvesting, and transporting the biomass. Increases in carbon in soil were subtracted. For waste, there is no such reduction for growing biomass, because any such reductions would be independent of whether waste was used as feedstock or permanently stored in landfill. Carbon emissions of the conversion process included total carbon inputs—biomass, coal, and electricity—minus carbon remaining in the fuel. For processes that generated electricity, electricity input was a negative number that reduced the calculated carbon release. This carbon credit for electricity generation was based on 0.61 tonne of CO2 per megawatt-hour of electricity generated by the process. It was assumed that on combustion all carbon remaining in the fuel would be released into the atmosphere as CO2.

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Comparison of Options and Market Penetration  be grown and harvested without creating indirect greenhouse gas emissions. • Production of corn grain has indirect greenhouse gas emissions, but the panel’s cost analyses assume that a U.S. carbon price will not be imposed on such indirect emissions. • Electricity produced as a coproduct has a value of $80/MWh4 in the absence of any price placed on greenhouse gases. If a greenhouse gas price is imposed, the value of coproduct electricity includes, in addition to $80/MWh, the cost of the CO2 emission for electricity generation on the basis of the average of all U.S. electricity generation. • The biomass and cofed coal and biomass conversion plants are sized for biomass feed rates of about 4,000 dry tons per day. • The high-yield perennial grass is Miscanthus at $101 per dry ton. Chapter 2 discusses the projected costs and availability of the various bio- mass feedstocks in 2020. The data from Chapter 2 have been combined to esti- mate a supply function for biomass to show the quantities of biomass feedstocks available at the various unit costs. That supply function is shown in Figure 6.1. As discussed in Chapter 2, the unit costs of most of the feedstocks—straw, woody biomass, corn stover, Miscanthus, native and mixed grasses, and switchgrass—are built up from estimates of the various costs of growing and transporting them. The costs of two feedstocks—corn grain and hay—are based on recent market prices. In particular, the panel assumed that by 2020 the corn price will have dropped sharply from the 2008 high of $7.88/bushel to $3.17/bushel, correspond- ing to $130 per dry ton, a price more consistent with historical prices. The panel assumed that the price of dryland or field-run hay will be $110/ton, which is similar to historical prices. Finally, the cost of using wastes is based on a rough estimate of the costs of gathering, transporting, and storing municipal waste. Such costs can be expected to be highly variable, but the panel assumed that gathering, transporting, and storing will add up to $51 per dry ton. The costs of producing alternative liquid fuels via the various pathways were estimated on the basis of the costs of feedstocks, capital costs, operating costs, conversion efficiencies, and the assumptions outlined above. Scaling factors 4This is the value at the busbar. $80/MWh is the assumed wholesale price of electricity in 2020 in the absence of any carbon prices. The panel did not estimate the feedback from changes in policy options on that electricity price, other than the effects of including carbon prices.

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 Liquid Transportation Fuels from Coal and Biomass 140 Corn Grain Normal- Yield 120 Grasses Cost per Dry Ton (2007 Dollars) High-Yield Grasses Hay 100 Corn Stover 80 Woody Biomass 60 Waste Straw 40 20 0 0 100 200 300 400 500 600 700 800 Million Dry Tons Biomass per Year FIGURE 6.1 Supply function for biomass feedstocks in 2020. High-yield grasses include Miscanthus and normal-yield grasses include switchgrass and prairie grasses. R01203 Main Report 5-3 for capital costs of biochemical and thermochemical conversion plants were derived from two independent analyses and so might not be directly compara- ble. A factor of 0.70 was used for biochemical conversion plants, and a factor of 0.90 was used for thermochemical conversion plants. Figure 6.2 shows the estimate of the gasoline-equivalent5 cost of alternative liquid fuels, without a CO2 price, produced from coal, biomass, or combined coal and biomass. As indicated above, liquid fuels would be produced by using biochemical conversion of Miscan- thus to ethanol (biochemical ethanol) or by using thermochemical conversion via the Fischer-Tropsch (FT) process or a methanol-to-gasoline (MTG) process. For thermochemical conversion, FT and MTG are shown both with and without CCS. As discussed in Chapter 4, the cost of CCS was based on engineering estimates of expenses for transport, land purchase, permitting, drilling, all required capital 5Costsper barrel of ethanol are divided by 0.67 to put ethanol costs on an energy-equivalent basis with gasoline. For Fischer-Tropsch liquids, the conversion factor is 1.0.

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Comparison of Options and Market Penetration  200 Cost per Barrel Gasoline-Equivalent Product Carbon Storage Cost 180 Additional Transportation Cost (2007 Dollars with No Carbon Price) Nonfeedstock Operating Cost 160 Capital Cost Feedstock Cost 140 Total Cost 120 100 80 60 40 20 0 –20 BTL CFT CBFT CFT-CCS CMTG CMTG-CCS Corn Ethanol BTL-CCS CBFT-CCS CBMTG CBMTG-CCS Crude Oil @ $60/bbl Crude Oil Cellulosic Ethanol @ $100/bbl FIGURE 6.2 Costs of alternative liquid fuels produced from coal, biomass, or coal and biomass with zero carbon price. Costs are given per barrel of gasoline equivalent. Note: BTL = biomass-to-liquid fuel; CBFT = coal-and-biomass-to-liquid fuel, Fischer- R01203 Tropsch; CBMTG = coal-and-biomass-to-liquid fuel, methanol-to-gasoline; CCS = 4 Main Report 5- carbon capture and storage; CFT = coal-to-liquid fuel, Fischer-Tropsch; CMTG = coal-to-liquid fuel, methanol-to-gasoline. equipment, storing, capping wells, and monitoring for an additional 50 years. The full cost of CCS could be higher as a result of uncertainty about the regulatory environment of CO2 storage. The supply of ethanol produced from corn grain is also included in the figure. For comparison, costs of gasoline are shown in Figure 6.2 for two different crude oil prices: $60 per barrel and $100 per barrel. Figure 6.3 shows the net CO2 emission per gasoline-equivalent barrel pro- duced by various production pathways. Figure 6.4 shows the detailed flows of CO2 underlying the net flows in Figure 6.3. The CO2 released on combustion is similar among the various pathways, with ethanol releasing less CO2 on combus- tion than either gasoline or synthetic diesel and gasoline do. The large variation in net releases is the result of the large variations in the CO2 taken from the atmo- sphere in growing biomass and the large variations in the CO2 released into the atmosphere in the conversion process.

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0 Liquid Transportation Fuels from Coal and Biomass 1.20 1.10 1.06 Net CO2 (Tonnes per Barrel Gasoline-Equivalent Product) 1.00 0.80 0.60 0.49 0.47 0.44 0.42 0.42 0.37 0.40 0.20 0.00 (0.10) (0.13) (0.13) (0.20) (0.21) (0.40) (0.60) (0.76) (0.80) BTL CFT CBFT CFT-CCS CMTG CMTG-CCS Corn Ethanol BTL-CCS CBFT-CCS CBMTG CBMTG-CCS Cellulosic Ethanol Gasoline FIGURE 6.3 Estimated CO2 emission over the life cycle of alternative-fuel production from the mining and harvesting of resources to the conversion to and consumption of fuel. CO2 is expressed as tonnes of CO2 per barrel of gasoline-equivalent liquid 3 R0120 fuels; a barrel of ethanol is assumed to have 67 percent as much energy as a barrel 5-5 gaso- Main Report of line. The life-cycle CO2 emission from biofuels includes a CO2 credit from photosynthetic uptake by plants, but indirect greenhouse gas emissions, if any, as a result of land-use changes are not included. Note: BTL = biomass-to-liquid fuel; CBFT = coal-and-biomass-to-liquid fuel, Fischer- Tropsch; CBMTG = coal-and-biomass-to-liquid fuel, methanol-to-gasoline; CCS = carbon capture and storage; CFT = coal-to-liquid fuel, Fischer-Tropsch; CMTG = coal-to-liquid fuel, methanol-to-gasoline. The results in Figure 6.2 show that FT and MTG coal-to-liquid (CTL) fuel products with and without CCS are cost-competitive at crude prices of about $60/bbl, but Figure 6.3 shows that without CCS the process vents a large amount of CO2, almost twice that of petroleum gasoline on a life-cycle basis. With CCS, the CO2 life-cycle emission is about the same as that of petroleum gasoline. The biochemical conversion of biomass produces fuels that are more expensive than

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Comparison of Options and Market Penetration  2.0 Electricity CO2 Credit 1.8 Net CO2 (Tonnes per Barrel Gasoline-Equivalent Product) Production Release 1.6 In Product 1.4 From Atmosphere 1.0 0.9 0.8 0.8 1.2 0.7 0.8 0.0 1.0 0.7 0.8 0.2 0.6 0.1 0.1 0.2 0.1 0.0 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.3 0.3 0.2 0.0 0.0 –0.1 0.0 –0.1 –0.1 –0.2 –0.4 (0.58) (0.58) (0.66) (0.66) (0.67) –0.6 –0.1 –0.1 –0.8 –0.1 –0.1 –1.0 (1.19) (1.19) (1.19) –1.2 –0.2 –0.1 –0.1 –1.4 –1.6 BTL CFT CBFT CMTG CBMTG Ethanol Gasoline Cellulosic BTL-CCS CFT-CCS CBFT-CCS CMTG-CCS Corn Ethanol CBMTG-CCS FIGURE 6.4 Detailed flows of CO2 emission over the life cycle of alternative-fuel pro- duction from the mining and harvesting of resources to the conversion to and con- sumption of fuel. CO2 emission is expressed as tonnes of CO2 per barrel of gasoline equivalent. Note: BTL = biomass-to-liquid fuel; CBFT = coal-and-biomass-to-liquid fuel, Fischer- Tropsch; CBMTG = coal-and-biomass-to-liquid fuel, methanol-to-gasoline;ALTF = carbon CCS 6-4 capture and storage; CFT = coal-to-liquid fuel, Fischer-Tropsch; CMTG = coal-to-liquid fuel, methanol-to-gasoline. CTL fuels because the conversion plants are smaller and the feedstock more expensive: biomass costs 3–4 times as much as coal on an energy-equivalent basis. Because of the lower capital cost of the biochemical conversion plants, even the smaller plant produces cellulosic ethanol competitively, at about $115/bbl of gaso- line equivalent. CO2 emission from the corn grain ethanol is slightly lower than that from gasoline. In contrast, CO2 emission from cellulosic ethanol without CCS is close to zero.

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 Liquid Transportation Fuels from Coal and Biomass The cost of liquid fuel from thermochemical conversion of biomass, with CO2 venting and without coal, is about $140 and is higher than that from bio- chemical conversion. Most of the difference in cost results from the greater elec- tricity sales to the grid in connection with the biochemical conversion process. Thermochemical conversion of biomass has the potential of large negative net releases of CO2 with CCS; that is, the process leads to a net removal of CO2 from the atmosphere. Particularly interesting is the results from the relatively small (8,000 tons/day total feed) cofed coal and biomass plant with CCS. The fuel costs are about $110/bbl of gasoline equivalent, and CO2 atmospheric releases from plants with CCS are negative. Those results point to the importance of that option in the U.S. energy strategy. The important influence of a carbon price on fuel price is shown in Figure 6.5 and Table 6.1. The figure and table show that a $50/tonne CO2 price increases the costs of the fossil-fuel options, including the costs of petroleum-based gasoline, TABLE 6.1 Comparison of Costs of Alternative Liquid Fuels Produced from Coal, Biomass, or Coal and Biomass With and Without a $50/tonne CO2 Price Cost of Fuel ($/bbl of gasoline equivalent) Thermochemical Thermochemical Biochemical Conversion Conversion Conversion Without CCS With CCS Without CCS Carbon Price Feedstock FT MTG FT MTG ($/tonne of CO2 equivalent) 00 Coal 068 059 074 067 Not applicable 00 Coal and 101 092 115 102 Not applicable biomass 00 Biomass 138 Not estimated 151 Not estimated 117 00 Crude oil At crude-oil price of $60, cost of gasoline = $73/bbl At crude-oil price of $100, cost of gasoline = $113/bbl 50 Coal 121 115 095 088 Not applicable 50 Coal and 126 116 105 095 Not applicable biomass 50 Biomass 132 Not estimated 114 Not estimated 111 50 Crude oil At crude-oil price of $60, cost of gasoline = $94/bbl At crude-oil price of $100, cost of gasoline = $134/bbl

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Comparison of Options and Market Penetration  substantially. The carbon price brings the cost of biochemical conversion options to $110/bbl of gasoline equivalent. The large amount of CO2 vented in the CTL process almost doubles the cost of product once the carbon price of $50/tonne of CO2 is imposed. Inclusion of a carbon price does not increase the total costs for all pathways (Table 6.1). For example, thermochemical conversion of biomass costs about $140/bbl of gasoline equivalent without CCS, but the produced fuels with the carbon price and CCS are competitive with petroleum-based fuels in the range of $115/bbl of gasoline equivalent (or a crude oil price of $100/bbl). In general, if any pathway takes more CO2 from the atmosphere than it releases in other parts of its life cycle, the inclusion of a carbon price reduces the total cost of producing liquid fuel via that pathway. In reading the graphs, it is important to note that Figures 6.5, 6.6, and 6.7 show the breakdown of all costs, including negative costs, such as credit from electricity generation or from carbon uptake. The negative costs must be sub- tracted from the positive costs to obtain the actual costs. For example, BTL/CCS cost is $151/bbl – $37/bbl = $114/bbl. Those estimates are all based on costs of small gasification units operating with a feed rate of 4,000 dry tons per day. Each unit is capital-intensive. There- fore, larger units can be expected to be deployed in regions where potential bio- mass availability is large—for example, 10,000 dry tons per day. Such units could result in much lower costs. The panel also conducted a sensitivity analysis to assess the effect of uncer- tainty in capital costs on the cost of fuel products. A variation of a 30 percent increase to a 20 percent decrease in capital costs was evaluated. Results are shown in Figures 6.6 and 6.7. The capital-cost variations affect fuel costs of the capital- intensive gasification processes more than those of the biochemical conversion processes, but the variations do not have a major effect on the costs of fuel prod- ucts relative to each other, particularly in light of the wide swings in crude-oil price in 2008. Although it is not shown in the figures, another less-developed concept is biochemical conversion with CCS. The panel made a rough first-pass estimate of the cost reduction in biochemical conversion ($125/bbl of gasoline equivalent) and found that with a CO2 price of $50/tonne, cost could be reduced substantially through CCS. That cost, however, was not fully quantified. As noted previously, the cost estimates for biochemical conversion and ther- mochemical conversion are based on only one biomass feedstock, Miscanthus. Figures 6.5 through 6.7 do not show how much fuel could be produced at the

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 Liquid Transportation Fuels from Coal and Biomass 160 Cost per Barrel Gasoline- Equivalent Product Hay Normal-Yield 140 Grasses Waste Corn Grain Corn Stover 120 High-Yield Grasses Straw 100 (2007 Dollars) 80 Woody Biomass 60 Estimated Costs in 2020 Assumed CO2 Price: 40 Gasoline from Crude Oil @ $60/bbl $50/Tonne of CO2 Equivalent Gasoline from Crude Oil @ $100/bbl No Indirect Impacts on Land Conversion 20 0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0 Million Barrels Gasoline Equivalent per Day FIGURE 6.9 Estimated supply of cellulosic ethanol plus ethanol produced from corn grain at different price points in 2020. Cost estimates include a $50 tax for each tonne of CO2 released on a well-to-wheel basis. The red solid and dotted lines show the supply of crude oil at $60/bbl and $100/bbl for comparison. ALTF 6-9 The potential supply of gasoline or diesel from thermochemical conversion of a combination of coal and biomass (with CCS) is greater than that from biochemi- cal conversion that uses only biomass. The thermochemical costs are similar to or smaller than the biochemical conversion costs. The costs differ because coal costs less than biomass. In addition, using a combination of coal and biomass allows a larger plant to be built and reduces capital costs per volume of product. The combination of coal and biomass allows more alternative fuel to be produced than would be possible with biomass alone. The quantity of biomass limits the overall production in either case. Thus, the addition of coal increases the total amount of liquids that could be produced from a given quantity of biomass. Using the combination of coal and biomass, oil potentially can be displaced from transportation at almost 4 million bbl/d (40 percent of gasoline and diesel used

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Comparison of Options and Market Penetration  200 180 Cost per Barrel Gasoline Equivalent 160 Normal-Yield Grasses Waste High-Yield 140 Woody Grasses Corn Stover Hay Biomass (2007 Dollars) Waste Hay 120 High-Yield Woody Grasses Straw Corn Stover Biomass 100 Normal-Yield Grasses Straw 80 60 Estimated Cost in 2020 without CCS Assumed CO2 Price: Estimated Cost in 2020 with CCS $50/Tonne of CO2 Equivalent 40 No Indirect Impacts Gasoline from Crude Oil @ $60/bbl on Land Conversion Gasoline from Crude Oil @ $100/bbl 20 0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Million Barrels Gasoline Equivalent per Day FIGURE 6.10 Estimated supply of gasoline and diesel produced by thermochemical conversion of combined coal and biomass via FT with and without CCS at different price points in 2020. The cost estimates include a $50 tax for each tonne of CO2 released on a well-to-wheel basis. The red solid and dotted lines show the supply of crude oil at $60/bbl and $100/bbl for comparison. ALTF 6-10 by light-duty vehicles in 2008). As noted above, this analysis assumes that all cel- lulosic biomass sustainably grown for fuel will be used for liquid transportation fuel. See Box 6.1 for further discussion. MARKET PENETRATION The discussion above focuses on biomass supply and fuel technology deployable by 2020, but a potential supply of alternative liquid fuel does not translate to the sup- ply that would actually be available in 2020. The following section discusses issues that might limit the rate of market penetration. For biochemical conversion, two scenarios of potential biochemical penetration are presented. The actual penetra- tion could be slower or faster, depending on crude-oil price, expectations of future prices, federal and state policy, the U.S. construction industry, and other variables.

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0 Liquid Transportation Fuels from Coal and Biomass BOX 6.1 Preferential Use of Biomass— Power Generation or Liquid Transportation Fuels A number of factors can be expected to influence the use of biomass to sup- port U.S. energy requirements. The major options are use of biomass to generate power and to produce liquid transportation fuels. Biomass can be expected to be used for both options according to policies that mandate a minimum require- ment for renewable energy and fuels. Those include minimum requirements for renewable power generation and coal power-plant permits that mandate that a given percentage of biomass be fed with coal. Mandating minimum requirements for renewable transportation fuels will drive the use of biomass to produce fuels. Other factors will also be influential in determining the use of biomass. First, the lack of feedstock options other than biomass for producing liquid transportation fuels with reduced CO2 emission means that biomass will have to be a component. The use of coal with CCS can provide liquid transportation fuels and move the United States away from reliance on petroleum, but it does not reduce CO2 emission from the transportation sector. At its best, it is neutral rela- tive to conventional gasoline from the point of view of climate change. Power generation has a number of options other than biomass that can provide electric- ity with reduced CO2 emission. From a renewables point of view, there are wind and solar sources. Nuclear power also has low CO2 emission. Furthermore, the use of coal with CCS can produce electricity with marked reductions in CO2 emission— by, say, 80 or 90 percent—and in mercury and sulfur emissions. Thus, power gen- eration truly has options other than biomass to address greenhouse gas and other environmental issues. That points to the use of biomass for liquid transportation fuels as an essential component in any greenhouse gas management program. In addition, biomass for liquid transportation fuels provides diversity of supply and enhances energy security. If biomass is to be used as a component in a CO2-management approach, it should be used in a way that provides the lowest-cost CO2 reduction in terms of dollars per tonne of CO2 avoided. The avoided cost of CO2 is projected to be much lower when biomass is used to produce liquid fuels than when it is used to pro- duce power. That leads to the conclusion that the use of biomass to produce liquid trans- portation fuels has more societal advantages than its use to generate electricity, because the use of biomass is an effective route to reducing CO2 emission from the transportation sector where few other options exist and it does so at a much lower cost per tonne of CO2 avoided.

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Comparison of Options and Market Penetration  Biochemical Conversion Production of ethanol from grain is fully commercial. U.S. production capacity grew from 0.28 million bbl/d at the end of 2004 to 0.38 million bbl/d by the end of 2006 and to about 0.46 million bbl/d by the end of 2007. (Those figures corre- spond to 4.3, 5.9, and about 7 billion gallons per year by the end of 2007.6) The capacity-build rate of grain ethanol averaged 25 percent per year over a 6-year period. At the maximum build rate, 1–2 billion gallons of annual etha- nol-production capacity was added per year or an annual addition of 0.065–0.13 million bbl/d; at an average plant size of 3300 bbl of ethanol per day or 50 mil- lion gallons per year, that means 20–40 plants/year at the maximum. Considering current plant construction that was under way, ethanol-production capacity would have been about 0.5 million bbl/d by the end of 2008. However, 12–15 billion gallons of grain ethanol per year (0.8–1.0 million bbl/d) is probably the limit with respect to corn availability, assuming that corn yields and acreage increase modestly. Production of ethanol from cellulose has yet to be demonstrated on a com- mercial scale, and there remain questions about the economic and commercial viability of the technology. Within the next 3–5 years, five or six technology- demonstration plants (on a noncommercial scale) are expected. The plants will provide valuable information on cost, engineering design, technology robustness, and particularly commercial viability on the scale required to warrant large-scale cellulosic-ethanol production. That information should be available by 2012. The commercial and economic issues potentially will be gradually resolved as cellulosic-ethanol production technology matures and development of new strains of organisms and manufacturing methods reach commercial implementation. As commercially proven technology for cellulosic-ethanol production evolves in scale and efficiency, growth in cellulosic-ethanol production capacity could approach or even exceed the growth experienced in grain ethanol. Cellulosic-ethanol plants are similar to grain-ethanol plants but somewhat more complex; and because of the dispersed nature of biomass, they might be comparable in size to, or even up to twice as large as, typical grain-ethanol plants. For the rest of this discussion, it is assumed that cellulosic ethanol will be commercially demonstrated by 2012 and that it will be either economically competitive with petroleum-based fuels or made 6Inoil-equivalent figures, these rates—adjusted for energy content—correspond to 0.19, 0.26, and 0.31 bbl of oil equivalent per day.

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 Liquid Transportation Fuels from Coal and Biomass competitive through the use of subsidies or policy so that capacity will be built with private funds. The U.S. Department of Energy roadmap for cellulosic ethanol proposes “to accelerate cellulosic ethanol research, helping to make biofuels prac- tical and cost-competitive by 2012.” Here, cellulosic-ethanol plants with a collective capacity of 1 billion gallons per year are assumed to be in operation by 2015 as a result of overall commer- cial development and demonstration activities and that the capacity-build beyond 2015 will track one of two scenarios based on the capacity-build experienced by grain ethanol (1–2 billion gallons of new capacity per year) (Figure 6.11). One scenario tracks the maximum capacity-build experienced for grain ethanol, and the second scenario is more aggressive and reaches about twice the capac- ity achieved for grain ethanol. The two scenarios project 7–12 billion gallons of cellulosic ethanol per year by 2020 (0.5–0.8 million bbl/d). Continued aggressive capacity-building could achieve the renewable fuel standard (RFS) mandate capac- ity of 16 billion gallons of cellulosic biofuel per year by 2022, but it would be a stretch. The RFS was created by the 2005 U.S. Energy Policy Act. However, the 2007 U.S. Energy Independence and Security Act amended the RFS to set forth “a phase-in for renewable fuel volumes beginning with 9 billion gallons in 2008 and ending at 36 billion gallons in 2022” (0.6 and 2.4 million bbl/d, respectively). If the more aggressive scenario plays out, capacity-building could yield 1.5–2 mil- lion bbl of cellulosic ethanol per day by 2030 and up to 2.6 million bbl/d shortly thereafter, consuming about 440 million dry tons of biomass per year. However, it should be stressed that whether the production capacity expands more rapidly or less rapidly will depend heavily on economic incentives and policies and on the actual and projected prices of crude oil. Thermochemical Conversion For coal plants, the gasification, FT, and MTG technologies are developed. How- ever, there is no experience with integrated plants that would use all the technolo- gies combined with CCS. To have CTL ready to supply fuels in the shortest time possible to improve energy security, an immediate start on the design and con- struction of commercial demonstration plants with CCS is critical. CO2 capture is built into the FT and MTG processes, but learning from demonstration-plant operations is critical for decreasing cost and improving performance. CO2 stor- age will require adding compressors to the plants and locating the demonstrations close to CO2 repositories (for example, saline aquifers, geological formations, or

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Comparison of Options and Market Penetration  40 Billion Gallons of Ethanol per Year 35 30 25 20 15 10 5 0 2010 2014 2018 2022 2026 2030 Year FIGURE 6.11 Cellulosic-ethanol capacity-building scenarios starting with commercial demonstration plants in 2009 with first commercial-scale plants following thereafter, building to 1 billion gallons of cellulosic ethanol per year in 2015. Capacity-building beyond 2015 is in accordance with the maximum capacity build achieved for grain etha- nol (blue bars), and a more aggressive capacity build of about twice that achievedTF 6-11 AL for grain ethanol. The maximum build rate could achieve the 2022 Renewable Fuel Standard mandate of 16 billion gallons of cellulosic ethanol per year, but it would be a stretch. sites of enhanced oil-recovery opportunities). Experience from the demonstrations is also needed to resolve scientific and regulatory issues to make CCS viable. If the demonstrations are started immediately and CCS is proved viable and safe by 2015, economically viable commercial plants could be starting up before 2020. For thermochemical processing of biomass and cofed coal and biomass plants, a timeline similar to that for CTL applies. CCS is not necessary for bio- mass-to-liquid fuel plants to produce carbon-neutral fuels, and commercial dem- onstration can start immediately if society places a high enough value on car- bon-neutral fuels (fuels with zero greenhouse gas life-cycle emissions). Although CCS may not be required in coal-and-biomass-to-liquid (CBTL) fuel plants if the proportion of biomass to coal is high in the feedstock, such plants will have to deal with the problems of feeding biomass to gasifiers and locating the plants in a region that could supply sufficient biomass (about 4000 dry tons of biomass per day) and have access to sufficient coal (about 3000 tons/day as received). For CBTL plants, the technology is close to developed, and several commercial dem-

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 Liquid Transportation Fuels from Coal and Biomass onstration plants are in operation or being built with and without CCS. However, gaining operational experience in the plants with CCS is critical because cost reductions will result from the experience. Because CTL fuel has twice the CO2 life-cycle emission of gasoline unless it uses CCS, CCS will probably be required. Penetration rates of the CBTL plants could be expected to be similar to or slightly less than that of the cellulosic-ethanol build-out case that follows the experi- ence of grain ethanol discussed earlier. Penetration rates for biomass plants can be expected to be similar to that for the cellulosic-ethanol case, but both plants depend heavily on the ability to reduce fuel-production costs and on the pres- ence of a substantial carbon policy. The biomass-gasification penetration rate will depend heavily on getting the biomass supply up to about a million dry tons per year per site or higher. Cellulosic ethanol could be applied on a smaller scale of biomass availability. To get some perspectives on capacity growth for CBTL and CTL plants, the panel presents the following analysis. The capacity growth rates could be higher or lower, depending on such factors as government policy, oil prices, carbon price, and the labor and commodity markets. Consider a CBTL plant integrated with CCS that uses about 40 percent biomass and 60 percent coal on an energy basis. Such a plant produces liquid transportation fuels that are essentially carbon-free and, to the extent that it pro- duces electricity for the grid, the electricity is also carbon-free. In the recycle case designed to maximize the liquid-fuels production with CCS, the plant produces about 10,000 bbl of liquid hydrocarbon transportation fuels per day. The size of the plant considered in this case is 4,000 dry tons of biomass per day. The CBTL plant is more complex and its capital cost is substantially higher on the basis of a barrel of fuel produced than is a biochemical conversion plant of comparable biomass feed capacity. When the difference is put on the basis of energy-equivalent fuels, it is reduced but is still important. As mentioned above, the build-out of grain ethanol for fuel capacity averaged 25 percent per year over a 6-year period and was the basis of the estimation of the build-out rate of cellulosic ethanol at sites of 1.1 million dry tons per year. The cellulosic-ethanol build-out had 225 plants pro- ducing 1.5 million bbl of ethanol per day (1 million bbl of gasoline equivalent per day) in 2030 at a total running sum cost of about $100 billion for the base case and 370 plants producing 2.4 million bbl/d (1.6 million bbl of gasoline equivalent per day) and consuming about 440 million dry tons of biomass per year. For CBTL plants, the panel used a slightly lower build-out rate because of issues of accessing sites with about 1.1 million dry tons of biomass per year and a

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Comparison of Options and Market Penetration  similar availability of coal. In this case, a total of 200 plants were in place by 2030 and producing 2 million bbl of gasoline equivalent per day at a running sum cost of about $260 billion. It was assumed that three plants were commissioned in 2015 and that growth is expanded as capacity to build them increases; this largely fol- lows the cellulosic-ethanol projection to achieve the numbers summarized above. That would consume about 220 million dry tons of biomass and about 200 million tons of coal per year. If that growth rate could be continued to 2035, an estimated 2.5 million bbl of gasoline-equivalent fuels could be produced, consuming less than the projected biomass availability; but siting plants to access both biomass and coal is probably the limiting factor for CBTL plants. The analysis shows that the capac- ity growth rates would have to exceed historical rates considerably if 550 million dry tons of biomass per year is to be converted to liquid fuels in 2030. For CTL plants with CCS, consider a plant build-out rate of two to three plants per year each with 50,000-bbl/day capacity for 20 years starting in 2015 (when the first plants are commissioned). This scenario would reduce dependence on imported oil, but it would not reduce CO2 emission from transportation. At a build-out rate of two plants per year, 2 million bbl of liquid fuels per day would be produced from 390 million tons of coal per year by 2035 at a total cost of about $200 billion for all the plants built. At a build-out rate of three plants per year, 3 million bbl of liquid fuels per day would be produced from about 580 mil- lion tons of coal per year. The latter case would replace about one-third of U.S. oil use in light-duty transportation and increase U.S. coal production by 50 percent. FINDINGS AND RECOMMENDATIONS Finding 6.1 Alternative liquid transportation fuels from coal and biomass have the potential to play an important role in helping the United States to address issues of energy security, supply diversification, and greenhouse gas emissions with technologies that are commercially deployable by 2020. • With CO2 emissions similar to those from petroleum-based fuels, a sub- stantial 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.

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 Liquid Transportation Fuels from Coal and Biomass • With CO2 emissions substantially lower than those from petroleum-based fuels, up to 2 million bbl/d 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 bbl/d of gasoline-equivalent fuel can be technically produced if the same amount of biomass is com- bined 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 influence the market penetration of fuels. Finding 6.2 If commercial demonstration of cellulosic-ethanol plants is successful and com- mercial 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 bbl/d by 2035. Finding 6.3 If commercial demonstration of coal-and-biomass-to-liquid plants with carbon capture and storage is successful and the first commercial plants start up in 2020 and if it is assumed that capacity will grow by 20 percent each year, coal-and-bio- mass-to-liquid fuels with low CO2 life-cycle emissions can replace up to 2.5 mil- lion barrels of gasoline equivalent per day by 2035. Finding 6.4 If commercial demonstration of coal-to-liquid plants with carbon capture and storage is successful and the first commercial plants start up in 2020 and if it is assumed that capacity will grow by two to three plants each year, coal-to-liquid fuels with CO2 life-cycle emissions similar to those of petroleum-based fuels can replace up to 3 million barrels of gasoline equivalent per day by 2035. That option would require an increase in U.S. coal production by 50 percent.

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Comparison of Options and Market Penetration  Recommendation 6.1 Detailed scenarios of market penetration rates of biofuels, coal-to-liquid fuels, and associated biomass and coal supply options should be developed to clarify hurdles and challenges to achieving substantial effects on U.S. oil use and CO2 emissions. The analysis will provide policy makers and business leaders with the information needed to establish enduring policies and investment plans for accelerating the development and penetration of alternative-fuels technologies. REFERENCE EIA (Energy Information Administration). 2008. Annual Energy Outlook 2008 with Projections to 2030. Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

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