3

Alternative Fuels

This chapter discusses the fuel production and use associated with striving to meet the overall study goals of a 50 percent reduction in petroleum use by 2030 and an 80 percent reduction in petroleum use and in greenhouse gas (GHG) emissions from the light-duty vehicle (LDV) fleet by 2050 compared to the corresponding values in 2005. It addresses the primary sources of energy for making alternative fuels, the costs of alternative fuels, and the investment needs and the net GHG emissions of the fuels delivered to the LDV fleet over time. Alternative fuels are transportation fuels that are not derived from petroleum, and they include ethanol, electricity (used in plug-in electric vehicles [PEVs] such as plug-in hybrid electric vehicles [PHEVs] or battery electric vehicles [BEVs]), hydrogen, compressed or liquid natural gas, and gasoline and diesel derived from coal, natural gas, or biomass. Petroleum-based fuels are liquid fuels derived from crude oil or unconventional oils.

The chapter opens with a summary discussion of the study goals, fuel pathways, trends in the fuels market, fuel costs, investment costs, and GHG emissions for an LDV in 2030 using each fuel, and it includes a summary table for each of the last three categories, as well as some cross-cutting findings. More detailed discussions of each fuel follow the summary discussion, with a section devoted to each fuel. Also discussed are carbon capture and storage, and resource needs and limitations.

3.1 SUMMARY DISCUSSION

3.1.1 The Scope of Change Required

The study goals are aggressive and require significant improvements to the vehicle and the fuel system to meet the desired goals. The number of LDVs and the vehicle miles traveled (VMT) are expected to nearly double from 2005 to 2050, adding challenges to meeting the goals.1 To reach the goals with twice as many LDVs on the road in 2050 means that each LDV would consume on average only 10 percent of the petroleum consumed compared to 2005 and emit only 10 percent of the net GHG emissions. Gasoline and diesel made from petroleum would be nearly eliminated from the fuel mix to reach the petroleum reduction goal. The 80 percent net GHG emissions reduction goals can be met by various combinations of lower fuel consumption rate (inverse of fuel economy) and lower fuel net GHG emission (Table 3.1). The higher the reductions in LDV fuel consumption rate, the lower the reductions in fuel net GHG emissions would need to be to reach the GHG reduction goal. As discussed in Chapter 2, LDV fleet economy improvements of 3 to 5 times may be technically feasible by 2050, meaning that the average net GHG emissions of the fuel used in the entire LDV

TABLE 3.1 LDV Fuel Economy Improvement and Fuel GHG Impact Combinations Needed to Reach an 80 Percent Reduction in Net GHG Emissions Compared to 2005 Assuming a Doubling in Vehicle Miles Traveled (VMT)

LDV Fuel Economy Increase versus 2005 LDV Fuel Consumption Rate Relative to 2005 (percent)a Requisite Reduction in Net Fuel System GHG Impact versus 2005 (percent)b
50 80
33 70
25 60
20 50
17 40

aThe vehicle fuel consumption rate (e.g., gal/100 mi) corresponding to a given increase in fuel economy (e.g., miles per gallon) relative to the base year level. For example, a quadrupling (4×) of fuel economy simply means that the fuel consumption rate is 25 percent of the base level.
bThe net reduction of system-wide GHG emissions from fuel supply sectors needed to meet an LDV sector-wide 80 percent GHG reduction goal for a given fuel economy gain when assuming a fixed doubling of VMT, that is, without accounting for induced effects such as VMT rebound due to higher fuel economy.

_______________________

1The EIA Annual Energy Outlook 2011 (EIA, 2011a) is the basis for these projections.



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3 Alternative Fuels This chapter discusses the fuel production and use asso- goals with twice as many LDVs on the road in 2050 means ciated with striving to meet the overall study goals of a 50 that each LDV would consume on average only 10 percent of percent reduction in petroleum use by 2030 and an 80 percent the petroleum consumed compared to 2005 and emit only 10 reduction in petroleum use and in greenhouse gas (GHG) percent of the net GHG emissions. Gasoline and diesel made emissions from the light-duty vehicle (LDV) fleet by 2050 from petroleum would be nearly eliminated from the fuel compared to the corresponding values in 2005. It addresses mix to reach the petroleum reduction goal. The 80 percent the primary sources of energy for making alternative fuels, net GHG emissions reduction goals can be met by various the costs of alternative fuels, and the investment needs and combinations of lower fuel consumption rate (inverse of fuel the net GHG emissions of the fuels delivered to the LDV economy) and lower fuel net GHG emission (Table 3.1). fleet over time. Alternative fuels are transportation fuels that The higher the reductions in LDV fuel consumption rate, are not derived from petroleum, and they include ethanol, the lower the reductions in fuel net GHG emissions would electricity (used in plug-in electric vehicles [PEVs] such as need to be to reach the GHG reduction goal. As discussed in plug-in hybrid electric vehicles [PHEVs] or battery electric Chapter 2, LDV fleet economy improvements of 3 to 5 times vehicles [BEVs]), hydrogen, compressed or liquid natural may be technically feasible by 2050, meaning that the aver- gas, and gasoline and diesel derived from coal, natural gas, age net GHG emissions of the fuel used in the entire LDV or biomass. Petroleum-based fuels are liquid fuels derived from crude oil or unconventional oils. The chapter opens with a summary discussion of the study TABLE 3.1  LDV Fuel Economy Improvement and Fuel goals, fuel pathways, trends in the fuels market, fuel costs, GHG Impact Combinations Needed to Reach an 80 investment costs, and GHG emissions for an LDV in 2030 Percent Reduction in Net GHG Emissions Compared to using each fuel, and it includes a summary table for each 2005 Assuming a Doubling in Vehicle Miles Traveled of the last three categories, as well as some cross-cutting (VMT) findings. More detailed discussions of each fuel follow the LDV Fuel Requisite Reduction in summary discussion, with a section devoted to each fuel. Consumption Rate Net Fuel System GHG Also discussed are carbon capture and storage, and resource LDV Fuel Economy Relative to 2005 Impact versus 2005 needs and limitations. Increase versus 2005 (percent)a (percent)b 2× 50 80 3.1 SUMMARY DISCUSSION 3× 33 70 4× 25 60 5× 20 50 3.1.1  The Scope of Change Required 6× 17 40 The study goals are aggressive and require significant aThe vehicle fuel consumption rate (e.g., gal/100 mi) corresponding to a improvements to the vehicle and the fuel system to meet the given increase in fuel economy (e.g., miles per gallon) relative to the base desired goals. The number of LDVs and the vehicle miles year level. For example, a quadrupling (4×) of fuel economy simply means that the fuel consumption rate is 25 percent of the base level. traveled (VMT) are expected to nearly double from 2005 to bThe net reduction of system-wide GHG emissions from fuel supply sec- 2050, adding challenges to meeting the goals.1 To reach the tors needed to meet an LDV sector-wide 80 percent GHG reduction goal for a given fuel economy gain when assuming a fixed doubling of VMT, that is, 1  The EIA Annual Energy Outlook 2011 (EIA, 2011a) is the basis for without accounting for induced effects such as VMT rebound due to higher these projections. fuel economy. 42

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ALTERNATIVE FUELS 43 fleet would have to be reduced by 50 to 70 percent per gallon reduces the economic motivation to switch from gasoline to of gasoline equivalent (gge) by that time. an alternative fuel. Second, biofuel production is expected to increase as Finding: Meeting the study goals requires a massive a result of the Renewable Fuel Standard 2 (RFS2) passed restructuring of the fuel mix used for transportation. as part of the 2007 Energy Independence and Security Act Petroleum-based fuels must be largely eliminated from (EISA). This legislation mandated the consumption of 35 the fuel mix. Other alternative fuels must be introduced billion gallons of ethanol-equivalent3 biofuel and 1 billion such that the average GHG emissions from a gallon gallons of biodiesel (about 24.3 billion gge/yr based on equivalent of fuel are only about 40 percent of today’s energy content) by 2022. The detailed requirements of RFS2 level. are discussed in Appendix G.1. Based on the 2010 gasoline use of 136 billion gge/yr (8.88 million bbl/d), this mandate increases biofuel use from 9.9 percent (0.87 million bbl/d) to 3.1.2 Fuel Pathways 18 percent (1.59 million bbl/d) of the gasoline mix by volume Many different alternative fuel pathways have been pro- (EIA, 2011b). Although the mandated volume for cellulosic posed, and this study selected seven different fuel pathways biofuel is not expected to be met by 2022, any additional to analyze: conventional petroleum-based gasoline, biofuels biofuel volume in the conventional gasoline mix reduces the (including ethanol and “drop-in”2 biofuels), electricity, need for gasoline from petroleum and the volume of other hydrogen, compressed natural gas (CNG), gas to liquids alternative fuels needed to reach the study goals. See Sec- (GTL), and coal to liquids (CTL). These were selected tion 3.2, “Biofuels,” in this chapter for a detailed discussion. because of their potential to reduce petroleum use, to be pro- Third, the volume of economic natural gas from shale duced in large quantities from domestic resources, and to be deposits within the United States has been increasing rapidly. technically and commercially ready for deployment within In its June 18, 2009, report the Potential Gas Committee the study period. Most fuels selected have lower net GHG upgraded by 39 percent the estimated U.S. potential natural emissions than petroleum-based fuels. Other alternative- gas reserves (defined as being potentially economically fuel pathways were discussed but not included for detailed extractable by the use of available technology at current analysis because they did not meet the first three criteria. For economic conditions) compared with its previous biannual example, methanol is discussed in Appendix G.8 but was estimate (Potential Gas Committee, 2009). Based on the new not included for detailed analysis because of environmental estimates, the probable natural gas reserves would provide and health concerns that inhibit fuel distribution and retail about 86 years of consumption if the consumption rate stays companies from broadly offering methanol as a fuel. at the current level. In 2011, the Potential Gas Committee The fuel costs, net GHG emissions, investment needs, and increased its estimates such that 90 years of probable reserves resource requirements were analyzed on a consistent basis exist based on 2010 consumption. Many previous studies on for the different fuels to facilitate comparisons among fuels. alternative fuels did not include natural gas as a possible Future technology and cost improvements for the selected source for LDV fuel because of limited domestic supply, and fuels are considered and compared on a consistent basis, the likely price increase in electricity and residential heating even though the extent of improvement for different fuels costs associated with high natural gas use in the transporta- is likely to vary. tion market. With increasing domestic production, natural gas now is a viable option for providing transportation fuels through multiple pathways including electricity, hydrogen, 3.1.3  Developing Trends in the Fuels Market GTL, and CNG. See Section 3.5, “Natural Gas,” in this chap- Several developments in the energy markets over the ter and Appendix G.7 for a detailed discussion. past few years will have large impacts on long-term LDV fuel-use patterns. First, the fuel economy of the LDV fleet 3.1.4  Study Methods Used in the Analysis will increase rapidly over the next decade because of higher Corporate Average Fuel Economy (CAFE) standards effec- This study considers conventional and alternative fuels tive through 2016 and proposed through 2025. The CAFE for the 2010-2050 period, and this committee undertook a standards increase requirements from 23.5 mpg in 2010 to number of tasks to generate possible fuel scenarios and data 34.1 mpg in 2016 to 49.7 mpg in 2025. Alternative fuels for use in the modeling efforts described in Chapter 5. The and new LDV technologies would compete with future primary sources for the data are different for each fuel and gasoline or diesel LDVs that use much less petroleum and are explained in the sections that provide details on each have lower net GHG emissions. From a consumer viewpoint, fuel below in this chapter. The committee made efforts to the decreasing volume of gasoline needed to travel a mile standardize input data and definitions between the primary 2  Drop-in fuel refers to nonpetroleum fuel that is compatible with existing 3  A gallon of ethanol has about 77,000 Btu, compared with 116,000 Btu infrastructure for petroleum-based fuels and with LDV ICEs. in 1 gallon of gasoline equivalent.

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44 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS information sources. The tasks the committee performed TABLE 3.2  2030 Annual Fuel Cost per LDV, Untaxed include: Unless Noted Annual · Assessed the current state of the technology readi- Annual Consumer ness for each fuel using information gathered from Fuel Cost Consumer Use Fuel Cost Fuel ($/gge or kWh) (gge or kWh) ($/yr) presentations made to this committee and published literature. Gasoline (taxed) 3.64/gge 325 gge 1,183 · Estimated future improvements to these technologies Biofuel (drop in) 3.39/gge 325 gge 1,102 Gasoline (untaxed) 3.16/gge 325 gge 1,027 that could be broadly deployed in the study period.4 PHEV10a 3.16/gge 260 gge 913 · Estimated the range of costs based on future technol- 0.141/kWh 650 kWh ogy for each fuel delivered to the LDV at a fueling CTL with CCS 2.75/gge 325 gge 894 station in a similar way for each fuel. The reference GTL 2.75/gge 325 gge 894 price basis in the Energy Information Administra- PHEV40b 3.16/gge 130 gge 752 0.175/kWh 1,950 kWh tion’s (EIA’s) Annual Energy Outlook 2011 (EIA, Hydrogen—CCS case 4.10/gge 165 gge 676 2011a) is used for all primary fuel prices. Investment Natural gas—CNG 1.80/gge 325 gge 585 costs are expressed in 2009 dollars. BEV 0.143/kWh 3,250 kWh 465 · Estimated the initial investment costs needed to build NOTE: All fuel costs are based on the 2011 AEO (EIA, 2011a) for 2030. the infrastructure for each fuel pathway.5 The assumed fuel economies are representative of on-road LDV averages · Estimated the net GHG emissions per gallon of gas- for 2030 described in the scenarios in Chapter 5. The following assump- oline-equivalent for each fuel based on the methods tions were made: 13,000 mi/yr traveled and 40 mpgge for liquid and CNG selected for producing the fuel. An upstream GHG vehicles, 80 mpgge for hydrogen and 4.0 mi/kWh for electric vehicles. PHEV10 gets 20 percent of miles on electric, PHEV40 gets 60 percent. All component, a conversion component, and a combus- costs are untaxed unless noted. Electricity cost includes the retail price plus tion component were included in the estimate of net amortization of the cost of a home charger. GHG emissions. aPHEV10 is a plug-in hybrid vehicle designed to travel about 10 miles primarily on battery power only before switching to charge-sustaining operation. 3.1.5  Costs of Alternative Fuels bPHEV 40 is a plug-in hybrid vehicle designed to travel about 40 miles primarily on battery power only before switching to charge-sustaining The costs of alternative fuels through 2035 are estimated operation. based on the energy raw material prices in the reference case of the Annual Energy Outlook 2011 (AEO; EIA, 2011a), and the basis and assumptions for the estimates are explained ing force for consumers to switch from gasoline to alternate in the individual fuel sections. Fuel prices beyond 2035 vehicle technologies in this timeframe. Untaxed fuel cost were estimated by the committee. Table 3.2 summarizes differences of only several hundred dollars per year will not the expected alternative fuel costs for 2030 on a $/gge or cover the additional vehicle costs described in Chapter 2.6 $/kWh basis for some of the fuel pathways and shows the consumer’s annual fuel costs for a new vehicle of that type Finding: As the LDV fleet fuel economy improves over based on 2030 estimated vehicle mileage. time, the annual fuel cost for an LDV owner decreases. While the values in Table 3.2 are useful guideposts for With high fleet fuel economy, the differences in annual this analysis, there are a few factors to keep in mind. First, fuel cost between alternative fuels and petroleum-based the fuel costs shown in Table 3.2 are untaxed—current or gasoline decreases and the annual costs become similar future taxes are not included and could alter the actual annual to one another. Therefore, over time fuel-cost savings cost that consumers pay. Second, the per-gallon of gasoline- will become less important in driving the switch from equivalent fuel cost estimates in 2030 are a snapshot in time petroleum-based fuels to other fuels. and will likely change as technology develops and world energy prices change. Third, the untaxed fuel-purchase costs to consumers each year appear similar for most fuels except 3.1.6  Investment Costs for Alternative Fuels for CNG and the BEV, which are significantly lower than oth- The investment costs to build the fuel infrastructure are ers. Given the small separation for the other options in 2030, sizable for all of the alternative fuel and vehicle pathways. untaxed fuel costs are not expected to be a significant driv- In fact, these costs remain among the most important barriers 4 Some future technologies that might be developed during the study period are not included for detailed analysis because future efficiencies and 6 As pointed out in Chapters 4 and 5, consumers tend to value about 3 costs are not well understood. Examples of this include photoelectrochemi- years worth of fuel savings when making decisions on initial vehicle pur- cal hydrogen production and biofuels from algae. chases. Using the numbers in Table 3.2, 3 years of untaxed hydrogen saves 5  Investment costs are explained in Appendix G.2, “Infrastructure Initial only $1,501 compared with taxed gasoline during 2030. The cost saved is Investment Cost.” not enough to cover the higher cost of a fuel cell electric vehicle (FCEV).

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ALTERNATIVE FUELS 45 to rapid and widespread adoption of alternatives. Table 3.3 fineries. Hydrogen requires hydrogen production plants plus shows the investment costs on a $/gge per day basis and on smaller-scale distributed investments by retailers to install a $/LDV basis. This calculation includes only the investment new storage tanks and fuel pumps. The investment costs in building a new form of infrastructure needed to make and for BEVs and PHEVs in Table 3.3 include only the costs deliver the fuel to the customer. It does not include invest- for home, workplace, and public chargers. The centralized ment to expand an already large and functioning infrastruc- infrastructure for CNG has already been built, and so the ture associated with producing more of the basic resource. incremental CNG infrastructure costs include home fueling For instance, for hydrogen made from natural gas, the systems (paid for by car owners), or new filling stations (paid investment cost includes the cost of converting natural gas to for by retailers). Thus, the infrastructure requirements vary hydrogen, pipelines to deliver the hydrogen, and the full cost from a few very large, multibillion-dollar investments (e.g., of a hydrogen station, but it does not include investments to for biorefineries) made by a few decision makers in industry, produce natural gas or deliver it to a plant. A complete list of to millions of small multithousand-dollar investments made which costs are included or excluded is shown in Appendix by millions of decision makers such as consumers, ratepay- G.2 “Infrastructure Initial Investment Cost.” Details for these ers, and retailers. investment costs are found in the individual fuel sections below in this chapter. Finding: The investment cost for a new fuel infrastruc- The investment cost for a new petroleum refinery is ture using electricity, biofuels, or hydrogen is in the included in Table 3.3 for perspective. However, with increas- range of $2,000 to $3,000 per LDV. This is a significant ing fuel economy for the LDV fleet, no new refinery capac- barrier to large-scale deployment when compared with ity will be needed during the study period. So in effect an infrastructure cost for using petroleum of only about the initial investment cost for gasoline is near zero. The $530 per LDV. alternative-fuel-producing industry, in 2030, must make a $1,000 to $3,000 investment for each new alternative-fuel 3.1.7  GHG Emissions from the Production and Use of LDV, whereas almost none is needed for new petroleum Alternative Fuels gasoline LDVs. This cost differential is a major barrier to large-scale deployment of alternative fuels. Operational and infrastructure costs (as noted in Tables The scale, pace, and modularity of the infrastructure 3.2 and 3.3) are critical factors to consider for deployment. investments vary for the different vehicles and fuels. These However, the net GHG emissions for the different vehicle differences are noted in the right-most column of Table 3.3. and fuel options need to be examined to determine how the Two basic categories are used to describe the infrastructure goal of 80 percent GHG reduction could be met. The esti- requirements: centralized and distributed. Centralized infra- mates of annual GHG emissions in 2030 for different vehicle structure investments are those that are borne by a select and fuel options are shown in Table 3.4. number of decision makers. For example, the infrastructure Each vehicle and fuel option has a range of net annual for CTL, GTL, or gasoline requires large-scale plants (which GHG emissions because GHG emissions depend on how cost billions of dollars each) that individual companies would the fuels are produced. The range of net GHG emissions pay for. Biofuels require large-scale investments for biore- for biofuels is large because the net GHG emissions depend TABLE 3.3  2030 Fuel Infrastructure Initial Investment Costs per Vehicle Infrastructure LDV Fuel Use Investment Cost Alternative Fuel 2030 Investment Cost per Day ($/vehicle) Cost Burden Electricity BEV $330/kWh per day 8.9 kWh 2,930 Distributed (car owners, ratepayers) Electricity (PHEV40) $530/kWh per day 5.4 kWh 2,880 Distributed (car owners, ratepayers) Biofuel (thermochemical) $3,100/gge per day 0.89 gge 2,760 Centralized (industry) CTL (with CCS) $2,500/gge per day 0.89 gge 2,220 Centralized (industry) Hydrogen (with CCS) $3,890/gge per day 0.45 gge 1,750 Centralized (industry) and distributed (retailers) GTL $1,900/gge per day 0.89 gge 1,690 Centralized (industry) Natural gas—CNG $910/gge per day 0.89 gge 810 Distributed (retailers and car owners) Electricity (PHEV10) $370/kWh per day 1.75 kWh 650 Distributed (car owners, ratepayers) Gasoline (new refinery—if needed) $595/gge per day 0.89 gge 530 Centralized (industry) NOTE: Basis: 13,000 mi/yr and 40 mpgge for liquid and natural gas vehicles, 80 mpgge for hydrogen, and 4.0 mi/kWh for electric vehicles. PHEV10 gets 20 percent of miles on electric; PHEV40 gets 60 percent. Investment costs are explained in the individual fuel sections.

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46 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS TABLE 3.4  Estimates of 2030 Annual Net GHG Finding: The GHG emissions from producing biofuels, Emissions per Light-Duty Vehicle Used in the Modeling in electricity, and hydrogen can vary depending on the basic Later Chapters resource type and conversion methods used. Making Annual these fuels with methods involving very low GHG emis- GHGs sions increases the technical and cost hurdles, especially Net GHG Emissions during the introductory period. Actions to encourage the Emissions Annual per LDV use of these more challenging methods should be timed to Fuel (kg CO2e) Use (kg CO2e) coincide with large-scale deployment and not be a burden CTL with CCS 12.29/gge 325 gge 4,000 during the introductory period for the fuel. Needed policy GTL 11.47/gge 325 gge 3,730 actions for each fuel pathway are listed in Appendix G.3. Gasoline 11.17/gge 325 gge 3,630 PHEV10 0.590/kWh 650 kWh 380 3,290 11.17/gge 260 gge 2,910 Natural gas 9.20/gge 325 gge 2,990 3.2 BIOFUELS PHEV40 0.590/kWh 1,950 kWh 1,146 2,600 11.1/gge 130 gge 1,454 3.2.1 Current Status Hydrogen—low cost 12.2/gge 165 gge 2,010 BEV—reference grid 0.590/kWh 3,250 kWh 1,920 Biofuel is a generic term that refers to any liquid fuel pro- Biofuel—with ILUCa 5.0/gge 325 gge 1,620 duced from a biomass source. A number of different biofuel BEV—low-GHG grid 0.317/kWh 3,250 kWh 1,030 products (e.g., biobutanol and drop-in biofuels9) derived Biofuel—without ILUC 3.2/gge 325 gge 1,040 from different feedstocks (e.g., lignocellulosic10 biomass and Hydrogen—with CCS 5.1/gge 165 gge 840 algae) have been proposed, but only corn-grain ethanol and Hydrogen—low-GHG case 2.6/gge 165 gge 430 Biofuel—with ILUC,CCS –9.0/gge 325 gge –2925 biodiesel were produced in commercially relevant quantities in the United States as of the drafting of this report. Ethanol aIndirect land-use changes (ILUC) can have large impacts on net GHG and biodiesel have been of interest because they can be easily emissions but can vary considerably. Basis: 13,000 mi/yr and 40 mpgge for liquid and NGVs, 80 mpgge for synthesized using well-known processes from commercially hydrogen and 4.0 miles/kWh for electric vehicles. PHEV10 gets 20 percent available agricultural products (such as corn and soybeans of miles on electric; PHEV40 gets 60 percent. GHG estimates are explained in the United States, sugar cane in Brazil, and other oil in the individual fuel sections. seeds elsewhere). However, neither ethanol nor biodiesel is fully fungible with the current infrastructure and LDV fleet designed for petroleum-based fuels. Ethanol and biodiesel are usually shipped separately and blended into the fuel at the final distribution point. Ethanol on many factors, including the type of feedstock used,7 the can be blended into gasoline in various proportions but has management practices used to grow biomass (e.g., overuse only about two-thirds of the volumetric energy content of of nitrogen fertilizer could increase N2O flux), any land-use petroleum-based gasoline. As of 2011, ethanol supplied changes associated with feedstock production,8 and the use almost 10 percent by volume of the U.S. gasoline demand of carbon capture and storage (CCS) with biofuel produc- (Figure 3.1). Biodiesel, produced via the transesterification tion. The range of differences for a BEV is determined by of various vegetable oils or animal fats, supplied less than the average GHG emissions of the grid and over time may be 1 percent of U.S. transportation fuel demand in 2011 (see quite different than shown in Table 3.4. Hydrogen has a large Figure 3.1). U.S. biodiesel production capacity was about 2.7 range of possible GHGs determined by the several different billion gal/yr in 2010 (NBB, 2010), but actual production is choices of production method. significantly lower. Biomass can also be used to synthesize The net GHG emissions from the three typical alternative drop-in fuels, that is, synthetic hydrocarbons that would be fuels—biofuels, hydrogen, and electricity—can be either fully fungible with existing infrastructure and vehicles. high or low depending on technology choices, carbon costs, The EISA included an amendment to the Renewable regulations, and other factors. Choices driven by technology, Fuel Standard in the Energy Policy Act (EPAct) of 2005. economics, and policy determine the GHG emissions for RFS2 mandated an increase of over 200 percent in the use future alternative fuels. of biofuels between 2009 and 2022. (See Box 1.1 in Chap- ter 1.) Biofuels, including corn-grain ethanol and biodiesel, currently require government subsidies or mandates to com- pete economically with petroleum-based fuels. Increases in 7  Corn-grain ethanol is likely to have different net GHG emissions than ethanol consumption can also be limited by the “blend wall” cellulosic biofuel. 8  Uncertainties in GHG emissions from land-use changes are a key con- 9  Biofuels that are compatible with existing infrastructure and internal tributor to the wide range of estimates for net GHG emissions from biofuels. combustion engine vehicles (ICEVs) for petroleum-based fuels. Some biofuel feedstock such as corn stover would not contribute much to 10 Plant biomass composed primarily of cellulose, hemicellulose, and GHG emissions from land-use changes. lignin.

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ALTERNATIVE FUELS 47 14 Ethanol 12 Biodiesel Quantities Produced 10 (Billion Gallons) 8 6 4 2 0 2000 2002 2004 2006 2008 2010 2012 Year FIGURE 3.1  Amount of fuel ethanol produced in the United States. SOURCE: Data from EIA (2012b,c). 3-1.eps (NRC, 2011). In 2010, the U.S. Environmental Protection Although the use of corn-grain ethanol can reduce petro- Agency (EPA) approved the use of E15 in internal combus- leum imports, its effects on GHG emissions are ambiguous. tion engine vehicles (ICEVs) of model year 2001 or newer Life-cycle assessments by various authors have estimated a in response to a waiver request by Growth Energy and 54 0 to 20 percent reduction in GHG emissions from corn-grain ethanol manufacturers. Although EPA approved the use of ethanol, relative to gasoline (Farrell et al., 2006; Hill et al., E15 in 2010, its sale just began in July 2012 (Wald, 2012). In 2006; Hertel et al., 2010; Mullins et al., 2010). April 2012, EPA approved 20 companies for the manufacture The EISA requires the use of additional advanced and of E15 (EPA, 2012a).11 Without an approved method for cellulosic biofuels that will reduce petroleum imports, lower eliminating misfueling of older cars,12 increased ethanol use CO2e emissions, and be produced predominantly from is likely to be constrained in the near term. In addition, auto lignocellulosic biomass. (See Appendix G.1 for definitions manufacturers do not recommend using E15 in any vehicles of biofuels in EISA.) To qualify as an advanced biofuel, a that were initially designed to use E10 because of concerns biofuel would have to reduce life-cycle GHG emissions by that E15 might damage older engines (McAllister, 2012). at least 50 percent compared with petroleum-based fuels.14 Flex-fuel vehicles (FFVs) can use higher concentrations To qualify as a cellulosic biofuel, a biofuel would have to be of ethanol (up to 85 percent), and many auto manufacturers produced from cellulose, hemicellulose, or lignin and reduce produce flex-fuel vehicles because of the CAFE credit13 they life-cycle GHG emissions by at least 60 percent compared receive (DOE-EERE, 2012c). However, the number of E85 with petroleum-based fuels. Although RFS2 specified life- fueling stations is limited (about 2,500 stations across the cycle GHG reduction thresholds for each type of fuel and United States) and varies by state (DOE-EERE, 2012a). The EPA makes regulatory determinations accordingly, the actual price of E85 has always been higher than petroleum-based life-cycle GHG emissions of biofuels could span a wide gasoline on an equivalent energy content basis. range (NRC, 2011). Biofuels facilities that began construc- tion after 2007 would have to be individually certified for 11  When the U.S. Environmental Protection Agency (EPA) approves a new both biomass source and production pathway to qualify for fuel or fuel component, EPA only evaluates the fuel’s impact on the emission renewable identification numbers (RINs).15 control system and its ability to meet the evaporative and tailpipe emission The U.S. government and private investors have invested standards. EPA does not evaluate the impact of the new fuel on any other aspect of vehicle performance, including degradation of vehicle components billions of dollars to develop cellulosic biofuels (see Tables and performance that are not associated with the emission control system. 12  The Renewable Fuels Association submitted a Model E15 Misfueling 14  In its Renewable Fuel Standard Program (RFS2) Regulatory Impact Mitigation Plan to EPA for review and approval on March 2012. The plan Analysis (EPA, 2010b), EPA determined the life-cycle GHG emissions to includes fuel labeling to inform customers, a product transfer documenta- be 19,200 g CO2e/million Btu for petroleum-based gasoline and 17,998 g tion requirement, and outreach to public and stakeholders. However, those CO2e/million Btu for petroleum-based diesel. measures will not eliminate the possibility of accidental misfueling. 15  The Renewable Identification Number (RIN) system was created by 13  CAFE credits were used to incentivize vehicle manufacturers to sell EPA to facilitate tracking of compliance with RFS. A RIN is a 38-character large numbers of vehicles that run on natural gas or alcohol fuels. See numeric code that corresponds to a volume of renewable fuel produced in Chapter 6 for details. or imported into the United States.

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48 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS 2.3 and 2.4 in NRC, 2011); however, no commercially viable Finding: Sufficient biomass could be produced in 2050, processes are operational as of the drafting of this report. when converted with current biofuel technology and Initial research focused on cellulosic ethanol; however, consumed in vehicles with improved efficiencies consis- the difficulties associated with integrating ethanol into the tent with those developed by the committee in Chapter 2 existing fuel distribution system and the inability to increase (about a factor-of-four reduction in fuel consumption per ethanol yields to the desired levels have resulted in a shift mile by 2050), that the goal of an 80 percent reduction in in research emphasis away from the biochemical conver- annual petroleum use could be met.16 sion processes to the thermochemical or hybrid conversion processes. Conversion processes of lignocellulosic biomass 3.2.4  Conversion Processes to fuels are discussed below in this chapter. Several technologies can be used to process biomass into liquid transportation fuels for the existing LDV fleet. 3.2.2 Capabilities Converting corn starch to ethanol and converting vegetable The production potential of cellulosic biofuels is deter- and animal fats to biodiesel or renewable (green) diesel are mined by the ability to grow and harvest biomass and the well-established commercial technologies. As of 2012, the conversion efficiency of the processes for converting the collective capacity of corn-grain ethanol and biodiesel refin- biomass into a liquid fuel. Many studies have been published, eries in the United States is sufficient to essentially meet the and they show that the currently demonstrated conversion 2022 RFS2 consumption mandates for conventional biofuels potential is about 46-64 gge/ton of dry biomass feedstock and biomass-based diesel. (as summarized in NRC, 2011). This represents an energy- There are a number of potential processes for converting conversion efficiency to liquid fuel of 25 to 50 percent based cellulosic biomass into liquid transportation fuels. Demon- on the ratio of the lower heating value of the fuel product to stration facilities have been built for some of the various that of the biomass feedstock. Much of the balance of the technologies. Much of the focus on cellulosic biofuel has biomass-energy content is used to produce electricity and to switched away from ethanol to producing a biofuel that is power the conversion processes. a drop-in fuel. Three main pathways are being developed to produce cellulosic biofuels: biochemical, thermochemical, and a 3.2.3 Biomass Availability hybrid of thermochemical and biochemical pathways. The Multiple potential sources of lignocellulosic biomass pathways are discussed in detail in the report Liquid Trans- can be used to produce biofuels. They include crop residues portation Fuels from Coal and Biomass: Technological such as corn stover and wheat straw, fast-growing perennial Status, Costs, and Environmental Impacts (NAS-NAE-NRC, grasses such as switchgrass and Miscanthus, whole trees and 2009b). Briefly, biochemical processes use biological agents wood waste, municipal solid waste, and algae. Each potential at relatively low temperatures and pressures to convert the source has a production limit. The consumptive water use and cellulosic material to biofuels—primarily ethanol and higher other environmental effects of producing biomass for fuels alcohols. are discussed in detail in Renewable Fuel Standard: Potential Thermochemical conversion uses heat, pressure, and Economic and Environmental Effects of U.S. Biofuel Policy chemicals to break the chemical bonds of the biomass and (NRC, 2011). transform the biomass into many different products. Three Several studies have been published on the estimated main pathways are being considered for thermochemical amount of biomass that can be sustainably produced in conversion: gasification followed by Fischer-Tropsch (FT) the United States (NAS-NAE-NRC, 2009b; DOE, 2011; catalytic processing to make naphtha and diesel, gasifica- NRC, 2011, and references cited therein). All of the studies tion followed by conversion of the syngas into methanol focused on meeting particular production goals and none and subsequent conversion into gasoline via the methanol- of them projected biomass availability beyond 2030; they to-gasoline (MTG) process, and pyrolysis (either high- are discussed in Appendix G.4. The studies had different temperature or lower-temperature hydropyrolysis) followed target production dates ranging from 2020 to 2030. The by hydroprocessing of the pyrolysis oil to produce gasoline most recent study (DOE, 2011) projected that 767 million and diesel. Other thermochemical pathways are also under tons of additional biomass (above that currently consumed) development. Thermochemical and biochemical processes could be available in 2030 at a farm gate price of less than can be combined—for example, gasification of the biomass $60/ton. This estimate was based on an annual yield growth followed by fermentation of the syngas to produce ethanol of 1 percent and would require a shift of 22 million acres of or other alcohols. cropland (or 5 percent of 2011 cropland) and 41 million acres of pastureland (or 7 percent of 2011 pastureland) into energy crop production. That amount was assumed to be available in 2050 in this report. 16  See Chapter 5 modeling results for further detail.

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ALTERNATIVE FUELS 49 3.2.5 Costs of economies of scale and improvements in the process con- figurations. Biorefineries that are bigger and more efficient The economics of biofuel production have been discussed than the first-mover facilities will be built as engineering and in a number of studies. Both NAS-NAE-NRC (2009b) and construction techniques are refined over time. The analysis is NRC (2011) compared recent information to develop com- this chapter assumes that yields will increase from a baseline parative economics. The report Renewable Fuel Standard: of 55 gge per dry ton in 2012 at a rate of 0.5 percent per year Potential Economic and Environmental Effects of U.S. Bio- to a yield of 64 gge per dry ton by 2028. The capital costs are fuel Policy (NRC, 2011) and the references cited therein form assumed to decrease by 1 percent per year through 2050 for the bases for the discussion of economics in this chapter. an overall reduction in capital cost of 31 percent compared Conversion of cellulosic biomass to drop-in biofuels is a to the present cost. The capital costs given in this report are relatively new and evolving suite of technologies. Predicting for fully engineered facilities for a relatively new technol- the future developments that can lower the cost of biofuel ogy. Others (Wright et al., 2010) have estimated a 60 percent production is difficult. The cost of production is primarily a decrease in capital costs as the technology evolves. Figure function of the cost of biomass, the yield of biofuels, and the 3.2 shows the current and future costs to produce cellulosic capital investment required to build the biofuel conversion biofuels based on these assumptions and the assumption that facility. Current conversion efficiencies are 46-64 gge/ton of bioenergy feedstock is $75 or $133 per dry ton. Current esti- dry biomass (which gives an average value of 55 gge per dry mates are for a biomass cost of $75 per ton, but a sensitivity ton with a range of ±9 gge per dry ton). to a higher cost is also included (see Figure 3.2). Current capital costs to build a cellulosic biorefinery vary Table 3.5 is a summary of projections of cellulosic bio- between 10 and 15 $/gge per year for all of the technologies fuels that could be available, in addition to the 2012 ethanol discussed above. Thus, a biorefinery that would produce 36 and biodiesel production of 14 to 15 billion gal/yr, using million gge/yr consumes about 2,000 dry tons of biomass per different investment rates for new plant capacity. This com- day. The biorefinery would cost between $360 million and mittee estimated that about 45 billion gge of biofuel would $540 million to build. An average capital cost would be 12.5 be required to meet the target of 80 percent reduction in ± 2.5 $/gge per year. Because biorefining is a developing and petroleum use for the LDV fleet in 2050 and would require evolving technology, it is reasonable to assume that yields about 703 million dry tons per year of biomass feedstock. will increase and that the capital costs will decrease as the A uniform annual construction rate of about $10 billion per technology matures. Yields will increase because of improve- year can easily produce the projected biofuel needs in 2050. ments in the catalysts used and in the process configurations. The fuel availabilities are based on the projections discussed The capital costs are expected to decline primarily because 6 Cost of Biomass $75/ton $133/ton 5 4 Cost of Production (Dollars Per gge) 3 2 1 0 2000 2010 2020 2030 2040 2050 2060 Year FIGURE 3.2  Sensitivity of biofuel cost to biomass cost. 3-2.eps

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50 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS TABLE 3.5  Estimates of Future Biofuel Availability needed to transport the biofuels from the conversion facili- Annual Plant Investment Rate ties to the existing petroleum product distribution system. (billion dollars per year) Although drop-in biofuels can use the existing petroleum- 1 4 7.2 10.4 product distribution system, feeder lines will most likely be required between the biorefineries and the major petroleum Biofuel production (billion gge per year) by pipelines. However, adding feeder lines will require a rela- 2022 0.9 3.7 6.7 9.7 tively small incremental investment. 2030 1.8 7.4 13.3 19.2 2050 4.3 17.3 31.2 45.0 3.2.7  Regional or Local Effects Biomass required in 2050 68 270 488 703 (million dry tons per year) Biomass can be grown only in certain parts of the country, Estimated land-use change 5.5 22.2 40.1 57.8 and so the conversion facilities will also be located nearby. (million acres) If drop-in fuels are produced, then the fuels can be shipped Total investment to 2050 38 152 275 396 via the existing system of petroleum-product pipelines. This (billion dollars) system efficiently transports large volumes of petroleum Average number of biorefineries built 2.7 10.8 19.5 28.2 products. Initially, the biofuel refineries will be sited near per year the locations where the lowest-cost biomass is grown or harvested. Many of these locations are in the Southeast   and Midwest United States. The major petroleum pipelines between the Gulf Coast and the Northeast and North Central United States bisect these regions. Tie-ins to these pipeline above. Land requirements are scaled from the U.S. Billion- systems would be relatively short. Ton Update previously discussed (DOE, 2011). Worldwide expenditures on exploration and production of petroleum are high (Milhench and Kurahone, 2011). 3.2.8 Safety For example, ExxonMobil alone invested over $32 billion The chemical properties of drop-in cellulosic biofuels will globally in capital and exploration projects in 2010. The be similar to those of existing, petroleum-based LDV fuels, November 7, 2011, issue of the Oil and Gas Journal (2011) with no additional fuel-related safety hazards. Truck traffic reported that the National Oil Companies of the Middle East in rural areas is expected to increase, which could increase and North Africa planned to invest a total of $140 billion in traffic accidents in these areas. oil and natural gas projects in 2012, with even more invest- ments to follow in coming years. If the biofuels industry grows as projected, many U.S. 3.2.9 Barriers petroleum refineries will close or be converted to biorefin- The primary barrier to displacing petroleum with biofu- eries. Conversion of a petroleum refinery to a biorefinery els is economic. At present, biofuels are more expensive to will be significantly less costly and labor-intensive than the produce than petroleum-based fuels. The corn-grain ethanol construction of a “grass-roots” biorefinery. industry had many years of government subsidies and is In all future years, the amount of biofuels that can be currently supported by the RFS2 consumption mandate. produced will most likely be limited not by biomass avail- Subsidies or mandates are projected to be required to support ability, but rather by the availability of capital to build the cellulosic biofuel unless the price of oil is close to $190/bbl biorefineries. However, a potential investor will not start or conversion costs decline as projected. construction without secure contracts for biomass supply As discussed above and in detail in other reports (NAS- and a guaranteed market for the product.17 NAE-NRC, 2009b; NRC, 2011), ethanol involves definite infrastructure issues. Pure ethanol cannot be used in con- 3.2.6 Infrastructure Needs ventional ICEs because of cold-start problems. It has to be blended with petroleum-based gasoline. The highest content A large number of biomass conversion facilities would allowed in the United States is 85 percent ethanol by volume have to be built along with specialized harvesting equipment (E85). Although E85 could contain up to 85 percent ethanol, and a truck fleet to transport the biomass from the fields to its ethanol content typically averages only 75 percent or even the conversion facilities. Economic studies have shown that less in the winter. the conversion facilities need to be near where the crops are As of 2012, the fuel industry was close to reaching the grown. Therefore, additional product pipelines would be maximum amount of ethanol that can be consumed by blend- 17  Factors that can affect actual supply of biomass for fuels are discussed ing into E10. Total U.S. gasoline consumption in 2010 was in the report Renewable Fuel Standard: Potential Economic and Environ- just over 138 billion gallons. Blending all of this as E10 mental Effects of U.S. Biofuel Policy (NRC, 2011). would consume only 13.8 billion gallons of ethanol, which is

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ALTERNATIVE FUELS 51 less than the 15 billion gallons of conventional ethanol man- TABLE 3.6  Capability of the U.S. Electricity System in dated by RFS2. Fewer than 0.1 billion gallons of E85 were 2010 sold in 2009. As the fuel economy of vehicles improves and Net gasoline sales decline, even less gasoline will be available Summer Electricity to be blended with the volume of ethanol mandated. Drop-in Capacity Production Capacity Source (GW) (thousand GWh) Factor biofuels do not have this limitation. Coal 318.1 1,879.9 0.67 Oil and natural gas steam 113.5 123.9 0.13 3.2.10  GHG Reduction Potential Natural gas combined cycle 198.2 733.8 0.42 Diesel/conventional combustion 138.6 51.0 0.11 There is ongoing debate regarding the GHG emissions turbine from the production of biofuels, including the time profile Nuclear 101.1 802.9 0.90 of the emissions. The uncertainties and variability associated Pumped storage 21.8 –0.2 –0.001 with the GHG reduction potential of biofuels are discussed Renewables 123.0 371.6 0.35 Total 1,014.4 3,962.8 0.45 in detail in NRC (2011). The values for GHG emissions used in this study were a modified version of those developed   by EPA for the RFS2 final regulations. The difference was the treatment of emissions attributable to indirect land-use The average U.S. retail price for electricity is about $0.10/ change (ILUC). The EPA analysis distributes the GHG kWh with substantial variation across the country because of emissions from ILUC over a 30-year period. For the analy- the time of use, local generation mix, and various incentives sis in this report, all emissions contributed by ILUC were or taxes. In general, electricity produced by hydro power attributed to the first year’s operation of the biofuel conver- costs the least, followed closely by coal, nuclear, and natural sion facility rather than spread over 30 years. This alternate gas. Electricity generation from natural gas is expanding ILUC treatment and its impact on annual biofuel GHG rapidly for the following reasons: emissions are discussed in detail in Appendix G.5. These predicted GHG emissions do not include the use of CCS in · The cost of natural gas generation strongly depends the production facility to reduce overall well-to-wheels GHG on the cost of fuel. Currently the cost of natural gas emissions. Applying CCS to a biofuel production facility can is low ($2.5 to $3.5/million Btu) and could remain potentially provide slightly negative well-to-wheels GHG low for a decade or more. emissions (NAS-NAE-NRC, 2009a). · CO2 emissions per unit of power generated by natural gas are about half of the CO2 emissions per unit of power generated by coal. 3.3  ELECTRICITY AS A FUEL FOR LIGHT-DUTY · Emissions of sulfur oxides (SOx), nitrogen oxides VEHICLES (NOx) and other toxic air pollutants from natural gas are much lower than the emissions from coal. 3.3.1 Current Status In the United States, electricity is widely available, plen- Gas turbines are well suited to provide backup power for tiful, and relatively inexpensive. It already is used as fuel intermittent renewable energy generation sources, such as for some LDVs available on the general market, including wind and solar, because they can be ramped up relatively PHEVs (e.g., the Chevrolet Volt) and BEVs (e.g., the Nissan quickly. Because of this characteristic, the share of electricity Leaf). Further, electric-power vehicles are in wide use in generation from natural gas tends to increase as renewable commercial applications such as in warehouses and factories. energy increases. The generation of electricity produces GHG emissions, mainly CO2. In 2010, total GHG emissions from electric power as reported in the AEO 2011 were 2.3 3.3.2 Capabilities billion metric tons CO2e (EIA, 2011a). There are additional Table 3.6 shows the 2010 capability of the U.S. electric- emissions further upstream in the process, for example, in ity system (EIA, 2011a). The capacity factor measures the mining coal, producing natural gas, transporting fuels to ability of a power source to produce power and reflects both the power plant, and building solar panels, wind turbines, availability to produce power and whether or not the plant and power plants. These upstream emissions can be added is dispatched. Capacity factor is estimated as the annual to the combustion emissions to estimate the total life-cycle electricity production for each source divided by the power emission of any process, including electricity generation. production it would have achieved when operating at its net Life-cycle emissions are considered in this report’s analyses summer capacity 24 hours per day for the entire year. Power of GHG emissions. dispatch is affected by the price of the source relative to The capability (and demand) for electricity generation in other competing sources because lower-priced sources are the United States is expected to grow slowly from the pres- dispatched preferentially. ent to 2050. For the purposes of this study, two cases in the

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52 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS AEO 2011 (EIA, 2011a) were examined: the 2011 reference There are no GHG emissions assumed in the AEO case and the GHG price case (hereafter referred to as the cases for nuclear and renewable electricity. The life-cycle low-GHG case). The low-GHG case is based on a steadily emissions for nuclear and renewable energy sources were escalating carbon tax beginning at $25/metric ton of CO2e assumed to be 0.02 kg CO2e/kWh, based on the values used in 2013 and escalating at 5 percent per year, reaching $152/ in the NRC report America’s Energy Future. Technology and metric ton in 2050. The National Energy Modeling System Transformation (NAS-NAE-NRC, 2009a). Table 3.7 sum- (NEMS) is used by EIA to produce the AEO projections up marizes the results for GHG emissions from fuels. to 2035. Therefore, the reference and low-GHG cases had In addition to extending beyond the AEO’s 2035 projec- to be extrapolated to 2050. For the low-GHG case, the total tions, the current study had to verify that the low-GHG case GHG emissions, power output, and cost data were extrapo- still gives the desired result of about an 80 percent reduction lated to 2050 using the years 2031 to 2035 to better capture in GHG emissions by 2050 after all emissions in the life the accelerating effects of the carbon tax increase in shifting cycle are accounted for. The fraction of electricity generated the mix of generation sources. For the reference case, data by each fuel was estimated by extrapolating the 2035 AEO from the period 2020 to 2035 were used because the mix of results to 2050. Because the changes in the fuel mix were generation sources does not change much. accelerating in the latter period of the EIA case, 2031-2035, The low-GHG case shows that the annual GHG emis- the rate in that period was used as a reasonable basis from sions in 2050 are reduced from the reference-case emissions which to extrapolate. The result is shown in Table 3.8, which by more than the desired 80 percent; however, this result indicates that the GHG emissions are still reduced by more does not account for the life-cycle emission effects in the than 80 percent in 2050. electricity-generating sector because in the AEO analyses some of the emissions are attributed to other sectors. To compare fuels used in transportation on a consistent basis, TABLE 3.7  2010 Electricity-Generation GHG Emissions the additional upstream generation of GHG emissions for by Source combusted fuels will have to be included to account for the Combustion Upstream Life-Cycle life-cycle emissions for non-combusted fuels, for example, Emissions Emissions Emissions renewables and nuclear. Source (kg CO2e/kWh) (kg CO2e/kWh) (kg CO2e/kWh) For coal and natural gas, the upstream emission factors Coal 0.9552 0.042 1.0 in the Greenhouse Gases, Regulated Emissions, and Energy Natural gas 0.433 0.123 0.556 Use in Transportation Model (GREET model; Argonne Nuclear 0 0.02 0.02 National Laboratory) were used to calculate the total life- Hydro 0 Renewables 0 0.02 0.02 cycle emissions. The AEO 2011 estimated GHG emissions from coal com- SOURCE: EIA (2011a). bustion to be 0.9552 kg CO2e/kWh.18 For coal, the upstream emissions embedded in the GREET model are 3.74 kg CO2e/ GJ. Using a conversion factor of 1.055 GJ per million Btu TABLE 3.8  Key Parameters of the AEO Base Case and and assuming a heat rate of 10,000 Btu/kWh for the conver- Low-GHG Case sion of coal to electricity, the upstream emissions are 0.04 Parameter 2010 2020 2035 2050 kg CO2e/kWh. Accounting for transmission line losses of 7 AEO base-case cost 9.6 8.8 9.2 9.4 percent, the correction from both upstream and transmission ($/kWh) line losses is an additional 0.042 kg CO2e/kWh, making the AEO low-GHG case 9.6 11.2 12.7 14.8 total emissions for coal-fired electricity 1.0 kg CO2e/kWh. cost ($/kWh) The existing value for natural gas combustion emissions Carbon tax ($/metric 0 35 73 152 in the AEO model is 0.433 kg CO2e/kWh.19 The upstream ton CO2e) GHG emissions for natural gas in the GREET model are 13.4 AEO base-case 3,963 4,158 4,633 5,140 kg CO2e/GJ. The heat rate used in AEO 2011 for converting output natural gas to electricity is 8,160 Btu/kWh. Using this as a (billions kWh) conversion factor, the upstream emissions of natural gas are AEO low-GHG case 3,963 3,823 3,976 4,190 0.115 kg CO2e/kWh. Correcting for transmission line losses output of 7 percent makes the total correction 0.123 kg CO2e/kWh, (billions kWh) and the total GHG emissions for natural gas are 0.556 kg AEO base-case 0.586 0.535 0.545 0.541 CO2e/kWh. GHG emissions (kg CO2e/kWh) AEO low-case GHG 0.586 0.412 0.256 0.111 18  emissions See http://205.254.135.24/oiaf/1605/coefficients.html. 19  (kg CO2e/kWh) See http://205.254.135.24/oiaf/1605/coefficients.html.  

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66 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS The cost estimates for GTL are based on the FT process TABLE 3.18  GTL Outlook Production Estimates economics (see Table 3.17). There are no published data 2020 2035 2050 available for the MTG option. For the purpose of this study, Optimistic outlook capital cost and overall performance data for the MTG   GTL/MTG plants 1 4 12 option are expected to be similar to the numbers presented in   GTL/MTG production, bbl/d 50,000 200,000 600,000 Table 3.17. The investment required for the GTL processes Realistic outlook is lower than the investment estimated for the CTL options.   GTL/MTG plants 1 3 6   GTL/MTG production, bbl/d 50,000 150,000 300,000 This is expected because CTL requires the greater complex- ity of coal gasification and the complex cleaning of the syn-   thesis gas, and because of the fact that half of the coal has to be converted to CO2 (to make hydrogen), which in turn has but does not yield any GHG reduction. Adding CCS to a to be captured and stored (CCS). GTL facility would have a small effect on the life-cycle GHG The cost for the liquid fuel from a GTL plant is about emissions of the fuel produced because the GHG releases $106/bbl in 2035, which is less than the price of crude oil in that could be captured at the conversion facility are small 2035 ($125/bbl) forecasted by EIA (2011a). However, the compared to the CO2 release from combusting the liquid fuel. GTL cost estimate is based on a natural gas price of $7.21/ million cubic feet in 2035, which is lower than natural gas prices in 2008 and earlier. If the price of natural gas were 3.6.5 Infrastructure Needs to reach $10.0/million cubic feet, the liquid product cost Because natural gas is readily available throughout most would increase to $130/bbl. The cost of the liquid product in of the country, there are no major issues with either infra- 2050 is estimated at $109/bbl based on a natural-gas price of structure or the location of GTL facilities. $9.06/million cubic feet. If the natural-gas price were $11.0/ million cubic feet, the liquid-product cost escalates to close to $130/bbl. 3.6.6 Safety Although the GTL process includes a complex step for 3.6.4 Implementation generating synthesis gas, there are no unique safety issues. Natural processing, transmission, and use are widely prac- GTL technology has been commercialized in a number of ticed in the United States. The process of converting natural locations where the price of natural gas is low because those gas to a liquid fuel for LDVs has many similarities to petro- locations are far away from markets where the gas can be leum-refining processes, and well-known safety practices used directly for power and heat generation. Moreover, all the can be applied. GTL facilities are based on producing diesel fuel, naphtha, and in some cases high-value lubricants. When considering the application of GTL technology in 3.6.7 Barriers the United States, two factors need to be considered. First, One important barrier to the wide use of natural gas to the MTG option might be preferred because gasoline is a make liquid fuels is the cost over the life of commercial GTL more widely used transportation fuel than diesel. Second, facilities and the availability of natural gas. Recent technol- the price of natural gas will likely be significantly higher ogy advances for producing gas from tight shales and other in the United States than in other areas of the world where low porosity reservoirs suggest that the natural-gas resources it is readily available (e.g., in the Middle East and in West in the United States are significantly greater than previously Africa) because it can be readily used in heating, power estimated. The resource availability is a positive factor, but generation, petrochemical production, and other industries. the cost and the environmental impact of producing this tight The forecasted production of liquid fuels from natural gas gas are unclear at present. Moreover, natural gas is used in (GTL) assuming an optimistic outlook and a more realistic all sectors of the economy, and the distinct advantage of outlook is summarized in Table 3.18. using natural gas in electricity generation suggests that the The estimates for fuel production from GTL are sensitive demand for gas in this sector could increase dramatically. to natural gas prices. Using the 2011 AEO (EIA, 2011a), the Use of natural gas directly in LDVs is also being proposed. cost of the fuel in 2035 is about $105/bbl, which is lower (See Section 3.5 ,“Natural Gas as an Automobile Fuel.”) The than the crude-oil price forecasted for that year. However, a balance between supply and demand for natural gas in the 25 percent increase in the price of natural gas would raise the United States depends on the level of consumption in many final-product price well above the crude-oil price. sectors and the level of production. Therefore, predicting The GHG emissions for the production of GTL fuel are, the future price of natural gas is difficult. Because the cost as in the case of coal, comparable to the emissions from of the gas feedstock is a major factor in the cost of the GTL producing petroleum-based fuels. Thus, GTL without CCS fuel made, the estimate for total liquid fuels produced from for LDVs reduces the consumption of petroleum-based fuels natural gas in 2050 is less than 600,000 bbl/d in the optimistic

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ALTERNATIVE FUELS 67 case. That production level requires an annual consumption and undergo the required processing steps to make liquid of 1.6 tcf of natural gas, or about 8 percent of the present products from carbon monoxide and hydrogen and remove production in the United States. and compress the CO2. A number of cases presented in NAS-NAE-NRC (2009b) include or exclude CCS, and in other cases the proposed 3.7  LIQUID FUELS FROM COAL facility produces significant amounts of electric power (these are called once-through cases). Although interesting 3.7.1 Current Status synergies have been identified in these schemes, all process Liquid fuels, both gasoline and diesel, have been pro- schemes require different gasification reaction systems for duced from coal at a significant scale since the 1930s. At the coal and for the biomass. They can be viewed as requiring present, the CTL facilities with the largest capacity are in a separate CTL and BTL gasification plants in a given site. South Africa and produce more than 100,000 bbl/d of liquid The number of sites in the United States where there are sig- products. Moreover, a number of proposed facilities are nificant amounts of biomass and coal for commercial-scale being considered in China. facilities might be small. There are two technology options for the production of The potential benefits of combining the gas products from liquid fuels from coal: direct and indirect liquefaction. The the biomass and coal gasification to make liquid fuels and direct liquefaction of coal involves reacting coal with hydro- electric power are clear from the studies available. A CBTL gen or a hydrogen-donating solvent. This technology option facility produces liquid fuels at a higher cost than does a CTL has been the subject of research, development, and pilot- facility but at lower cost than a BTL facility. Moreover, by scale demonstration since the late 1970s. The consensus capturing the CO2 produced in the biomass portion of the view is that this technology is still in development and that facility, the process drastically reduces the life-cycle GHG the complexity of the process scheme and the poor quality of emissions of the liquid fuels (the emissions during their com- the liquid products are major limitations. However, a dem- bustion are counterbalanced by the CO2 taken up during plant onstration facility was built in China, and that facility may growth). The potential benefits of CBTL facilities, while provide a definitive assessment of the coal-to-liquid fuels significant, will require commercial-scale demonstrations option (NMA, 2005; NPC, 2007; NAS-NAE-NRC, 2009b). of BTL technology and combining it with CTL technology. This section focuses on the indirect liquefaction option The CBTL process was not included in the case study that involves the gasification of coal to a mixture of carbon model runs explained in Chapter 5 because it is a derivative monoxide and hydrogen (synthesis gas) followed by the process of two commercially available processes. Coal con- conversion of this gas into liquid products. There are two version and biomass conversion to liquids are individually schemes to make the synthesis gas into liquid-fuel products. included in all of the model scenarios. One option is to convert the synthesis gas into methanol followed by MTG (Zhao et al., 2008). The second option 3.7.2 Capabilities is to convert the synthesis gas into a broad range of hydro- carbons via FT chemistry followed by the hydrocracking of The United States has ample coal resources that can the molecules with more than 20 carbons into shorter-chain allow the production of significant amounts of liquid fuels molecules. The FT option results in a mix of liquid products such as gasoline and diesel from coal. Most coal produced that includes mostly diesel fuel and a significant amount of in the United States (about 1 billion tons per year) is used naphtha that can be upgraded to gasoline. to generate electricity. In principle, additional coal could The commercial-scale facilities in South Africa are be mined to produce liquid fuels because the coal reserves producing diesel and gasoline from coal by the FT option. in the United States are estimated to be in the range of 250 Although the Mobil Corporation operated a facility that billion tons. However, concerns have been raised about the used the MTG option, the feedstock was natural gas rather environmental impact of coal mining and of the disposition than coal. of mineral ash present in coal. Those concerns apply to all In the report Liquid Transportation Fuels from Coal and uses of coal (AAAS, 2009; EPA, 2011a,b). Biomass: Technological Status, Costs, and Environmental The process to convert coal into a liquid fuel is complex Impacts (NAS-NAE-NRC, 2009b), a process scheme labeled and expensive. The gasification of the coal is the most chal- coal-and-biomass to liquid fuel (CBTL) is proposed. The lenging process step. The coal has to be fed into a reactor process uses a separate gasifier for the coal and the biomass that operates at pressures ranging from 20 to 50 atmospheres feedstocks. The effluents from these gasifiers undergo a num- along with pure oxygen and water. The average reactor ber of separation steps to remove solid and gaseous impuri- temperature is about 800°C. Because coal is a solid and its ties. The biomass gasifier effluent also includes a thermal quality varies, the feed system is complex and sensitive to cracking step to convert the tar produced from the biomass the coal quality. Moreover, coal contains a number of impuri- to lighter products. The clean-up streams are then combined ties including mineral ash, sulfur, nitrogen and mercury. A

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68 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS number of process steps are needed to remove the byproducts TABLE 3.19  CTL Outlook Process Data of the gasification reaction to yield a pure stream of carbon CTL/FT 2020 2035 2050 monoxide and hydrogen (KBR, 2011). Coal, tons/d 26,700 26,700 26,700 The second major challenge in making liquid fuels from Fuel production, bbl/d 50,000 50,000 50,000 coal that applies to both the FT and the MTG options is the Investment, $billion 6.0 6.0 5.0 fact that chemistry dictates that two molecules of hydrogen Product cost, $/bbl 126.8 122.5 104.7 react with one molecule of carbon monoxide. Because coal, CO2 coal production, metric tons/d 2,580 2,580 2,580 CO2 vented, metric tons/d 5,011 5,011 5,011 on average, contains only an atom of hydrogen per atom of CO2 stored, metric tons/d 29,208 29,208 29,208 carbon, half of the carbon monoxide produced in the gas- ification step has to be used to make additional hydrogen. CTL/MTG 2020 2035 2050 This is done using the water gas shift reaction where water Coal, tons/d 23,200 23,200 23,200 and carbon monoxide are converted into carbon dioxide and Fuel production, bbl/d 50,000 50,000 50,000 hydrogen. Thus, this reaction step yields the required 2:1 Investment, $billion 5.0 5.0 4.0 mole ratio of hydrogen to carbon monoxide needed for the Product cost, $/bbl 105.2 102.5 86.0 subsequent reaction steps and also produces one molecule CO2 coal prod, metric tons/d 2,243 2,243 2,243 CO2 vented, metric tons/d 5,520 5,520 5,520 of carbon dioxide for each molecule of carbon monoxide. CO2 stored, metric tons/d 23,280 23,280 23,280 In other words, half of the coal is converted to CO2 and the other half into the reactants needed for the next process steps. NOTE: Product cost basis: (1) 20 percent of capital annual charge (financ- ing, return on capital, maintenance), 90 percent capacity utilization (2) $50/ Therefore, CCS is necessary if coal is to be used to make metric ton of CO2 pipelined and stored underground in 2020, $40 in 2035, liquid fuels with life-cycle GHG emissions in the range of and $30 in 2050; (3) coal prices as per AEO 2011 (EIA, 2011a), $1.85/ those from use of petroleum-based fuels. Although there million Btu in 2020, $1.98 in 2035, and $2.00 in 2050; (4) CO2 emissions are a few facilities that use CCS, there is consensus that a from the coal production are based on GREET estimates for the production/ large-scale demonstration in a variety of geological forma- transport of coal. SOURCE: Data from NAS-NAE-NRC (2009b). tions is required before CCS can be deemed commercially acceptable. The conversion of carbon monoxide and hydrogen via MTG or FT to diesel or gasoline presents less of a technol- ogy challenge and, has been done commercially for many for a facility with a 50,000 bbl/d capacity is high and thus years (ExxonMobil, 2009; NAS-NAE-NRC, 2009b). Most has a major impact on the cost of the liquid-fuel product. of the commercial facilities have used or are using natural The cost of the liquid-fuel product made in the CTL facili- gas rather than coal as the feedstock. The use of natural gas ties is within the range of the cost of a barrel of crude oil to make liquid fuels is discussed in a separate section above forecasted for 2035 in the 2011 AEO (EIA, 2011a) and the in this chapter. cost of a barrel of crude oil extrapolated to 2050. However, the CTL estimate is based on a coal price that remains essen- tially constant from the 2009 price; a doubling of the coal 3.7.3 Costs price will yield product costs of over $150/bbl. Conversely, The data presented in Table 3.19 are derived from Liquid coal prices could decrease as a result of increasing use of Transportation Fuels from Coal and Biomass: Technological natural gas or other resources for electricity generation. The Status, Costs, and Environmental Impacts (NAS-NAE-NRC, CTL facilities take a long time to build, and thus their pay- 2009b), which describes in detail the process schemes briefly back requires high product prices for a long period of time. reviewed here. It also described the challenges and potential of the various technology options. It includes estimates of 3.7.4 Infrastructure Needs the capital and operating costs for CTL facilities. Here, the cost of the first CTL facility built by 2035 has The process cost estimate for CTL is based on the facili- been estimated to be 20 percent higher than the facilities ties using Illinois #6 coal and the CTL plants being built built later on. The MTG facility is estimated to be lower in the Midwest. Therefore, the mining and transport of the in capital cost and to require less coal for the same level of coal to the CTL facilities are assumed to be handled within production of 50,000 bbl/d of liquid-fuel product than would the present infrastructure. The liquid-fuel products from the the FT process. The MTG process is more selective than the facilities will be consumed in the Midwest and will be mar- FT process as indicated by the higher energy conversion effi- keted using the present infrastructure. The CO2 is assumed to ciency. Efficiency is the percent of the energy content of the be pipelined and stored underground within a 150-mile range coal that is contained in the liquid produced. The efficiency because geological studies indicate a significant storage in the 50 percent range indicates that close to half of the coal potential in the Illinois Basin (Finley, 2005). Therefore, the has to be converted into CO2. That amount of CO2 has to be main new infrastructure needed will be the pipelines to trans- “stored” via CCS in both cases. The capital cost estimated port the CO2, the injection wells to store it in underground

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ALTERNATIVE FUELS 69 formations, and the equipment to monitor CO2 emissions in TABLE 3.20  CTL Outlook Production Estimates the pipelines and from the underground storage formations. Optimistic Outlook 2020 2035 2050 All of these costs are included by adding $50/metric ton of CTL/FT plants — 1 2 CO2 stored in 2020, $40/metric ton of CO2 stored in 2035, CTL FT production, bbl/d — 50,000 100,000 or $30/metric ton by 2050 to the product cost. CTL/MTG plants — 2 6 CTL/MTG production, bbl/d — 100,000 300,000 Total production, bbl/d — 400,000 150,000 3.7.5 Implementation Realistic Outlook 2020 2035 2050 As mentioned above, CTL technology is used in South Africa at present. The main reason for its commercializa- CTL/FT plants — 1 1 CTL/FT production, bbl/d — 50,000 50,000 tion was the need to provide liquid fuels in a country rich CTL/MTG plants — 2 3 in coal. Another major consideration was the embargo of CTL/MTG production, bbl/d — 100,000 150,000 crude oil and petroleum products imposed on the country Total production, bbl/d — 100,000 200,000 because of its Apartheid Policy. Economic considerations   were, therefore, secondary. While a number of feasibility studies on CTL have been announced in the last 10 years, none of the facilities have reached commercialization. China has been operating a CTL demonstration project (China Shenhua Coal to Liquid and Chemical Co. Ltd., cation, and refining of coal. Thus, CTL safety is expected to 2010; Reuters, 2011). benefit from many decades of prior experience. However, There are major barriers to the widespread commercial- there is much less experience with the safety of pipelining ization of CTL technology. First, the process is complex and storing large quantities of CO2 (at least 9 million metric and costly. Second, large amounts of CO2 generated by tons per year from one CTL facility). Although 3,900 miles the facilities need to be captured and stored. The process of national CO2 pipeline infrastructure exist (Dooley et al., to capture CO2 is based on the absorption of the gas in a 2001) to transport about 65 million metric tons of CO2 each liquid solvent. A number of solvents have been used, and year for enhanced oil recovery (Melzer, 2012), geologic the process is practiced at a commercial scale. It requires a storage of CO2 is only in the demonstration phase (NAS- significant amount of energy, thus reducing the efficiency NAE-NRC, 2009b; see Section 3.8, “Carbon Capture and of the overall process. Third, the transportation and storage Storage,” below in this chapter). The key issue with CCS is to of CO2 add to the cost. The gas would be compressed to a ensure that the CO2 does not leak from either the pipeline or pressure of about 125 atmospheres and then pipelined to a the formation itself. At concentrations higher than 2 percent region where there is a porous underground formation for in air, CO2 can asphyxiate humans and animals (Praxair, storage. Wells will be used to transfer the gas to the for- 2007). Storing CO 2 entails health and ecological risks mation zone, where the gas is expected to either dissolve associated with acute or chronic leaks (NAS-NAE-NRC, in the formation water or be converted to a carbonate salt. 2009b). Clearly, the safety of CCS operations will be a major In 2011, DKRW Advanced Fuels LLC announced that its concern. CCS is being practiced for oil well stimulation in subsidiary, Medicine Bow Fuel and Power LLC, entered the North Sea, Algeria, and Saskatchewan, Canada, but at a into a contract to produce liquid fuels from coal and to sell scale much smaller than what is envisioned for a single CTL the carbon captured for enhanced oil recovery (DKRW facility. There are also a number of pilot demonstrations of Advanced Fuels LLC, 2011). CTL in the United States (NETL, 2011). Two estimates for the eventual production of liquid fuels from coal are presented in Table 3.20. One is an optimistic estimate, and the other one is a realistic outlook. Both esti- 3.7.7 Barriers mates assume that no CTL facilities would be operational An important issue to be considered when estimating the in 2020. The technology requires demonstration that large potential supply of CTL liquids is the actual production of amounts of CO2 can be captured, pipelined, and stored safely, coal with its inherent environmental and safety challenges. and such demonstrations are not expected to be completed If only 500,000 bbl/d of liquid-fuel products are to be pro- until later in this decade. Moreover, the design and construc- duced from coal, 85 million tons of coal would have to be tion of CTL facilities are expected to take at least 5-6 years mined and transported each year. Locating CTL facilities for the first few facilities. close to mines would reduce transportation costs. The coal consumption is equivalent to about 10 percent of the U.S. 3.7.6 Safety coal production in 2012. There also are environmental and safety issues related to the disposal of coal ash from the coal The actual production of liquid fuels from coal presents gasification step. Thus, a major increase in coal consumption the typical safety issues encountered in the handling, gasifi- to make liquid fuels is not likely.

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70 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS The most important barrier to the large-scale use of coal planned or underway in the United States and other regions to make liquid fuels is the GHG emissions from these facili- of the world (NETL, 2007, 2011). ties. The process eventually yields a liquid fuel for LDVs that has chemical properties substantially similar to those 3.8.1.2  Enhanced Oil Recovery (EOR) of petroleum-based fuels. Thus, the carbon content of the fuel is the same as the carbon content of petroleum-based CO2 can be injected into already-developed oil fields fuels. Moreover, the production of CTL fuel with CCS is to recover the oil that is not extracted by initial production estimated to emit at least as much CO2 as the production, techniques. Injected CO2 mixes with the oil in reservoirs and transport and refining of the same fuel from petroleum. For changes the oil’s properties, enabling the oil to flow more CTL fuels to have life-cycle GHG emissions equivalent to freely within the reservoirs and be extracted to the surface. those of petroleum-based fuels, an amount of CO2 equivalent The CO2 is then separated from the extracted oil and injected by weight to the weight of the coal used has to be captured again to extract more oil in a closed-loop system. Once eco- and stored. Thus, CTL technology can reduce the amount of nomically recoverable oil has been extracted from one area petroleum used in LDVs but does not contribute to reducing of a given reservoir, an EOR project operator reallocates GHG emissions. CO2 to other productive areas of the same reservoir. Once all economically recoverable oil has been extracted from a Finding: GTL fuel and CTL fuel with CCS can be used as given reservoir, the CO2 remains within the reservoir and the a direct replacement for petroleum-based fuel. However, project is plugged and abandoned. the GHG emissions from GTL or CTL fuel are slightly higher than those from petroleum-based fuel. The role 3.8.2 Capabilities of GTL and CTL with CCS in reducing petroleum use will thus be small if the goals of reducing petroleum The capture of CO2 from a gaseous stream has been use and reducing GHG emissions are to be achieved practiced commercially for many years—for example, CO2 simultaneously. has been removed from natural gas produced from reservoirs (Statoil, 2010), and the Weyburn project in Saskatchewan, Canada, has used CO2 captured from a North Dakota coal 3.8  CARBON CAPTURE AND STORAGE gasification facility for EOR (Preston et al., 2005, 2009). EOR uses injection of CO2 into a oil reservoir to assist in 3.8.1 Current Status oil production. In the United States, typical EOR uses about In carbon capture and storage, CO2 is captured from 5,000 cubic feet of CO2 per barrel of oil produced (that is, various processes, compressed into supercritical conditions about 160 lb of carbon produce one barrel of oil, which con- to about 125 atmospheres, pipelined, and then injected into tains about 260 lb of carbon). Oil and gas reservoirs are ideal a deep (>2,500 ft), porous subsurface geologic formation. geological storage sites because they have held hydrocarbons Capturing, storing, and transporting CO2 all have commer- for thousands to millions of years and have conditions that cial challenges, but, in most cases, the technologies have allow for CO2 storage. Furthermore, their architecture and been demonstrated or are in the demonstration phase. With properties are well known as a result of exploration for and CCS there are two major options for storage: deep saline production of these hydrocarbons, and infrastructure exists formations and enhanced oil recovery. for CO2 transportation and storage. To calculate the largest amount of CO2 that could be stored by EOR, all the CO2 used is assumed to remain in the 3.8.1.1  Deep Saline Formations ground. The United States produces about 281,000 bbl/d of In the case of a non-hydrocarbon-bearing formation, the crude oil using CO2 EOR (Kuuskaraa et al., 2011). Based CO2 in supercritical state will be dissolved partially in the on the best-case scenario for CO2 use in EOR, this would subsurface formation’s water phase, and the rest will remain sequester 0.26 million metric tons per day of CO2. If all U.S. in a separate phase. In certain formations, the CO2 will react crude oil was produced by EOR, about 2 million metric tons over a very long period of time with the solids and form of CO2 could be stored per day. solid carbonates. These are slow reactions, because it takes The typical process for capturing CO2 is by contacting decades for a significant amount of CO2 to be converted to the gaseous stream with a solvent that absorbs the CO2. A a solid carbonate. Experimental work is being conducted to number of solvents have been used. The CO2 is then desorbed determine the feasibility of extending this concept to storing as a concentrated gas and the solvent reused. This process CO2 in subsea formations. Currently, demonstrations of deep is widely used for processing natural gas streams but much saline formation CCS of more than 1 million metric tons per less used with gaseous streams from coal gasifiers or coal year of CO2 are in progress in a number of locations (Michael combustion units. The key concern is the degradation of the et al., 2010). Additional smaller demonstration projects are solvent by coal-derived impurities in the process gas. Other

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ALTERNATIVE FUELS 71 processes are being considered and developed to reduce the 3.8.5 Barriers cost and energy consumption required. The cost of CCS is significant but probably not the major CO2 compression to about 125 atmospheres for transport implementation barrier. The major barrier is the public and injection is straight forward but consumes a significant acceptance of pipelines, injection wells, and storage of large amount of energy. High-pressure compression is desirable amounts of carbon dioxide in subsurface formations (Court because it reduces the volume of gas being pipelined, and et al., 2012; de Best-Waldhober et al., 2012; Kraeusel and the supercritical state facilitates injection and retention of Moest, 2012), especially if these are near population centers. the CO2 (IPCC, 2005). Leakage of stored CO2 is an issue that is still being inves- Pipelining of CO2 is another conventional and proven tigated through research programs conducted by industry step. The key concern is leakage of CO2 into the atmo- and DOE. Careful design and operation of CCS can likely sphere. An asphyxiant denser than air, CO2 tends to stay prevent and mitigate any potential emissions of CO2, but close to the ground and is not easily dispersed. CO2 is fatal gaining public acceptance is expected to be difficult given at high concentrations and detrimental to humans at lesser the large quantities of CO2 to be transported and stored. A concentrations (Praxair, 2007). Thus, properly designed single CTL facility producing 50,000 bbl/d of liquid fuels CCS facilities will include a CO2 monitoring system and a will require CO2 storage in the range of about 4 million to 9 leak-prevention system. million metric tons per year. Specially designed injection wells are required for CCS. Abandoned oil and gas wells will not be used for CO2 injec- Finding: CCS is a key technology for meeting the study tion into spent oil and gas formations because these wells goals for GHG reductions by 2050. It will be very difficult may not be capable of handling the acidic supercritical CO2, to make large quantities of low-GHG hydrogen without and they may not be properly cemented to ensure that CO2 CCS being widely available. Combining CCS with biofuel does not leak into aquifers used for drinking water. production would improve the chances of meeting the study goals. 3.8.3 Costs The cost of CO2 capture is $30-$40/metric ton of CO2 3.9  RESOURCE NEEDS AND LIMITATIONS for a coal gasifier process stream, about $90/metric ton for a Reducing petroleum consumption and GHG emissions natural gas combined-cycle facility (because of a lower con- from the LDV fleet will have a significant impact on energy centration of CO2 compared to coal gasification), and $70- resource use in the United States. Comparing existing $80/metric ton for coal-fired power facilities (IPCC, 2005). resources with the estimated demands on resources for fuel- Adding in the cost of compression, pipelining, monitoring ing the vehicles in representative scenarios in its analyses, and injection into a suitable formation would increase the the committee here draws conclusions about whether the total cost by $30-40/metric ton (IPCC, 2005). For most CTL projected demands on resources can be met. facilities, the cost of CO2 capture is included in the facility Alternative LDV fuels can be produced from natural design and construction cost. However, additional costs are gas, coal, biomass, or other renewable energy sources, such incurred for compression, pipelining, monitoring, injection, as wind, solar, and hydro power. The U.S. consumption of and storage. These costs are estimated at $40/metric ton of natural gas, coal, and biomass in 2010 is shown in Table 3.21. CO2 in the first-mover facilities (2035 timeframe) and $30/ Of the amounts consumed, 976 million tons of coal and metric ton in facilities built later (2050 timeframe). In cases 7.378 tcf of natural gas were used for electricity generation of CTL where the costs of capture are to be included, $80/ (EIA, 2011b). The biomass was used primarily for power metric ton of CO2 for 2035 and $70/metric ton of CO2 for in wood-processing plants, with some generated electricity 2050 are used. going into the grid. 3.8.4 Infrastructure Needs CCS requires a large infrastructure—primarily the con- TABLE 3.21  U.S. Consumption of Natural Gas, Coal, and struction of pipelines to transport the CO2 from where it is Biomass in 2010 captured to injection wells for storage underground. In the Consumption in Quads United States, potential reservoirs with a capacity for storing (higher heating value) Amount Consumed more than 100 years’ worth of injected CO2 are available Natural gas 24.1 23.4 tcf within 100-150 miles of expected sources in most regions Coal 22.1 1,050 million tons of the country (NACAP, 2012). Biomass 4.30 269 million tons  

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72 TRANSITIONS TO ALTERNATIVE VEHICLES AND FUELS TABLE 3.22  Estimated Amount of Natural Gas Required to Fuel the Entire LDV Fleet via Different Fuel and Vehicle Technologies Natural Gas Required Annually for Different Vehicle-Fuel Combinations (tcf) Year Vehicle Miles Traveled (trillion mi/yr) ICE-CNG ICE-drop-in ICE-Methanol HEV-CNG Electric FCEV 2010 2.784 15.6 23.8 22.9 15.1 7.6 11.7 2030 3.727 10.1 15.5 14.9 8.4 7.5 7.3 2050 5.048 10.0 15.4 14.8 7.9 7.8 7.2   Biomass, coal, and natural gas can all be converted into TABLE 3.23  Effect of the Low-Greenhouse Gas Grid on “drop-in” liquid fuels by several routes (e.g., direct lique- the Mix of Generating Sources faction of biomass or coal, and gasification followed by FT Total Generation (billion kWh/yr) or MTG of all sources). These drop-in fuels will use the 2050 2050 existing petroleum products distribution system and existing Reference Low-GHG vehicles. The use of any of these alternative fuels would be 2009 Grid Grid transparent to the vehicle owner. The remaining alternative Coal without CCS 1,693 2,368 238 fuel and vehicle combinations include electricity in BEVs Coal with CCS 0 15 17 and PHEVs, hydrogen in FCEVs, and natural gas as a Petroleum and natural gas 871 1,290 1,225 vehicle fuel, either directly as CNG or through conversion without CCS to methanol. All of these fuels can be produced from natural Petroleum and natural gas with 0 0 489 CCS gas via mature technologies, and so a meaningful comparison Nuclear 795 855 1,255 would be to calculate the amount of natural gas that would Hydroelectric 274 314 323 be required to fuel the entire LDV fleet via the different fuel Biomass 38 159 179 and vehicle technologies (Table 3.22). The vehicle efficien- Solar 3 21 56 cies are assumed to be the mid-range efficiencies outlined Wind 71 163 330 Other 34 66 66 in Chapter 2. Direct use of CNG as a vehicle fuel is more resource   efficient and less costly than conversion of natural gas to any liquid fuel. The advantages of conversion to a liquid fuel are the use of the current fuel infrastructure, the ease of onboard The largest changes between the reference grid and the storage, and the familiarity of the driving population with liq- low-GHG grid are an almost 90 percent decline in coal uid fuels. Conversion of natural gas to electricity or hydrogen usage, a doubling of natural gas, and a 50 percent increase in as an energy carrier is currently more resource efficient than nuclear power. Total renewable electricity increases by over direct use of natural gas, but direct-use efficiency converges a factor of two and rises from 11 percent of total generation with that for PEVs and FCEVs by 2050 because of the differ- to 23 percent. ences in efficiency improvements with time. Both electricity Table 3.24 shows the fuel usage and resource demands and hydrogen carry additional socioeconomic burdens and for 10 scenarios: five different vehicle mix scenarios, com- infrastructure costs as discussed in previous sections. Elec- pounded with the reference grid and the low-GHG grid case tricity and hydrogen, as well as GTL and methanol, can be and two different resource mixes for producing hydrogen.22 produced from other resources such as coal and biomass. The implementation of these cases would be driven by Electricity and hydrogen can also be produced from nuclear, various government policies. The reference case scenario is solar, and wind power. driven by existing and currently proposed policies for LDV There are two distinct goals for the scenarios evaluated CAFE standards and RFS2. The other cases stress increased by the committee: one goal targets only petroleum reduction, biofuels, PEVs, FCEVs and CNGVs. and the second goal targets reduction of GHG emissions. These scenarios have not been optimized to minimize Both cases use the same vehicle and fuel technologies; costs, resource use, or GHG emissions. The reference sce- however, in the low-GHG cases, the technology and fuels nario reduces petroleum use by 25 percent, and the others used to generate electricity and hydrogen were modified to all meet or exceed the goal of an 80 percent reduction in reduce GHG emissions. The driving force for the low GHG petroleum use. GHG emission reductions are all similar for grid case is discussed above in this chapter. Table 3.23 shows the reference-grid scenarios. Additional reductions in GHG the impact of the low-GHG grid case on the mix of generat- emissions are possible for the electric and hydrogen cases ing sources. 22  These scenarios are described in greater detail in Section 5.3.2.

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ALTERNATIVE FUELS 73 with the use of a low-GHG grid and a change in the mix · Cleaning up the electric grid by 2050, as envisioned of resources used to generate hydrogen. Only the FCEV in 2011 AEO (EIA, 2011a), the basis for this dis- scenario meets the goal of reducing GHG emissions by 80 cussion, will reduce current coal use by 85 percent percent in 2050. The biofuel case can also meet the GHG or about 800 million tons per year, an amount that emissions target if CCS is added to the biorefineries. represents 44 percent of the total annual U.S. railroad The resource demands can be met but involve some freight tonnage. Shipments of biomass could mitigate challenges. The largest changes are needed to achieve a that impact. low-GHG grid. These include an increased use of almost 7 · Most petroleum products are currently shipped long tcf/yr of natural gas (a doubling of the current consumption distances by pipeline. Significant increases in hydro- for electricity), the construction of about fifty 1,000-MW gen or electricity as an LDV fuel would idle a large nuclear power plants and about 100,000 new wind turbines fraction of the petroleum pipeline system. and the capture and storage of more than 200 million metric · The large increase in natural gas consumption would tons/yr of CO2. require a significant expansion in natural gas pipe- The most challenging related demands concern increased lines. Use of hydrogen as an LDV fuel would require use of biomass and natural gas and public acceptance of the construction of an additional hydrogen pipeline construction of a large number of nuclear power plants. As system. discussed above in this chapter, the demand for biomass is · CCS has to be economical and meet stringent per- expected to be achievable and to be less than the biomass formance requirements at large scale. CCS demon- availability estimated in other recent analyses. Shipping and strations at appropriate scale are needed to validate handling the mass and volume of biomass involved will be performance, safety, and costs. challenging. Natural gas demand doubles over the amount currently used to generate electricity. This increase repre- Nearly 50 percent of U.S. petroleum refining output is sents essentially all of the additional natural gas expected to currently used to fuel the LDV fleet. An 80 percent reduction be available for use based on the most recent estimates of in use of petroleum for LDVs will impact the availability future gas availability in the United States. and price of the refining byproducts that are used by other There are important ancillary impacts from these resource industries. demands on the associated infrastructure: TABLE 3.24  Fuel Demands for Illustrative Scenarios and Resources Used Scenario 2005 Actual Reference Biofuels Electric FCEV CNG Petroleum based fuels, billion gge/yr 124.8 93.1 17.2 13.9 3.8 4.1 GTL and CTL, billion gge/yr 0 7.7 7.7 7.7 0.8 0.8 Total biofuels, billion gge/yr 4.9 24.1 55.9 24.1 19.2 19.1 Electricity, billion gge/yr 0 1.3 0 14.4 1.6 1.0 Hydrogen, billion gge/yr 0 0.5 0 1.1 33.5 0.5 CNG, billion gge/yr 0.1 0.1 0.1 0.1 0.1 51.0 Petroleum reduction, % 25.4 86.2 88.9 97.0 96.7 Ethanol, % of liquid fuels 5.6 11.9 17.5 30.9 30.7 33.9 Resources Used to Power Vehicles, Reference Electric Grid Corn, million tons/yr 81 165 165 165 84 99 Other biomass, million tons/yr 0 208 703 220 325 208 Natural gas, billion cubic ft/yr 18 1,021 888 1,915 3,038 6,969 Coal, million tons/yr 0 50 39 150 108 14 Net GHG emissions reduction, % — 11 67 55 60 56 Resources Used to Power Vehicles, Low GHG Electric Grid and Hydrogen Production Corn, million tons/yr 81 165 165 165 84 99 Other biomass, million tons/yr 0 209 703 226 358 209 Natural gas, billion cubic ft/yr 18 1,105 890 2,613 4,664 7,039 Coal, million tons/yr 0 41 39 54 15 6 Net GHG emissions reduction, % — 13 67 72 85 58  

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