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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
6
Hydrogen and Alternative Technologies for Reduction of U.S. Oil Use and CO2 Emissions
Estimating future transportation fuel use is difficult because of the complexities and uncertainties inherent in the analysis. Petroleum may continue to be the dominant fuel, or production may become constrained and prices rise much further. Hydrogen may replace petroleum as the main fuel, or it may not become significant at all. As discussed in Chapter 3, fuel cell vehicles and hydrogen have the potential to become competitive with conventional vehicles and fuels, but it is far from certain when that might be. Competitiveness depends in part on the cost of petroleum, which itself is highly uncertain, as witnessed by recent dramatic escalations in world oil prices. Nevertheless, as discussed in Chapter 2, there appear to be compelling reasons why the nation may have to reduce its use of petroleum, and hydrogen is among the leading candidates proposed to achieve dramatic reductions. Moving to a hydrogen-based transportation sector would be a revolutionary change that is unlikely to happen by itself. Mapping a route is essential to understanding how such a change might happen. Toward that end, this chapter formulates and analyzes several scenarios to map plausible futures for the use and impacts of hydrogen fuel cell vehicles (HFCVs) and other alternative vehicles and fuels. The scenarios and analyses necessarily depend on a host of assumptions. None of the scenarios should be viewed as projections of what the committee thinks is likely to happen. Rather, they are intended to describe different paths along which events may unfold and the consequences, especially for oil consumption and carbon dioxide emissions.
SCENARIOS AND ANALYSIS
Scenarios
The main object of the scenario analysis is to estimate the maximum practicable penetration rate of fuel cell vehicles, and then to estimate the resulting reductions of petroleum use and emissions of carbon dioxide (CO2) in 2020 and beyond; period to bring hydrogen fuel cell vehicle technologies to cost competitiveness with gasoline vehicle technology; and the costs for a future hydrogen infrastructure. The committee developed three scenarios in order to investigate the range of possible outcomes. The hydrogen scenario analyses are based on the results presented in Chapter 3. In addition, as discussed in Chapter 4, hydrogen is not the only way to reduce petroleum use. Two scenarios focused on alternatives are analyzed, and a final scenario looks at combining all the approaches.
Case 1 (Hydrogen Success) assumes that development programs are successful, as shown in Table 6.1, and that policies are implemented to ensure commercial deployment. Hydrogen fuel cell vehicles are introduced starting with a few thousand vehicles in 2012, growing to a fleet of almost 2 million by 2020, 60 million in 2035, and 220 million in 2050 (Figure 6.1). This rapid-growth case corresponds to a scenario recently developed by the U.S. Department of Energy (DOE) to 2025 (Gronich, 2007) and extended by the committee to 2050. By 2050, 80 percent of new vehicles sold are assumed to be HFCVs (Figure 6.2). This is consistent with other recent modeling studies (Greene et al., 2007).
Case 1a (Hydrogen Accelerated) assumes that hydrogen and fuel cell vehicles are introduced at twice the rate of Case 1, although technical and cost goals are met at the same rate as Case 1. By 2020, 4 million hydrogen fuel cell vehicles are in the fleet. By 2050, 95 percent of new vehicles sold are assumed to be HFCVs This case is intended to investigate whether hydrogen could replace even more oil than in Case 1 if the nation faces a crisis situation, perhaps from declining worldwide petroleum production or rapidly worsening global climate change.
Case 1b (Hydrogen Partial Success) assumes that developing programs fall short of the costs and performance of Case 1 (Hydrogen Success). Thus, the market introduction rate is slower than for Case 1, similar to DOE’s “Scenario the investments that would be needed during a transition 1” (Gronich, 2007). By 2020, fewer than 1 million HFCVs
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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
TABLE 6.1 Assumed Cost and Performance of Hydrogen Fuel Cell Vehicles and Gasoline Reference Vehiclesa
Case 1: Hydrogen Success
Case 1b: Hydrogen Partial Success
Reference Gasoline ICEV (AEO 2008)
Efficient Gasoline ICEV (Case 2)
FC drivetrain retail price (including fuel cell and hydrogen storage
Costs fall with learning and manufacturing scale to $100/kW
Costs fall with learning and manufacturing scale to $130/kW
$54/kW
$64/kW
HFCV retail price increment compared to gasoline reference vehicle
>$100,000 (initially) → $3,600 (learned out)
>$100,000 (initially)→ $6,100 (learned out)
—
$1,000
FCV market Introduction
2012 (Case 1)
2010 (Case 1a)
2015
—
—
New car fuel economya
51 mpgge (2015) → 85 mpgge (2050) = 2 × efficient gasoline case
45 mpgge (2015) → 73 mpgge (2050) = 1.75 × efficient gasoline case
2005: 20.2 mpg
2015: 25.0
2050: 31.7
20.2 mpg
25.2
42.4
NOTE: Case 1a, Hydrogen Accelerated, is the same as Case 1, Hydrogen Success, for these values. Costs and fuel economy of HFCVs are based on a reference midsize vehicle with an 80 kW fuel cell. While small relative to most current engines, this would give equivalent performance, in part because of weight reductions in the body. This vehicle is assumed to represent the range of vehicles from small to large. Given all the other uncertainties in this analysis and the limited resources available to the committee, this assumption was both reasonable and unavoidable.
aOn-road fuel economy is assumed to be 80 percent of the EPA average.
FIGURE 6.1 Hydrogen cases: Number of gasoline and hydrogen fuel cell vehicles in the fleet over time for three hydrogen cases.
are on the road, about the same rate of market penetration as hybrid electric vehicles have experienced.
Case 2 (ICEV Efficiency) investigates the impact of improving conventional internal combustion engine ICEV fuel economy with currently feasible and expected technology. Fuel economy more than doubles by 2050, as shown in Table 6.1, in the committee’s judgment the maximum practical rate with evolutionary vehicle technology. This analysis is based on the results in Chapter 4.
FIGURE 6.2 Hydrogen cases: Fraction of new gasoline and hydrogen vehicles sold each year.
Case 3 (Biofuels) examines the large-scale use of biofuels production from crop and cellulosic feedstocks. This level of production, equivalent to a maximum practical rate, is based on the results in Chapter 4.
Case 4 (Portfolio), “all of the above,” analyzes the impact if HFCVs, more efficient conventional vehicles, and biofuels are all pursued simultaneously.
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TABLE 6.2 Hydrogen Supply Pathways Considered in This Analysis
Resource
Hydrogen Production Technology
Hydrogen Delivery Method to Station (for Central Plants)
Natural gas
Steam methane reformation (on-site)a
Steam methane reforming (central plant)
N/A
Liquid hydrogen truck
Compressed gas truck
Hydrogen gas pipeline
Coal
Coal gasification with carbon capture and sequestration (central plant)
Liquid hydrogen truck
Compressed hydrogen gas truck
Hydrogen gas pipeline
Biomass (agricultural, forest, and urban wastes)
Biomass gasification (central plant)
Liquid hydrogen truck
Compressed hydrogen gas truck
Hydrogen gas pipeline
On-site reforming of ethanol
N/A
Electricity (from various electric generation resources)
Water electrolysis (on-site)
N/A
NOTE: N/A = not applicable.
aOn-site refers to hydrogen production at the refueling station.
These scenarios are compared to a reference case, based on the Energy Information Agency (EIA) 2008 Annual Energy Outlook (EIA, 2008). The committee selected the AEO high-oil-price scenario for its reference case as being more representative of conditions under which HFCVs are promoted than the AEO reference case.1 This scenario includes improvements of gasoline ICEV technology to meet CAFE (corporate average fuel economy) standards, although fuel economy continues to grow slowly after 2020, and some use of biofuels (blending up to 10 percent ethanol) but no introduction of hydrogen or advanced ICEV technology. Gasoline taxes continue as per AEO 2008.
The time frame for analysis is 2008 to 2050. The committee agreed that HFCVs were not likely to make a large impact on U.S. oil use and greenhouse gas emissions by 2020, because they are unlikely to enter the market before 2012-2018, and then it will take time to build up a large enough number of vehicles to impact oil use and carbon emissions significantly. The committee recognizes that uncertainties increase in such a long-term analysis, but it was necessary for examining the time frame during which hydrogen could have a large impact.
Technologies Considered
Hydrogen and fuel cell technologies are based on technologies currently in development, as discussed in Chapter 3 and recently reviewed in the National Research Council (NRC) FreedomCar Fuel Partnership report (NRC, 2008). Available hydrogen supply pathways are listed in Table 6.2. Hydrogen production or storage technologies that would require fundamental scientific breakthroughs (for example, hydrogen storage in carbon nanostructures or biological production of hydrogen by algae) are not considered.
Cost and performance data for current and midterm (2015-2030) hydrogen infrastructure technologies are discussed in Chapter 3. Efficiency improvements in ICEVs and biofuels are described in Chapter 4.
Modeling Tools for Scenario Analysis
The committee developed two EXCEL-based models for infrastructure and scenario analysis:
Hydrogen infrastructure model: designs and costs hydrogen infrastructure to meet a specified market penetration for HFCVs.
Simplified transition model: estimates investment to bring HFCV costs to competitive levels, investment costs for building hydrogen infrastructure, oil savings, and greenhouse gas emission reductions,2 over time.
The models were developed at the University of California at Davis (UC Davis) and are described in detail in Appendix C. Given the time and resources available to the committee, the models were of necessity relatively simple, but they
1
In this scenario, imported low-sulfur crude oil is projected to cost about $79 per barrel in 2010, rising to $90 in 2015, $102 in 2020, and $119 in 2030 (all in 2006 dollars). Oil was over $130 per barrel in June 2008, but that does not necessarily mean that the AEO numbers are wrong. Other projections are both well above and well below this one.
2
Carbon dioxide is the main greenhouse gas of concern in this analysis, but other gases, especially methane and nitrous oxide, are emitted as part of the full fuel cycle. These are accounted for with global warming equivalency factors, taken from the literature and the GREET model.
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TABLE 6.3 Assumptions in Reference Case
2005
2020
2035
2050
Total number of LDVs (millions)
220
280
331
369
Share of LDV fleet
Gasoline ICEVs
99.8%
96.6%
93.2%
91.4%
Gasoline hybrids
0.3%
3.4%
6.8%
8.6%
New LDVs sold per year (millions)
16.2
18.2
20.8
22.4
Share of New LDVs per year
Gasoline ICEVs
98.6%
94.7%
91.8%
91.1%
Gasoline hybrids
1.4%
5.2%
8.2%
8.9%
Average on-road fuel economy, new gasoline LDVs (mpg)
Gasoline ICEVs
20.2
29.3
30.6
31.7
Gasoline hybrids
32.1
41.0
42.9
44.5
Gasoline price ($/gallon)
2.32
3.19
3.54
3.96
Vehicle-miles traveled (billion per year)
2,556
3,251
4,243
5,364
Gasoline consumed (billion gallons per year) (includes blends of ethanol up to 10%)
124
132
140
157
Ethanol (billion gallons per year) consumed as:
Blend in gasoline to 10%
3.4
12.7
15.6
21
E 85
0.01
0.06
0.20
Greenhouse gas emissions (million tonnes CO2 equivalent per year)
1,345
1,442
1,527
1,710
were quite adequate for the purpose of scoping the potential growth of HFCVs and their impact.
Modeling Assumptions
Only U.S. light-duty vehicles (LDVs) are considered. All scenarios assume the same total number of vehicles and vehicle-miles traveled (VMT) as the reference case.
The AEO high-price case is used as the basis for energy prices.
The real discount rate is 15 percent (no inflation is included).
The costs are given in 2005 constant dollars.
Costs for hydrogen infrastructure technologies (hydrogen production, storage, delivery, refueling stations) draw heavily on DOE’s H2A database (DOE, 2007). Both current and 2015 technology numbers are used where available (for production and refueling station technologies).
HYDROGEN SCENARIO ANALYSIS
Reference Case
Cases 1 through 4 (hydrogen and other alternative fueled vehicle) are compared against a reference case. The reference case is based on the high-price case of the AEO (EIA, 2008), which gives projections to 2030 for vehicle miles traveled, vehicle fuel economy, and vehicle fleet composition based on the DOE National Energy Modeling System (NEMS). For input beyond 2030, a vehicle stock model was adapted from the Argonne National Laboratory VISION model to estimate numbers of LDVs, fuel economy, and vehicle energy use to 2050 (Singh et al., 2003; Argonne, 2007). The vehicle stock model keeps track of what vehicles are in the fleet (vehicles are retired after a certain number of years) as increasing numbers of hydrogen vehicles enter the market, allowing the calculation of energy use and greenhouse gas emissions for each year. Table 6.3 and Figures 6.3 to 6.5 summarize the reference case. After the committee had completed its initial analysis, Congress passed the Energy Independence and Security Act of 2007 (EISA), which included a significant increase in fuel economy standards for vehicles. The reference case reflects this new policy.
The reference case includes modest use of biofuels. In 2030, the reference case assumes that 15 billion gallons of ethanol are used per year, 12 billion from corn ethanol and 3 billion from cellulosic ethanol. This gradually increases to 21 billion gallons per year in 2050 (12 billion gallons from corn, 9 billion gallons from cellulosic feedstocks). This is equivalent to about 8-10 percent ethanol by volume in gasoline after about 2020.3
3
EISA includes ambitious goals for biofuels as well as fuel economy. The goal for 2020 is 36 billion gallons, of which 21 billion would be from advanced processes, such as cellulosic ethanol. The committee decided not to include these goals in its reference case for two reasons. First, the likelihood of meeting the biofuel goals appears to be much lower than for fuel
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FIGURE 6.3 Reference case: Number of light-duty vehicles in the fleet.
FIGURE 6.4 Reference case: Assumed fuel economies for gasoline ICEVs and gasoline hybrid vehicles (HEVs). (The “dip” in hybrid fuel economy in 2004 occurred when hybrid sport utility vehicles and vans entered the market.)
Hydrogen Cases 1, 1a, 1b
Table 6.1 lists cost and performance assumptions for hydrogen fuel cell vehicles and a gasoline reference vehicle for each hydrogen case. HFCV costs are based on an 80 kW fuel cell “engine” with 5 kg (165 kWh) of compressed hydrogen gas stored on board.4 (The drivetrain includes the fuel cell and auxiliaries, a hybrid battery, electric motor, wiring, and hydrogen storage.) This is consistent with the following assumptions:
FIGURE 6.5 Reference case: Assumed biofuel use.
For Cases 1 (Hydrogen Success) and 1a (Accelerated Hydrogen), the fuel cell drivetrain (the fuel cell system, hybrid battery, motor, and auxiliaries) costs the automaker (original equipment manufacturer, or OEM) $50/kW. This corresponds to a fuel cell system cost of $30/kW plus added costs for a hybrid battery, electric motor, and other components. Of the $30/kW fuel cell system cost, about half is due to the fuel cell stack and half to the balance of plant. Hydrogen storage costs the OEM $10/kWh. A model from Kromer and Heywood (2007) shows the total OEM manufacturing cost for drivetrain plus storage to be $71/kW, or a retail price of about $100/kW, giving a drivetrain plus storage price of $7,920.
For Case 1b (Hydrogen Partial Success), the fuel cell drivetrain costs the OEM $62/kW corresponding to a fuel cell system cost of $50/kW plus added costs for a hybrid battery, electric motor, and other components. Of the $50/kW fuel cell system cost, about 40 percent is due to the fuel cell stack and 60 percent to the balance of plant. Hydrogen storage costs $15/kWh. The total OEM manufacturing cost is $93/kW or a retail price of about $130/kW, giving a drive-train plus storage price of $10,400.
The drivetrain and fuel storage for a reference gasoline internal combustion engine car are assumed to have an OEM cost of $35/kW plus $300 for the exhaust system. For an 80 kW engine, the OEM cost is $3,100 and the retail price $4,300 ($54/kW). The price for each vehicle is broken down into a drivetrain and a “glider” (the rest of the vehicle). For all vehicles the glider price is the same, $18,750. The HFCV price is assumed to decrease according to a learning curve model developed by Oak Ridge National Laboratory researchers (Greene et al., 2007), based on automobile manufacturers’ estimates of fuel cell vehicle costs in mass production (Figure 6.6).
Cases 1 and 1a assume that the HFCV has twice the fuel economy of an efficient gasoline ICEV, described in Case 2 (ICEV Efficiency) below. (The evolving efficient gasoline ICEV in Case 2 has fuel economy of 25.2 miles per gallon
economy. Second, the net oil displacement and CO2 emission reduction are much less certain than for fuel economy improvements. These factors are discussed in Chapter 4.
4
The 2006 reference gasoline vehicle is based on a midsized five passenger car, with a curb weight of 1,570 kg. As efficiency improves over time, the weight is reduced to about 1,280 kg by 2030. The weight of the corresponding HFCV is 1,320 kg, reflecting heavier components. This reference vehicle is about average for the current new car fleet and is assumed to represent the fleet. Similarly, the HFCV that replaces it is assumed to be representative. HFCVs, like conventional vehicles, will range from small to large, but the fuel savings can still be determined from the average.
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FIGURE 6.6 Assumed retail prices for hydrogen and gasoline vehicles over time for Cases 1 and 1a (left) and Case 1b (right).
(mpg) in 2015 and 42.4 mpg in 2050). The hydrogen fuel cell vehicle has about 1.4 times the fuel economy of the gasoline hybrid in Case 2 (which is assumed to get 36.5 mpg in 2015 and 60.3 mpg in 2050). In Case 1b (Hydrogen Partial Success), the fuel vehicle has 1.75 times the fuel economy of the efficient gasoline ICEV.
Analysis of all three hydrogen cases is detailed in Appendix C. Case 1b (Hydrogen Partial Success) gave rise to only modest reductions in oil use and CO2 emissions by 2050. The cost of making a transition was roughly twice that of Case 1 (Hydrogen Success) and took several years longer to complete.
Case 1a (Accelerated Hydrogen ) gave rise to a marginally faster transition, and the resulting reductions in oil use and CO2 emissions were 25-33 percent greater than Case 1 (Hydrogen Success) by 2050. However, the estimated transition cost for Case 1a was many times that for Case 1, because it assumed that more of the expensive early vehicles are pushed into the market in the early years of the transition.
For these reasons the committee chose Case 1 (Hydrogen Success) as the maximum practicable case as requested in its statement of task. Cases 1a and 1b are not considered further in this chapter.
Hydrogen Infrastructure Requirements and Costs
The UC Davis SSCHISM steady-state hydrogen supply pathway model (Yang and Ogden, 2007b) is used to design hydrogen infrastructure and estimate delivered hydrogen costs for Case 1 (Hydrogen Success). Hydrogen equipment costs and performance are from the H2A model developed by the Department of Energy (Paster, 2006). The H2A component-level data are combined into complete hydrogen supply pathways from hydrogen production through refueling using the SSCHISM steady-state pathways model developed at the University of California-Davis (Yang and Ogden, 2007b). SSCHISM employs an idealized spatial model of infrastructure layout in cities to design and cost alternative infrastructure pathways. Inputs include information about the level of demand (market fraction of hydrogen vehicles), the city population and size, the number of stations, local feedstock and energy prices, and constraints on viable types of supply. Outputs include the delivered hydrogen cost to the vehicle, hydrogen infrastructure costs, and energy use and CO2 emissions for different supply pathways. Cost and performance data about hydrogen production and delivery technologies are discussed in Chapter 3.
The committee makes several assumptions in designing the hydrogen infrastructure.
Phased introduction. There is a phased introduction of hydrogen vehicles and stations in selected large cities, beginning with cities such as Los Angeles and New York (with interest and motivation to implement hydrogen) and moving to other cities over time. This so-called lighthouse concept reduces infrastructure costs by concentrating development in relatively few key areas termed “lighthouse cities.” A possible schedule for phased introduction of hydrogen vehicles in various U.S. cities is shown in Figure 6.7. The list of 27 cities was chosen based on hydrogen scenario development work by DOE (Gronich, 2007; Melendez, 2006).
Station “coverage.” Initially, when hydrogen is introduced in each lighthouse city, some minimum number of hydrogen stations is needed to ensure adequate coverage and consumer convenience. This constraint is imposed to help deal with the “chicken-and-egg” problem of assuring hydrogen fuel availability to early non-fleet vehicle owners. This is assumed to be 5 percent of existing gasoline stations in cities (Nicholas et al., 2004; Nicholas and Ogden, 2007). The percentage of hydrogen stations and station capacity over time are shown in Figures 6.8 and 6.9. For the initial introduction of hydrogen vehicles, it is assumed that 100 kg/d stations are
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FIGURE 6.7 DOE plan for introduction of light-duty hydrogen, vehicles into 27 “lighthouse” cities (thousand vehicles per year introduced between 2012 and 2025). The overall build-up rate corresponds to Case 1. The total number of vehicles in 2025 is 10 million, and 2.5 million vehicles are sold that year. SOURCE: Gronich (2007).
available at 5 percent of gasoline stations for the first several years. (These very early stations might be supplied from the existing industrial hydrogen system, using excess hydrogen from refineries and other industrial or merchant sources.) This is followed by a brief period of building “medium-sized” 500 kg/d on-site steam methane reformers (SMRs) at 5 percent of gasoline stations. As demand grows, capacity is added at each of these stations to make them 1,500 kg/d stations. Beyond about 2022, new 1,500 kg/d stations are
FIGURE 6.8 Fraction of gasoline stations offering hydrogen, 2000-2050.
added, and the fraction of gasoline stations offering hydrogen increases over time. To account for underutilization of hydrogen station equipment as demand grows, a relatively low system capacity factor of 70 percent is assumed.
The assumed capital costs of different hydrogen production systems are summarized in Table 6.4, based on H2A’s future (2015) technology assumptions (DOE, 2007). (See also Chapter 3.)
FIGURE 6.9 Capacity of new hydrogen stations by year, 2000-2050.
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TABLE 6.4 Assumed Capital Costs for Hydrogen Production Systems
Plant Size (tonne/d)
FUTURE TECH H2A 2015 Capital Cost (dollars/kg per day)
Central natural gas (SMR) (production plant only)
50
621
300
400
400
375
Central coal (production plant only)
250
1,275
400
1,170
1,200
950
Central biomass (production plant only)
30
1,260
155
860
200
820
On-site SMR (station)
0.1
3,970 ($0.4 million per station)
0.5
1,811 ($0.9 million per station)
1.5
1,452 ($2.2 million per station)
On-site electrolysis (station)
0.1
4,325 ($0.4 million per station)
0.5
2,050 ($1.0 million per station)
1.5
1,673 ($2.5 million per station)
The SSCHISM infrastructure model compares the different possible supply options in Table 6.2 for 73 different U.S. cities, finding the lowest-cost supply in each city at a specified market penetration. The best choice depends on the level of demand, the city size and demand density, and local energy and feedstock prices. For the first 5-10 years, on-site SMRs dominate the hydrogen supply. After that time, central production plants begin to be built in large cities, with truck or pipeline delivery, although on-site SMRs are assumed to persist in smaller cities. All coal hydrogen plants are assumed to have carbon capture and sequestration (CCS). Biomass hydrogen plants are small in size (30-200 tonnes per day) to match the scale of regional biomass supply. This compares to 250-1,200 tonnes per day for coal plants. The analysis uses a regional biomass supply curve (that specifies the amount of biomass available at a certain amount per tonne) (Perlack et al., 2005) to reflect biomass feedstock cost increases as demand grows.
Figure 6.10 shows the capital costs for infrastructure up to 2030. On-site SMRs dominate, with central production and pipeline delivery beginning after about 2027, when the first central production systems using biomass and coal are built. These are accompanied by pipeline delivery systems and stations. Biomass plants appear slightly earlier than coal hydrogen plants, and more of them are built because they are smaller in size. Later, central production dominates in large cities, although on-site reformers persist in other areas (Figure 6.11).
In terms of the amount of hydrogen produced, coal-based hydrogen is the dominant source, with significant
FIGURE 6.10 Early infrastructure capital costs for Case 1.
FIGURE 6.11 Capital costs for hydrogen infrastructure.
FIGURE 6.12 Estimated average cost of delivered hydrogen in the United States and the assumed gasoline price.
contributions from biomass hydrogen as well. However, it is important to note that the delivered costs of hydrogen from coal, biomass, and natural gas central plants are quite close (within $0.50/kg). Thus, the choice of a feedstock may be determined by other factors, such as state policies favoring renewables. The long-term capital cost for infrastructure is roughly 25 percent on-site reformer stations, 25 percent central production plants (most hydrogen comes from coal, with some from biomass), 25 percent delivery systems (pipelines predominate), and 25 percent refueling stations with truck or pipeline delivery. The U.S. average cost of delivered hydrogen is shown in Figure 6.12.
The total infrastructure capital cost is about $2,000 per car served by the system. The total capital costs to build a
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TABLE 6.5 Type of Hydrogen Supply over Time
Case 1 (Hydrogen Success)
2020
2035
2050
No. of cars served (percentage of total fleet)
1.8 million (0.7%)
61 million (18%)
219 million (60%)
Infrastructure capital cost
$2.6 billion
$139 billion
$415 billion
Total no. of stations
2,112 (all on-site SMR)
56,000 (40% on-site SMR)
180,000 (44% on-site SMR)
No. of central plants
0
113 (20 coal, 93 biomass)
210 (79 coal, 131 biomass)
Pipeline length (miles)
0
39,000
80,000
Hydrogen demand (tonnes per day)
1,410 (100% NG)
38,000 (22% NG, 42% biomass, 36% coal with CCS)
120,000 (31% NG, 25% biomass, 44% coal with CCS)
NOTE: NG = natural gas.
“steady-state” hydrogen infrastructure to serve the demands in 2020, 2035, and 2050 are estimated in Table 6.5. Note that more than $400 billion is required to build the hydrogen infrastructure to supply the fuel for the HFCV fleet in 2050.
Investment Costs for Hydrogen Fuel Cell Vehicles to Reach Cost Competitiveness
Examining the annual cash flows reveals the total investment required for hydrogen HFCVs to reach “breakeven” with gasoline ICEVs. These are shown in Figure 6.13:
The “CAP COST Diff” (dollars per year) is the difference in vehicle price for a gasoline vehicle versus a hydrogen vehicle, summed over all the new HFCVs sold that year. This starts out negative (HFCVs cost a lot more than gasoline vehicles), but small (only a few HFCVs are sold). In the longer term, the annual cost difference continues to grow, as HFCVs are assumed to always cost more than gasoline cars.
“FUEL COST Diff” (dollars per year) is the annual difference in fuel costs for HFCVs (counting all HFCVs currently in the fleet) compared to what would have been paid to fuel comparable gasoline-fueled vehicles. Hydrogen soon becomes less costly as a fuel on a cents-per-mile basis, so this difference becomes positive around 2017.5 This analysis
FIGURE 6.13 Cash flows for Case 1.
assumes that for a new fuel such as hydrogen with a small HFCV fuel tank (approximately 5 to 8 gallons of gasoline equivalent), consumers would value fuel on a cost-per-mile traveled basis (dollars per mile) rather than a cost-per-gallon-equivalent basis, as they do now for gasoline.
“TOTAL Diff” (dollars per year) is the cash flow, which equals the economy-wide cost per year of pursuing a fuel cell market introduction plan. The cash flow is defined
5
Hydrogen fuel becomes cost competitive with gasoline (on a cents-permile basis) in about 2017, when hydrogen costs are still fairly high, about $5.60/kg. This is because the hydrogen vehicle is assumed to have a fuel economy 2.0 times greater than the gasoline vehicle, and the gasoline price in the AEO high-oil-price case is $2.80 per gallon. This analysis compares the cost of hydrogen with the price of gasoline. The committee decided this would be the most straightforward comparison because it would be difficult to estimate a price for hydrogen without a model for all its uses in the economy, and it is hard to estimate the cost of gasoline, which depends on many complex factors. Gasoline prices include federal, state, and local taxes. One could argue that hydrogen should be competed against the untaxed gasoline price. However, other alternative fuels such as ethanol are untaxed to encourage their adoption, and the committee decided to give hydrogen the same advantage. It should be noted that much of the revenue raised by gasoline taxes goes to highway maintenance and other necessary functions that continue no matter what type of vehicles travel on them. As discussed in Chapter 7, these revenues will have to be replaced from other sources if alternative fuels remain untaxed. On the other hand, the price of gasoline does not include the cost of externalities that hydrogen is intended to address: CO2 emissions and oil imports.
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as the gasoline vehicle minus the annual cost of the hydrogen vehicle. This starts out negative, but becomes positive in 2023, when the cost of hydrogen vehicles becomes less than that of a similar number of gasoline vehicles. While the HFCVs first cost remains higher than for the gasoline car, the net fuel cost savings make the annual cash flow positive at the breakeven year.
“CMLTV Diff” (dollars) is the cumulative cost difference, the sum of the cost difference over time (starting in 2012), providing a yearly tally of the total funds that would have to be invested to make HFCVs competitive. At first, there is a negative cash flow (early HFCVs cost more than gasoline cars), but eventually as HFCV and hydrogen fuel costs come down, the negative cash flow “bottoms out” in 2023 at a minimum of about $22 billion, when about 5.6 million fuel cell vehicles have been produced. This minimum is the “buydown” investment that must be supplied to bring the HFCV to cost competitiveness.
Most of the negative cash flow is due to the high price of the first few million fuel cell vehicles. This is not surprising, since, initially, fuel cell vehicles cost a lot more than gasoline vehicles (see Figure 6.6). The subsidy that might be needed by automakers or buyers is the sum of the difference in costs between HFCVs and gasoline cars, each year between vehicle introduction in 2012 and life-cycle cost (LCC) breakeven in 2023. This cumulative difference in vehicle first cost for HFCVs (as compared to a reference gasoline vehicle) is about $40 billion (averaged over the 2012-2023 buydown period, this is about $7,000 per car, or an average of $3.3 billion per year for 12 years). Transition dates and costs are summarized in Table 6.6, relative to a reference gasoline vehicle.
The buydown cost is quite sensitive to assumptions for key factors. For example, if fuel cell vehicles could be introduced at their “learned-out cost” (e.g., the cost of HFCVs once they have become technically mature and are manufactured at large scale), buydown cost requirements for vehicles would be greatly reduced, and fuel cell vehicles would become competitive almost immediately. In this case, the primary transition cost would be building a hydrogen infrastructure to the point at which hydrogen is competitive as a fuel (fuel cost per kilometer), on the order of a billion dollars. Note that this would happen much sooner than the vehicles reaching cash flow breakeven (see bottom row in Table 6.6). Box 6.1 explores the sensitivity of the results to assumptions on HFCV fuel economy and incremental costs, and the cost of hydrogen and gasoline.
TABLE 6.6 Transition Costs and Timing for Hydrogen Cases
Breakeven Year (annual cash flow > 0)
2023
Cumulative life-cycle cost difference (between HFCV and gasoline reference car) to breakeven year
$22 billion
Cumulative vehicles first-cost difference (between HFCV and gasoline reference car) to breakeven year
$40 billion (~$3.3 billion/yr)
Number of HFCVs at breakeven year (millions)
5.6 (1.9% of fleet)
Hydrogen cost at breakeven year
$3.3/kg
Hydrogen demand; number of hydrogen stations at LCC breakeven year
4,200 tonnes/d; 3,600 stations
Total cost to build infrastructure for demand at LCC breakeven year
$8.2 billion
Year when hydrogen fuel cost per kilometer = gasoline price per kilometer
2016
Hydrogen cost ($/kg)
5.20
Gasoline price ($/gal)
2.70
Total cost to build infrastructure to meet demand in 2023 (LCC breakeven year)
$0.5 billion (1,000 small on-site SMR stations)
RESULTS: COMPARISON OF GREENHOUSE GAS EMISSIONS AND OIL DISPLACEMENT FOR SCENARIOS
Assumed Greenhouse Gas Emissions for Fuels
Until 2020, all hydrogen comes from on-site SMRs with a CO2 release of 100 g CO2 equivalent per megajoule of fuel. After that time, low-carbon sources such as biomass hydrogen and hydrogen from coal with carbon capture and storage are phased in. By 2050, roughly 31 percent of hydrogen is produced via on-site SMRs, the remainder via low-carbon sources (44 percent coal with CCS, 25 percent biomass H2). Thus, the overall emissions for hydrogen supply in 2050 are 37 g CO2/MJ fuel, based on the CO2 values given in Table 6.7, which shows the assumptions regarding the well-to-wheels emissions associated with different fuel supply pathways. In all cases, the carbon emissions from the hydrogen supply are assumed to follow the curve shown in Figure 6.14, where CO2 emissions are shown as declining linearly between 2020 and 2050. The average CO2 emissions might fall faster than this, because most new capacity after
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TABLE 6.7 Assumed Greenhouse Gas Emissions per Unit of Fuel Consumed
Fuel
Greenhouse Gas Content of Fuels(g CO2 equivalent/MJ fuel used LHV basis)
Conventional gasoline
90 (AEO 2007 projections to 2030 show this staying approximately constant)
Hydrogen from on-site reformation
100 (TIAX, 2007)
Hydrogen from coal with CCS, pipeline delivery
16 (92% CO2 capture rate, assuming U.S. electricity mix)
0 (100% CO2 capture rate, assuming zero-carbon electricity is used for CO2 compression) (adapted from Ruether et al., 2005). Coal mining, transport, and plant and mine construction emissions are estimated to be about 3.8 g CO2 eq/MJ H2, but this is counterbalanced by GHG savings of about 4.3 g CO2 eq/MJ, due to exported electricity from the plant)
Hydrogen from biomass, pipeline delivery
10 (TIAX, 2007)
Hydrogen from electrolysis using zero-carbon electricity (wind, hydro, solar)
0
Ethanol from corn
70 (22% reduction relative to gasoline)
Ethanol from cellulose
13 (85% reduction relative to gasoline)
SOURCES: Ruether et al. (2005); TIAX (2007).
2025 is likely to be very low carbon in these scenarios (70 percent biomass hydrogen or coal hydrogen with CCS).
Case 1 (Hydrogen Success)
Oil Displacement
Figure 6.15 estimates gasoline consumption for the Hydrogen Success case and the reference case. Oil displacement is about 0.8 percent in 2020, rising to 24 percent in 2035 and 69 percent in 2050. Although it takes several decades for hydrogen’s impact to be seen, beyond 2025 it enables growing reductions in both greenhouse gas emissions per year and annual oil use. Hydrogen may be important to achieve long-term stabilization goals requiring deep cuts in carbon or oil use. Figures 6.15 and 6.16 show a dip in the reference case after about 2020. This occurs even though the increase in fuel economy of new cars levels off because the entire on-road fleet fuel economy increases as new efficient vehicles replace older vehicles.
FIGURE 6.14 Greenhouse gas emissions from hydrogen supply over time.
FIGURE 6.15 Case 1 gasoline consumption relative to the reference case.
FIGURE 6.16 Case 1 greenhouse gas emissions relative to the reference case.
Greenhouse Gas Reductions
Figure 6.16 shows the committee’s estimate of the reductions in greenhouse gas emissions for Case 1 (Hydrogen Success) relative to a reference case, where no hydrogen technologies are introduced. Greenhouse gas emissions per
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BOX 6.1
Sensitivity of Breakeven Analysis Results to Changes in Assumptions
The results of an analysis of the costs and timing of a hydrogen transition depend on many assumptions and inputs and are sensitive to changes in four important input parameters:
The fuel economy of an HFCV compared to a reference gasoline vehicle;
The incremental cost of an H2FCV compared to a gasoline reference vehicle;
The cost of hydrogen; and
The cost of gasoline (dollars per gallon).
The values of these parameters for Case 1 (Hydrogen Success) are shown in Table 6.1.1. Also shown are potential high and low values for each parameter. Each parameter is varied over this range.
Three key metrics that describe a hydrogen transition are:
The “breakeven year”;
The “breakeven cost” (e.g., cumulative cash flow to get to the breakeven year); and
The total capital cost (the incremental cost for HFCVs + the infrastructure cost) to get to the breakeven year.
TABLE 6.1.1 Range Over Which Parameter Values Can Vary for Case 1
Parameter
Low Value
Case 1 Value
High Value
Fuel economy of HFCV versus fuel economy of efficient gasoline car
1.3
2
3
Incremental cost of HFCV compared to reference gasoline vehicle
1,713
(FC system = $50/kW; H2 storage = $2/kWh)
3,600
(FC system = $50/kW; H2 storage = $10/kWh)
6,800
(FC system = $62/kW; H2 storage = $18/kWh)
Incremental cost of H2 compared to Case 1 long-term cost
−$2/kg
0
$2/kg
Price of oil
0.5 × high-price case (oil at $40-$60/bbl in 2012-2030)
Oil price from AEO 2008 high-price case (oil at $80-$120/bbl in transition period 2012-2030)
1.3 × high price case (oil at $105-$160/bbl in 2030)
NOTE: bbl = barrel; FC = fuel cell.
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The value for each of these three metrics is shown as a function of the variables in a series of three “spider plots” (Figures 6.1.1-6.1.3). In each plot, the x-axis is the ratio of the variable to its Case 1 value (shown in Table 6.1.1.). (The normal Case 1 input is represented by a value of “1” on the x-axis. So, an HFCV incremental cost of $3,600 corresponds to an x-value of 1, while an HFCV incremental cost of $6,800 corresponds to an x-value of 6,800/3,600 = 1.88.) When the input parameter is varied from its low to its high values, the value of x changes from 0.5 to 2. The metric varies as the input changes. This shows the sensitivity of the results to changes in the input variables.
As expected, the breakeven year is delayed and buydown costs are higher if the HFCV price is higher, the HFCV is less efficient, or hydrogen costs more than in Case 1. Breakeven occurs faster and the buydown cost is less for higher oil prices.
For example, if hydrogen costs $1/kg more than expected, there is relatively little impact on the breakeven year or the transition cost. However, if the cost of hydrogen is $2/kg higher than expected, this delays breakeven by 12 years (from 2023 to 2035) and raises the breakeven cost by almost a factor of three (from about $23 billion to $61 billion). If the oil price is 1.3 times the AEO’s projected high-price case (e.g., about $100 to $160 per barrel of oil in the transition period between 2012-2030), the breakeven year is accelerated slightly. However, if oil prices drop to 70 percent of the AEO projections (e.g., about $55 to $85 per barrel of oil during the transition period 2012-2030), breakeven is delayed 5 years (from 2023 to 2028) and the buydown cost rises from $23 billion to $31 billion. If oil prices drop to 50 percent of the AEO high-price case ($40 to $60 per barrel during the transition), breakeven is delayed further to 2035, and the buydown cost almost triples to $61 billion.
FIGURE 6.1.1 Sensitivity of breakeven year to changes in HCFV fuel economy, HFCV price, H2 cost, and gasoline price.
FIGURE 6.1.2 Sensitivity of buydown cost (billion dollars) to changes in HFCV fuel economy, HFCV price, H2 cost, and gasoline price.
FIGURE 6.1.3 Sensitivity of capital investment to breakeven year (incremental price of HFCVs + H2 infrastructure capital, billion dollars).
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year are reduced by about 0.7 percent in 2020, 19 percent in 2035, and 60 percent in 2050 compared to the reference case.
Case 2 (ICEV Efficiency)
Case 2 is an “evolutionary,” not revolutionary, scenario. The committee assumes that currently available improvements in gasoline internal combustion engine technology are used to improve fuel economy (rather than power and acceleration).
A range of more efficient advanced gasoline technologies could be implemented in 2010-2035 as described in Chapter 4. In this scenario, a new “high-fuel-economy” gasoline vehicle is introduced, as well as a hybrid gasoline vehicle, and these capture growing market share over time. By 2035 (2050), 42 percent (85 percent) of new LDVs and 30 percent (60 percent) of the fleet are gasoline hybrids, and the remaining non-hybrid cars have high fuel economy. This is shown in Figure 6.17.
In 2010, the new gasoline vehicle is assumed to have an on-road fuel economy of 22.2 mpg, the hybrid 31.9 mpg. (These values are selected to match the reference case up to 2010.) The fuel economy of each vehicle is then assumed to improve as follows and discussed in Chapter 4:
2.6 percent per year from 2010 to 2025,
1.7 percent per year from 2026 to 2035, and
0.5 percent per year from 2035 to 2050.
The on-road new car fuel economy over time is plotted in Figure 6.18. Note that this is similar to the reference case in Figure 6.4 up to about 2020. Beyond this, Case 2 is significantly more efficient; by 2050, gasoline ICEV and hybrid cars are about 35 percent more efficient than in the reference case, which incorporates the new CAFE standards.
The committee did not project increased market share for diesel engines in this scenario because of the uncertainty over the costs of meeting future tailpipe emission specifications and consumer acceptance, considering the poor history of diesels in U.S. automobiles. However, advanced diesel power
FIGURE 6.17 Case 2 assumed market penetration for gasoline ICEVs and advanced gasoline HEVs.
FIGURE 6.18 Case 2 assumed on-road fuel economy for new gasoline ICEVs and gasoline hybrid ICEVs over time.
trains could offer an additional 15 percent reduction in fuel consumption and CO2 emissions over advanced conventional spark ignition power trains and have cost advantages over hybrid electric vehicles (see, for example, Adrian, 2004). In a high-fuel-cost environment, they could become a growing fraction of LDV sales with the some shifts in government positions on diesels and a positive public relations program. Thus, to the extent that diesels can penetrate the market, this scenario may understate potential fuel savings.
The same vehicle stock model used in the reference case keeps track of the vehicle numbers and vintages of advanced gasoline cars and gasoline hybrids on the road in any year. This allows calculation of oil consumption and greenhouse gas emissions for each year.
Oil Displacement
Gasoline consumption for the case above is estimated in Figure 6.19. Improving fuel economy is a very effective way to cut gasoline use. Gasoline consumption in 2020 is only slightly reduced relative to the reference case, which includes rapidly improving fuel economy, but in 2035 it is down by 35 billion gallons per year (25 percent), and in 2050, by 64 billion gallons per year (40 percent).
Greenhouse Gas Reductions
Greenhouse gas emissions show a similar trend (Figure 6.20). Fuel economy improvements can yield increasing reductions in greenhouse gases. Greenhouse gas emissions are reduced by about 24 million tonnes of CO2 equivalent per year (1.7 percent) by 2020, 385 million tonnes (25 percent) by 2035, and 700 million tonnes (41 percent) by 2050.
Based on projected gasoline prices and cost estimates for improved fuel economy, it appears that gasoline hybrids and advanced gasoline vehicles would pay for themselves on a life-cycle cost basis, so no external subsidy should be needed. A simple calculation shows that increasing fuel economy from 30 to 45 mpg in a car that travels 15,000
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FIGURE 6.19 Gasoline consumption for Case 2 and for the reference case.
FIGURE 6.20 Greenhouse gas emissions for Case 2 and for the reference case.
miles a year saves 167 gallons of gasoline per year. If a car is kept 10 years and gasoline costs $2.5 per gallon, the present value of fuel savings amounts to $2,565 (assuming a 10 percent discount rate). This would be enough to pay for the difference in first cost between a conventional gasoline car and a hybrid, which is estimated to be $1,800-$2,500 per car (Kromer and Heywood, 2007).
Case 3: Biofuels
Case 3, Biofuels, considers an emphasis on biofuels in the transportation sector. Assumptions about the introduction of biofuels are summarized in Table 6.8. Annual production levels for various biofuels are plotted in Figure 6.21. The detailed assumptions are discussed in Chapter 4. For reference, the maximum practicable case, in the committee’s judgment, is 700 million dry tons of sustainable biomass available in 2050, with all of the biomass used for cellulosic ethanol production at 90 gallons per dry ton. This would total 63 billion gallons of ethanol per year in 2050, the amount assumed in Case 3.
The AEO 2007 reference case includes about 12 billion gallons of corn ethanol by 2030 plus an additional 3 billion gallons of cellulosic ethanol. The committee extended this to assume that in the reference case, cellulosic ethanol production reaches 9 billion gallons per year by 2050. The assumed biofuels use in the reference case is shown in Figure 6.5.
TABLE 6.8 Assumed Biofuel Use in Case 3
Corn Ethanol
Cellulosic Ethanol
Biobutanol
Biodiesel
F-T Diesel via Biomass Gasification
Production (billion gallons)
Timing of introduction similar to that for biomass H2, toward end of scenario time frame
• 2002
• 2006
2.5
• 2008
6
0.25
• 2010
8
1
• 2015
10
6
0.6 (2012)
• 2020
12 (max = 30% of expanded corn crop)
16
0.1
• 2025
28
0.6
1.5 (max = 30% of soy crop, limited by land)
• 2030
36
2.6
• 2035
12
44
4.0
• 2050
63
CO2 reduction (energy equivalent basis)
22% relative to gasoline
85% relative to gasoline
80% relative to regular diesel
Oil reduction (energy equivalent basis)a
1 gallon gasoline equivalent ethanol replaces 0.96 gallon oil
1 gallon gasoline equivalent ethanol replaces 0.93 gallon oil
1 gallon biodiesel replaces 0.95 gallon oil
aGasoline = 119,000 Btu/gal, ethanol = 80,000 Btu/gal, and biodiesel is equivalent to regular diesel.
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FIGURE 6.21 Annual production of biofuels assumed for Case 3.
The reference case corresponds to about 10 percent ethanol by volume in gasoline by 2050. In Case 3 (Biofuels), this is expanded to include an additional 54 billion gallons of biofuels per year (beyond the reference case). This is roughly four times the biofuel use in the reference case or about 40 percent ethanol in gasoline plus some other advanced biofuels. It is important to note that the greenhouse gas and oil reductions shown for Case 3 are relative to a reference case that already includes biofuel use up to 10 percent of gasoline by volume.
In the Biofuels case, the assumed corn ethanol use is the same as in the reference case. The difference is that more cellulosic and other advanced biofuels are produced. The additional biofuels production assumed in the Biofuels case (compared to the reference case) is shown in Figure 6.22.
Gasoline displacement for Case 3 is shown in Figure 6.23. The total is about 12 billion gallons per year by 2020 and 39 billion gallons per year in 2050.
Greenhouse gas emissions reductions are given in Figure 6.24 for the Biofuels case. The total reduction in greenhouse gas emissions is about 8 percent from the reference case by 2020, rising to 23 percent by 2050. The committee has not estimated the costs of building biofuel production plants or changes in the fuel distribution infrastructure that might be needed.
FIGURE 6.22 Case 3: Added biofuel production relative to the reference case.
FIGURE 6.23 Case 3: Oil displacement relative to the reference
FIGURE 6.24 Case 3: Greenhouse gas emission reductions relative to the reference case.
Comparison of Scenarios
The estimated savings in gasoline use and greenhouse gas emissions for each case are plotted in Figures 6.25 and 6.26. In the near to mid term, improving the fuel economy of gasoline vehicles will be the most effective option for reducing oil use and greenhouse gas emissions. This is already incorporated in the reference case up to 2020, but continued improvements thereafter could match the savings from hydrogen until about 2035. Biofuels could begin to make a difference sooner than hydrogen, which takes more time to implement, assuming cellulosic ethanol comes online in 2010. After about 2032, however, Case 1 (Hydrogen Success) would lead to greater greenhouse gas reductions per year than Case 3 (Biofuels). By 2040, the Hydrogen Success scenario offers about twice the greenhouse gas reduction and oil savings per year as the Biofuels scenario, and by 2050, almost three times the reduction. This clearly illustrates the time frames for different technologies and the total contributions they might make by 2020 and beyond. Although efficiency and biofuels could contribute sooner, hydrogen would surpass the annual savings achievable with either after
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FIGURE 6.25 Oil consumption for Cases 1-3 compared.
FIGURE 6.26 Greenhouse gas emissions for Cases 1-3 compared.
2035. This result highlights the long time constants inherent in changing the energy system, as well as the need to develop long-term, very low carbon options.
COMBINED APPROACHES TO REDUCING GREENHOUSE GAS EMISSIONS AND OIL USE
The previous section looked at the potential impact of implementing one technological measure at a time. In the future, reducing oil use and greenhouse gas emissions probably will be increasingly important, and it is likely that a combination of approaches would be implemented. However the reductions for each approach cannot simply be added because they affect each other. This section considers several combinations.
Case 1 + Case 2: HFCVs + ICEV Efficiency
This case combines higher gasoline vehicle efficiency with introduction of hydrogen fuel cell vehicles (Case 1 and Case 2). The results are shown in Figures 6.27 and 6.28. Comparing Figure 6.27 and 6.25, gasoline consumption in 2035 is about 18 billion gallons per year lower for the combined case than for HFCVs alone. By 2020, efficiency reduces greenhouse gas emissions by about 1.8 percent relative to the base case. Beyond 2030, HFCVs lead to deeper cuts in emissions than would be possible with efficiency alone.
Case 3 + Case 2: Biofuels + ICEV Efficiency
Combining higher gasoline vehicle efficiency with biofuels yields much greater reductions in oil use and greenhouse gas emissions than are possible with biofuels alone. This is shown in Figures 6.29 and 6.30, which combine Cases 2 and 3. By 2020, biofuel use alone could reduce annual oil use by about 8 percent, with efficiency bringing the total to 10 percent. In the longer term, the effect of efficiency improvements dominates, with biofuels saving 23 percent of gasoline use or greenhouse gas emissions in 2050 and efficiency an additional 41 percent. This strategy “stretches” limited biomass resources to fuel more vehicle miles traveled per acre of land.
FIGURE 6.27 Oil use for Cases 1 and 2 combined.
FIGURE 6.28 Greenhouse gas emissions with HFCVs for Cases 1 and 2 combined.
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FIGURE 6.29 Oil use for Cases 2 and 3 combined.
FIGURE 6.30 Greenhouse gas emission reductions for Cases 2 and 3 combined.
Case 4 (Portfolio): Implement Efficient ICEVS plus Biofuels and Hydrogen FCVs
Case 4 combines all three of the major options discussed above. Figure 6.31 shows the assumed numbers of vehicles in the fleet over time. Note that the number of hydrogen vehicles is the same as in Case 1 (Hydrogen Success) and the number of gasoline ICEVs is the same as in Case 2 (ICEV Efficiency). The number of advanced gasoline ICEVs (hybrids) increases, but eventually loses market share to HFCVs.
Figure 6.32 shows the reduction in petroleum consumption over time for Case 4. Gasoline use is virtually eliminated in the light duty vehicle fleet by 2050. Table 6.9 shows the reduction in gasoline use for the four cases relative to the reference case.
Table 6.10 lists the emissions reductions relative to the reference case for the four cases. Emissions of greenhouse gas over time are shown in Figure 6.33. The cumulative impact of reductions is shown in Figure 6.34. With a combined approach including efficiency, biofuels, and hydrogen fuel cells, it is possible to reduce CO2 emissions by about 90 percent and gasoline use by 99 percent by 2050.
FIGURE 6.31 Assumed number of vehicles in the fleet for Case 4.
FIGURE 6.32 Oil use in million gallons per year for Case 4.
TABLE 6.9 Gasoline Displacement for Cases 1-4 Compared to Reference Case
Case
Billion Gallons Gasoline Saved per Year (% Saved)
2020
2035
2050
Case 1 (Hydrogen Success)
1.0 (0.8%)
34 (24%)
109 (69%)
Case 2 (ICEV Efficiency)
2.2 (1.7%)
35 (25%)
64 (41%)
HFCVs + ICEV Efficiency
3.0 (2.2%)
55 (39%)
125 (80%)
Case 3 (Biofuels)
12 (9%)
28 (20%)
39 (25%)
Case 3 + Case 2 Biofuels + ICEV Efficiency
14 (11%)
64 (45%)
103 (66%)
Case 4: ICEV Efficiency (Case 2) + Biofuels (Case 3) + Hydrogen (Case 1)
15 (11%)
83 (59%)
157 (100%)
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TABLE 6.10 Greenhouse Gas Emission Reductions for Cases 1-4 Compared to Reference Case
Case
Million Tonnes CO2 Equivalent Avoided (% Avoided)
2020
2035
2050
Case 1 (Hydrogen Success)
10 (0.7%)
295 (19%)
1,026 (60%)
Case 2 (ICEV Efficiency)
24 (1.7%)
385 (25%)
700 (41%)
HFCVs + ICEV Efficiency
26 (1.8%)
475 (31%)
1,123 (66%)
Case 3 (Biofuels)
118 (8%)
281 (18%)
386 (23%)
Case 3 + Case 2 Biofuels + ICEV Efficiency
143 (10%)
666 (44%)
1,086 (64%)
Case 4: Hydrogen (Case 1) + ICEV Efficiency (Case 2) + Biofuels (Case 3)
130 (9%)
747 (49%)
1,505 (88%)
FIGURE 6.33 Greenhouse gas emissions for Case 4 (combination of HFCVs, efficiency, and biofuels).
FIGURE 6.34 Cumulative reduction of greenhouse gas emissions for Case 2, Case 3 plus Case 2, and Case 4.
CONCLUSIONS
CONCLUSION: In the judgment of the committee, the maximum practicable number of HFCVs that could be on the road by 2020 is around 2 million. Subsequently, this number could grow rapidly to as many as 60 million by 2035 and more than 200 million by midcentury, but such rapid and widespread deployment will require continued technical success, cost reductions from volume production, and government policies to sustain the introduction of HFCVs into the market during the transition period needed for technical progress.
CONCLUSION: While it will take several decades for HFCVs to have major impact, under the maximum practicable scenario fuel cell vehicles would lead to significant reductions in oil consumption and also significant reductions in CO2 emissions if national policies are enacted to restrict CO2 emissions from central hydrogen production plants.
CONCLUSION: The unit costs of fuel cell vehicles and hydrogen in the Hydrogen Success scenario—the maximum practicable case—decline rapidly with increasing vehicle production, and by 2023 the cost premium for HFCVs relative to conventional gasoline vehicles is projected to be fully offset by the savings in fuel cost over the life of the vehicle relative to a reference case based on the EIA high-oil-price scenario. At that point, according to the committee’s analysis, HFCVs become economically competitive in the marketplace.
Fully implementing the maximum practicable hydrogen case by 2050 would require construction of approximately 80,000 on-site distributed natural gas reforming units, 80 coal gasification plants of 500 MW (electrical equivalent) with CCS, 130 biomass gasification plants (each 100 MW equivalent) with associated biomass growth and collection farms, and roughly 80,000 miles of pipelines for hydrogen supply and CCS. The committee estimates that more than $400 billion would be required to fully build out hydrogen supply to fuel the HFCVs by 2050.
The committee’s analysis indicates that at least two alternatives to HFCVs—advanced conventional vehicles and biofuels—have the potential to provide significant reductions in projected oil imports and CO2 emissions. However, the rate of growth of benefits from each of these two measures slows after two or three decades, toward the end of the committee’s analysis period, while the growth rate of projected benefits from fuel cell vehicles is still increasing. The deepest cuts in oil use and CO2 emissions after about 2040 would be from hydrogen.
Over the next 20 years, the greatest impact on U.S. oil and CO2 reductions would result from implementing existing
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evolutionary vehicles focused on vehicle design to deliver efficiency improvements.
The potential of biofuels under the committee’s maximum practicable approach achieves a 23 percent reduction in CO2 and gasoline use by 2050, but has only a small impact prior to 2035, compared to the reference case.
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Yang, C., and J. Ogden. 2007b. U.S. Urban Hydrogen Infrastructure Costs Using the Steady State City Hydrogen Infrastructure System Model (SSCHISM). Presentation at the 2007 National Hydrogen Association Meeting, San Antonio, Texas, March 18-22. (A beta copy of the model is posted on Christopher Yang’s website at University of California at Davis Institute of Transportation Studies, http://www.its.ucdavis.edu/people.)