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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
3
Hydrogen Technology
This chapter reviews the hydrogen production and fuel cell vehicle technologies that will be needed to establish a budget roadmap to achieve the “maximum practicable” goal spelled out in Chapters 6 (“U.S. Carbon Dioxide (CO2) and Oil Reductions from Hydrogen and Alternatives”) and 7 (“A Budget Roadmap,” which covers the R&D, vehicle, and infrastructure costs entailed in moving to a self-sustaining hydrogen-based system). It details how the hydrogen production and delivery infrastructure might grow to meet the demand for hydrogen fuel and lays out a picture of how the future hydrogen infrastructure could evolve to support the growing number of hydrogen fuel cell vehicles (HFCVs), referred to as the maximum practicable rate (MPR) of penetration, developed and discussed in Chapter 6. In the MPR case, HFCVs are introduced starting with a few thousand in 2012, growing to a fleet of 2 million in 2020, 60 million in 2035, and 220 million in 2050.
In assessing these developments, the committee analyzed hydrogen production, delivery, and dispensing technologies and evaluated fuel cell and hydrogen storage. In doing so, its members met representatives of major hydrogen fuel and auto companies that have announced hydrogen programs, participated in studies of the National Research Council (NRC) Committee on the Review of the FreedomCAR and Fuel Partnership. (To allow for greater interaction, the two committees shared two members.) It also met with U.S. Department of Energy (DOE) officials to review its technical programs, conducted a detailed review of the literature with the help of a consultant, and reviewed publicly available sources that have a history of technology evaluations and/or product introductions.
Resource calculations in Chapters 6 and 7 include costs of both the HFCVs and the hydrogen infrastructure (for production, delivery, and dispensing), and this chapter includes estimated cost data for key technologies. The cost of the hydrogen fuel cell and onboard hydrogen storage system on the HFCV will be critical to its competitiveness with alternative vehicle technologies described in Chapter 4. The cost and technical status of hydrogen producing and delivering technologies from various primary feedstocks determined which technologies were included in the roadmap. This chapter focuses on the least expensive, most fully developed technologies with potential for low well-to-wheels (WTW) carbon dioxide (CO2) release that are the most practical for different stages of the move to hydrogen. Using the criteria of cost and stage of technological advancement in this screening process effectively ruled out some technologies that are in early development phases or have high current costs but may have good potential for improvement. This fact does not imply that these technologies are unimportant or will not play roles in the future. The committee’s task included estimating the costs of building the infrastructure to meet growing hydrogen demand during the transition to a self-sustaining hydrogen transportation system (i.e., one without subsidies). The technologies chosen represent just one scenario of what could happen.
This chapter addresses the readiness of the hydrogen production and delivery and HFCV technologies to begin to meet the MPR case. Much of the current development of HFCVs is aimed at the year 2015 for the most crucial early-stage technologies to be at the point at which decisions to move to mass commercialization could be made. This focus is consistent with the MPR case.
HYDROGEN PRODUCTION AND DELIVERY
Hydrogen can be produced from various resources, either in small facilities at the point of sale or in larger facilities farther away and requiring delivery. Getting to a self-sustaining market will require an evolution of the supply infrastructure to ensure the lowest possible costs and fuel availability at all times. The long-term vision of the hydrogen production and supply infrastructure is to produce large amounts of hydrogen from domestic resources with low WTW CO2 emissions and deliver this to customers at a cost that is competitive with gasoline on a cost-per-mile traveled basis. The report
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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
The Hydrogen Economy (NRC, 2004) indicated that this long-term potential could be possible once a large number of HFCVs are in the market and a mature hydrogen industry is in place. This section discusses the transitional period and lays out a picture of what this might look like. The technologies discussed are those that are the most well developed and nearest to technical and economic readiness. These are the technologies that are included in the resource estimates in Chapter 6, along three alternative time frames:
Early hydrogen delivery for first vehicle owners—supplied from existing industry excess capacity or small skid-mounted production appliances at existing gasoline stations
Midtransition vehicle owners—supplied mainly by on-site production at full-size refueling stations
Late transition to self-sustaining hydrogen transportation system—supplied mainly in large central production facilities and delivered by pipeline to refueling stations
Early Hydrogen Infrastructure
Before HFCVs can be marketed generally, there must be enough fueling facilities to convince buyers that fuel will be available when and where they need it. Based on the analogy with diesel fuel, between 10 and 25 percent of stations providing an alternate fuel gives customers confidence in fuel availability. Meeting this standard for early hydrogen vehicle users will be very challenging because hydrogen fueling equipment is much more expensive than traditional liquid fuels. Reducing the number of locations while still providing good coverage will be important to hold down capital costs and to increase the hydrogen volume sold at each location. Recent estimates (Nicholas et al., 2004) are that as few as 5 percent of stations offering hydrogen might satisfy customer concerns if their locations are closely coordinated to provide adequate coverage of urban and suburban areas. This very close coordination in locating stations is a new concept compared with today’s free market and individual company decisions to determine locations. This concept involves coordination between auto companies, energy providers, and local governments that is not practical today because of antitrust concerns.
Convincing hydrogen suppliers to build hydrogen stations before the introduction of many HFCVs is sometimes referred to as the “chicken-and-egg problem.” Hydrogen suppliers are reluctant to invest large sums before they know that many HFCVs will be sold. Similarly auto companies will not be able to sell many HFCVs without an adequate number of hydrogen fueling stations. A way around this quandary is to stage HFCV introduction in phases by region. This approach is referred to as the “lighthouse concept” (Gronich, 2007). For example, if the HFCV is first introduced in the Los Angeles area, then only 5 percent of the stations in that region need to offer hydrogen to provide adequate coverage. As more HFCVs are sold, the infrastructure expands, eventually to mid- and late transition supply options discussed in the next two sections. This is then repeated in more cities. This concept is more fully explained in Chapter 6, as is a list of possible cities.
The demand for hydrogen at these stations will be very low for the first several years of operation because there will be an excess of stations for the few HFCVs in the market. All of the hydrogen stations will be underutilized for a period of years. During the first several years of operation there will be fewer than 10 HFCV fills (at perhaps 5 kg each) per station per day on average. At very low demand the technology choices to provide hydrogen include truck delivery of hydrogen from current industrial hydrogen gas suppliers or from excess hydrogen production at some refineries and chemical plants directly to the filling station where it is stored, much as in today’s gasoline station. Where hydrogen is not available, small skid-mounted natural gas reformers or small water electrolysis systems could be used to generate hydrogen at the refueling station. As demand grows, these small units might be moved to new areas and replaced by larger facilities. The initial hydrogen cost for all of these options is high, but as the hydrogen sales volume increases the cost will decline. The hydrogen sales volume might increase quickly during this early stage if hydrogen-powered internal combustion engine vehicles (ICEVs) as well as HFCVs were also filling at these stations. Box 3.1 contains a discussion of the hydrogen ICEV.
To illustrate this point, for a 500 kg/d natural gas reformer (about one-third the size of a full commercial-scale unit needed for a full-size refueling station) producing hydrogen at a station and dispensing at 5,000 pounds per square inch (psi), the hydrogen cost will be $3.50/kg when operating at full capacity (70 percent). Full capacity will provide about 70 refuelings per day. For this station in the very early years when there are only 10 refuelings per day, the hydrogen cost increases to $7.70/kg.
Midtransition Infrastructure for Expanding Hydrogen Availability to Full-size Stations
With increasing HFCV sales, hydrogen demand will eventually catch up to the initial capacity of the first stations. In addition, coverage must expand to cover distant suburban areas as well as some rural areas and highways between urban areas. The amount of hydrogen needed around any urban center would still be small, which favors hydrogen technologies that do not need a large hydrogen distribution system. This includes distributed reforming of natural gas or renewable liquid fuels such as ethanol and electrolysis of water using electricity. The distributed approach uses large appliance-type devices located at the refueling site to convert the raw material to hydrogen. These devices would be factory
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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
BOX 3.1
The Hydrogen-powered ICEV
Hydrogen-powered ICEVs (HICEVs) have been demonstrated by several auto companies including Ford and BMW. BMW even offers a model to the public for lease. The hydrogen ICEV has many of the same advantages as an HFCV in that the fuel can be made from various sources and the primary combustion product is water. However since the HICEV still uses an oil-based lubricant, a small amount of this is consumed and very small CO2 releases result. In addition since combustion still takes place at a high temperature, some NOx emissions also result.
An HICEV can be about 25 percent more efficient than a gasoline ICEV, but this is offset by increases in engine cost resulting from the light nature of hydrogen. It is difficult to get enough air and hydrogen into the cylinders at normal pressure. Either much bigger cylinders are needed or boosting the air pressure through turbocharging or supercharging is needed to achieve the power a gasoline engine provides. Either choice increases the cost.
Perhaps the most difficult technical problem to resolve is storing enough hydrogen on board to travel a reasonable distance. Since the efficiency of the HICEV is only about 60 percent that of an HFCV, much more hydrogen is needed to travel the same distance. This probably will limit the number of HICEVs that enter the market.
Because of the ease in converting an existing gasoline ICEV vehicle design to an HICEV it is likely that if a hydrogen infrastructure were built, some number of HICEVs would also be built. Since the cost of this conversion is much lower than the cost of an HFCV the number could be influenced by future carbon policy or other government actions aimed at increasing hydrogen demand in order to reduce hydrogen cost especially at the beginning of the transition.
manufactured and delivered to a site ready for installation. Research and development has focused on small-scale natural gas reforming and water electrolysis.
This distributed approach likely will include adding hydrogen generating and storage to some existing gasoline filling stations as well as building retail stations specifically designed for hydrogen. The size of the stations can also be increased to become commercial scale (1,500 kg/d), reducing the cost of hydrogen further.
Full-size hydrogen stations, however, require much larger footprints than today’s gasoline equivalent. Typical modern gasoline stations are approximately 6,500 square feet, including a mini-mart. Area requirement is a very significant issue because suitable large sites may be difficult to find in urban areas and acquiring the needed permits is also likely to be difficult. DOE analysis estimates that the footprint for an existing gasoline station will have to be increased by about 7,200 square feet for either a full-size natural gas reformer or a water electrolysis system (Gronich, 2007). Even a smaller unit (e.g., 100 kg/d), would require about 2,200 square feet additional area. In any case, these are significant increases that will limit the number of existing sites that could possibly be used for dispensing hydrogen. This opens up the possibility that many of the hydrogen refueling sites will be at nontraditional locations such as shopping malls and big-box retailer parking areas or even auto dealerships. Box 3.2 discusses the latter option.
Distributed natural gas reforming is the lowest-cost method of delivering hydrogen to an HFCV during this period of low but growing demand for hydrogen. Most large urban areas have an existing natural gas infrastructure allowing its use in such places. For locations in which natural gas is not available, the outer reaches of population centers, or areas between cites along highways. other methods are needed. Water electrolysis is a proven, higher-cost, method of hydrogen production. Table 3.1 summarizes hydrogen
BOX 3.2
Auto Dealers Selling HFCVs and Hydrogen
Auto dealers selling and servicing HFCVs will need hydrogen on-site for initial fills and likely for some types of service. They may be willing to either sell hydrogen to the general public or to provide land to a fuel supplier at their dealer site. It would be a selling point, especially in the early stages of the transition, because dealers could assure customers that hydrogen fuel would be available at least at their facility and neighboring dealerships. Personnel at the dealership would have to be familiar with fueling procedures anyway, so the need for specially trained personnel would be reduced. Many dealerships also would have sufficient land area, unlike most current gasoline stations.
To see if this concept is feasible, the committee examined General Motors dealerships in the Los Angeles Basin. There are 131 GM dealers in the 2,027 square mile basin, or one for every 15.5 square miles. On average, there is one GM dealership within 2.2 miles of every person, which is not a great driving distance to refuel.
Although this is only one example, and indeed a very simplified way of viewing the concept, it appears that dealerships could contribute to hydrogen availability early in the transition. Dealers and customers would have to adapt to a different mode of business, but this should be feasible. Many other types of locations would also be needed because the number of auto dealerships is small compared to the number of gasoline stations.
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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
TABLE 3.1 Dispensed Hydrogen Costs for Distributed Generationa
Process
Future Technology ($/kg)
Current Technology ($/kg)
Natural gas reforming
2.60
3.30
Electrolysis
5.60
7.20
NOTE: Production plant is 1,500 kg/d; natural gas costs $6.10/MBtu; electricity costs $0.08/kWh (see Chapter 6 for other assumptions).
aCosts are at the dispensing nozzle and are derived from the H2A model; they represent the final dispensed hydrogen cost using either technology demonstrated today or with anticipated future improvements and a minimum of 500 installed units.
costs for the main distributed options. Reforming a bioliquid such as ethanol also is possible, although that is in an earlier stage of development (Paster, 2007a). The alternative technologies to natural gas reforming could be useful because they could lead to lower CO2 emissions than natural gas reforming. Electricity for electrolysis could be generated by low-CO2 methods, such as wind power, solar technologies, or nuclear methods. Reforming ethanol or another bioliquid could yield much lower CO2 releases, depending on how the bioliquid is produced. This may become an important distinction depending on future carbon policy and regulations. For example, California currently requires that at least 33 percent of the energy used to produce hydrogen dispensed at state-funded stations be provided from renewable sources.
Late Transition to Self-sustaining Centralized Hydrogen Production
At some point in the hydrogen transition, the drive to increase production and to lower both the cost of hydrogen and the CO2 emissions associated with hydrogen production would shift the emphasis away from distributed production toward very large centralized production plants. This is likely to start between 2025 and 2030 in the MPR case. These central plants could use a variety of primary feedstocks including natural gas, coal, and biomass. In the longer term there could be additional technology options such as hydrogen from high-temperature nuclear and concentrated solar, photobiochemical, and photoelectrochemical methods and from centralized electrolysis using solar or wind energy.
The concept of centralized hydrogen production is very different from today’s centralized refining system for making gasoline, which is characterized by a few very large refining centers. They serve nearby population centers but also feed a large pipeline network for delivering to areas hundreds or thousands of miles away. Gasoline is cheaper to ship by pipeline than hydrogen (on an energy-equivalent basis). As a result, the optimal distribution system for hydrogen would lead to smaller-sized plants located closer to population centers, with few if any long-distance pipelines.
The cost of producing hydrogen at a central plant and delivering it to a station is highly dependent not only on the feedstock cost and conversion technology, but also on the size of a commercial plant and the method and distance of delivering the hydrogen. In a fully developed hydrogen economy, delivery and dispensing of hydrogen could cost as much as its production and consume significant energy.
The first central hydrogen production plants could be needed as early as 2025. With the long lead times needed to plan, permit, and construct large plants, the decisions on what type of feedstock to use would be made about 5 years prior to this. These plants will have to use commercially proven technology. Natural gas reforming and coal gasification technologies are available today. The cost of hydrogen from both feedstocks is similar when feedstock costs are $6 per million British thermal units (Btu) for natural gas and $27 per ton for coal. Twice as much CO2 is produced in a coal-fed plant as one using natural gas. Both types could include CO2 capture technology (at 80 to 90 percent efficiency), which produces a high-purity CO2 stream that can then be sequestered in underground geological formations. Although CO2 capture is a proven technology, CO2 sequestration (i.e., permanent disposal underground) has not yet been adequately demonstrated for commercial readiness.
Biomass gasification for hydrogen production is under development but not commercially ready yet. It is likely that with continued emphasis on development it could be ready for commercial decisions in about 2025. Hydrogen from biomass gasification is more expensive than from natural gas or coal, but the net CO2 releases are very low if land use issues can be kept small (see Chapter 4, “Alternative Technologies for Light-Duty Vehicles”). If CO2 sequestration is not commercially available when central plants are needed, biomass could be an important source of hydrogen that would not contribute to carbon emissions.
Table 3.2 reviews the estimated costs of central hydrogen production. The costs shown in this table are derived
TABLE 3.2 Centralized Plant Gate Hydrogen Production Costs
Process
Future Technology ($/kg)
Current Technology ($/kg)
Natural gas reforming (379 tons/d)
1.50
1.60
Coal gasification (306 tons/d)
1.50
1.90
Biomass gasification (155 tons/d)
1.80
2.50
NOTE: Costs are at the plant gate and represent a learned out cost derived from the H2A model for either technology understood today or with anticipated future improvements. CO2 capture costs are included for coal gasification but not the other technologies. CO2 sequestration costs are not included for any technology. Future delivery and dispensing costs of about $1 to $2/kg (pipeline) or $3.50/kg (liquid) must be added to the production cost for the final delivery cost (Paster, 2007b). Feedstock costs: natural gas $6.10/MBtu; coal $27/ton; biomass $38/ton.
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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
from the H2A model that is the basis of the resource needs analysis in Chapter 6. These costs are plant gate costs. Delivery and dispensing costs have to be added on a case-by-case basis for a final dispensed cost that could be directly comparable to those in Table 3.1 for distributed hydrogen generation.
As with distributed hydrogen production, it is unlikely that centralized hydrogen production will be done using only one feed type or method. The best method in any particular case will be determined based on regional and local issues, including resource availability and hydrogen delivery options, all within any future existing carbon policy.
Hydrogen Safety
Safety issues, both real and perceived, along with the creation of appropriate codes and standards are significant barriers to the introduction of HFCVs and the hydrogen refueling infrastructure and are a significant risk to achieving the maximum practicable penetration rate for hydrogen vehicles. Safety issues along with the need for codes and standards were addressed in The Hydrogen Economy (NRC, 2004) and in the FreedomCAR and fuel partnership review (NRC, 2008). The latter source noted that more urgency is needed to address these issues. It states that “work on safety, codes, and standards is an essential federal role. The individual companies and states cannot do it on their own. The manufacturers want and need uniform national (and hopefully international) standards so they can market on a worldwide basis.”
HYDROGEN FEEDSTOCKS AND TECHNOLOGIES
The maximum practicable HFCV case starts with a few thousand HFCVs sold in 2012 and mass production sales (from 500,000 unit production systems) beginning several years later (after 2015). The questions about hydrogen production then are the following: (1) Will the distributed technologies be ready for commercial use about 2012 to 2015? (2) Will the centralized technologies be ready for commercial decisions about 2020 to 2025? The committee reviewed the readiness of many technologies and includes the following technologies as meeting the criteria of furthest developed and lowest cost: (1) distributed natural gas reforming, (2) distributed water electrolysis, (3) centralized coal gasification with carbon capture and sequestration (CCS), (4) centralized natural gas reforming, and (5) centralized biomass gasification. The discussion below addresses the technologies in their current state of development (current state) and their potential for further improvements (future state). Costs for the current state and future state technologies are based on DOE’s H2A model, which the committee reviewed and accepted.
Distributed Natural Gas Reforming
Catalytically reforming natural gas is now the most common method of producing hydrogen at a large scale for refineries and chemical plants. The challenge for near- and midterm use in a distributed system is to package this industrial process into small units or “appliances,” which can be installed inexpensively at existing retail stations. Making hydrogen directly at the filling station in a distributed system eliminates the need for a large and expensive hydrogen transportation infrastructure. This concept will be very important in the early and mid years of the transition. This concept includes all of the processes that are found in large-scale commercial plants, including the catalytic reformer, catalytic shift reactors, and hydrogen cleanup processes to achieve the appropriate hydrogen purity. Several companies are developing this concept and have demonstrated small appliances that are practical and have an appearance such that they would not look out of place in neighborhood filling stations (James et al., 2007).
The entire process has been successfully demonstrated, and most future developmental work now is directed at improving the efficiency and reducing the cost of equipment. Engineering cost analysis indicates that the overall cost of producing, storing, compressing to 5,000 psi, and delivering hydrogen to a car at a future full-scale 1,500 kg/d station is now $3.30/kg, with the potential to reduce this further to $2.60/kg.1 If the vehicle stores hydrogen at 10,000 psi, as most manufacturers are proposing, the cost will be even higher, but the vehicle will be able to travel farther.
Natural gas reformers appear to offer the lowest-cost method of producing hydrogen for the near and mid term and as such receive continued industrial emphasis. The cost of hydrogen is, however, highly dependent on the size of the reformer (in kilograms per day) and on the cost of natural gas. The hydrogen cost increases with a smaller-size reformer system and with higher-cost natural gas.
To illustrate this point, the natural gas price used for estimating a $2.60/kg cost just mentioned is $6.10 per million Btu. If the natural gas price is increased to $10 per million Btu then the hydrogen cost is increased to $3.30/kg.
The ability to use distributed natural gas reformers in various sizes could be very useful during the initial transition to hydrogen to keep capital costs as low as possible—in
1
At a natural gas cost of $6.10/MBtu. All of the costs of making hydrogen in this chapter are based on the assumptions discussed in Chapter 6 unless noted in the text. A kilogram of hydrogen has approximately the same energy content as a gallon of gasoline and is sometimes referred to as a gasoline gallon equivalent (gge). To compare the cost of hydrogen with the cost of gasoline one must also take into account the mileage of the vehicles. In the Chapter 6 analysis, the fuel cell vehicle achieves two times the fuel economy of the gasoline ICE on a gge basis. In this analysis, an HFCV using 1 kg of hydrogen will then travel the same distance as a gasoline ICEV using 2 gallons of gasoline. Thus, hydrogen purchased at $2.60/kg for an HFCV yields the same cost per mile as gasoline purchased for a conventional vehicle at $1.30/gal.
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essence, matching the size of the reformer to the localized demand for hydrogen. This could, however, lead to higher hydrogen costs because cost increases as reformer size decreases. For example, if the 1,500 kg/d reformer mentioned above is reduced to 500 kg/d size, then the hydrogen cost increases from $2.60/kg to $3.50/kg. Further reducing the reformer size to 100 kg/d increases the hydrogen cost to $6.20/kg.
Significant progress has been made in developing distributed natural gas reforming such that it could be ready for commercial use in the early transition years (2015 or earlier). Even with this success, still further efficiency increases and cost reductions are possible.
Distributed natural gas reforming (DNGR) will release some CO2 into the atmosphere. It is not feasible to use CCS technologies in this distributed process to capture and sequester the CO2 because of the large number of sites and the small size of each of them. However, on a WTW basis, an HFCV using hydrogen from DNGR units will emit less than half that emitted by a conventional ICE vehicle using gasoline, as shown in The Hydrogen Economy report (NRC, 2004).
The greatest potential challenges to the use of DNGR technology in the hydrogen transition are identifying and permitting land use for the refueling sites and the cost and availability of natural gas.
Distributed Water Electrolysis
Electrolysis of water is now a common way to produce small amounts of hydrogen. Scaling up an electrolyzer to full size (about 1,500 kg of hydrogen per day) has been demonstrated, and commercial alkaline electrolyzers are available in various sizes. For instance, Norsk Hydro reliably operates a 600-700 kg/d alkaline electrolyzer. Water electrolysis could play a role in the early to mid stages of the hydrogen transition because of the advanced stage of technology development, the widespread availability of electricity, and the relatively simple operation of an electrolyzer.
In alkaline electrolysis, water under an applied voltage dissociates into hydroxyl ions and hydrogen on one side of a wetted mat of sodium or potassium hydroxide solution. The hydroxyl ions traverse the wetted mat and form oxygen on the other side. Electrodes are inexpensive nickel. This is different from the polymer electrolyte membrane (PEM) process considered in many studies, including The Hydrogen Economy (NRC, 2004). That process involves transport of hydrogen ions across a polyelectrolyte membrane under an applied voltage using noble metal-based electrodes. The alkaline process is favored over the PEM process primarily because it does not require the costly membrane and platinum-based electrodes of the PEM process and scales up more economically at scales above 25 kg/d (Harg, 2007).
Electricity is the largest cost component of hydrogen production by electrolysis. Because the primary source and hence the cost of electricity vary considerably by region, state, and in many cases locally in the United States, the cost to make hydrogen varies widely. For example, in 2004, industrial electricity averaged 9.5 cents/kWh in California, 8 cents/kWh in Vermont, and 3.9 cents/kWh in Wyoming. This translates to the electricity cost component of making hydrogen varying from $2.10/kg hydrogen in Wyoming to $5.00/kg hydrogen in California at 74 percent electrolyzer efficiency. At a design hydrogen production rate of 1,500 kg/d and an average industrial electricity cost of 8.0 cents/kWh, the cost using current technology is $7.20/kg hydrogen. Future technical improvements are evolutionary in nature, which could result in a total hydrogen cost of $5.60/kg hydrogen (Fletcher, 2007).
The sensitivity to electricity cost is about $0.50 in hydrogen cost for each 1 cent/kWh in electricity cost, so for 2 cents lower electricity cost than the average, the hydrogen cost would be $1.00/kg lower. For the hydrogen cost from electrolysis to be in a competitive range with other feasible sources of distributed hydrogen supply (about $3/kg), electricity would have to be available at an unrealistically low cost of 2 cents/kWh (Levene, 2007). Well-to-wheels CO2 emissions from distributed water electrolysis (DWE) could be higher than for DNGR if the electricity is generated with the current U.S. feedstock mix.
The greatest challenge to the use of DWE for hydrogen is cost. However, electrolysis of water still may be used where lower-cost methods are not available (natural gas reforming) or where environmental advantages are possible through the use of solar or wind power for electricity. In selected areas with no other source of hydrogen, policies could be put in place to help supply during a growing hydrogen transition.
Central Coal Gasification with Carbon Capture and Sequestration
Commercial large-scale high-pressure gasification plants have been used for many years to produce a syngas (carbon monoxide [CO] and hydrogen) for either power generation or further conversion to chemicals. These plants run on heavy oils, petroleum coke, or coal. In this sense the basic core technology is technically and economically ready.
Although the core gasification technology is commercially available, the overall plant design and integration of the gasification module with the downstream processing modules can still be improved through further development to lower the production cost (Litynski, 2007). Co-producing power and hydrogen at a large coal gasification facility is likely to be the lowest-cost method for making hydrogen (NRC, 2004). This concept also has not yet been demonstrated at a large scale although all of the processing modules needed are commercially available.
The largest single challenge for widespread use of coal to make hydrogen is to lower CO2 releases to acceptably
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low levels. In the case of an oxygen-supplied gasification, capturing CO2 is relatively inexpensive. This CO2 must then be piped to a CO2 sequestration site and injected into underground storage. In a future with constraints on carbon emissions it is likely that if coal is to be used to make large amounts of hydrogen, CO2 sequestration must be adequately demonstrated and commercially available.
Large-scale CO2 sequestration from an integrated coal gasification plant with CCS has not yet been adequately demonstrated. Several partnerships have been formed to further develop and demonstrate CCS technology involving DOE, 41 states, and more than 400 organizations. Seven sequestration injection tests have been awarded funding through these partnerships (Litynski, 2007). The goals of this work are to verify that the costs of CO2 capture and sequestration are not high (less than 10 percent increase in power or hydrogen costs) and that any sequestered CO2 will remain so (less than 1 percent leakage after 100 years). Since it will take many years to complete this program, success may not be known prior to the start of the hydrogen transition.
The cost of hydrogen produced at a central gasification plant is estimated to be $1.50/kg at the plant gate (Joseck, 2007) for a 2,400-ton-per-day plant that makes 306,000 kg/d. This does not include costs for carbon sequestration, which should be low as a percent of the total hydrogen delivered costs (NRC, 2004)). Additional pipeline delivery and dispensing costs could increase the final delivered cost to $2.60/kg (Paster, 2007a). Table 3.2 summarizes hydrogen plant gate production costs for the key central production technologies. The cost of making hydrogen from coal is somewhat insensitive to the price of coal, because most of the overall cost is related to the large capital cost of the plant. For instance, tripling the coal cost, from $27 to $81 per ton increases the hydrogen cost by about $0.50/kg.
The greatest challenge to the use of coal gasification for hydrogen production is demonstration of the costs, capacity, safety, and risks of long-term carbon capture and sequestration. Although coal gasification is a commercially available technology, to reach the future cost estimates shown in Table 3.2, some further development is needed. Standardization of plant design, gas cooler designs, process integration, oxygen plant optimization, and acid gas removal technology shows potential for lowering costs. Other areas that can have an impact on future costs include new gasification reactor designs (entrained bed gasification) and improved gas separation (warm or hot gas separation) and purification technologies. These technologies need further R&D before they are commercially ready.
Central Natural Gas Reforming
Steam methane reforming of natural gas is the predominant method of making large amounts of hydrogen for the chemical processing industry and the refining industry. It is a well-developed and inexpensive commercial process with no real technical barriers to its expanded use to make hydrogen for transportation. The current cost of producing hydrogen at a 380-tonne-per-day plant is $1.60/kg at the plant gate for a natural gas cost of $6.10/MBtu (H2A model runs). This cost is similar to that of hydrogen from a coal gasification plant. Adding on delivery and dispensing costs could increase the final supply cost to about $2.90/kg. Because steam methane reforming is such a well-developed commercial technology, little future cost improvement is expected. As shown in Table 3.2 the future plant gate cost is anticipated to decrease to $1.50/kg at the same natural gas cost.
There are two primary issues with using significant natural gas resources to make hydrogen for transportation. One is CO2 releases, and the other is the availability and cost of natural gas. The CO2 associated with hydrogen production and use in an HFCV is about half of that associated with a gasoline ICEV. From this perspective, using natural gas to make hydrogen results in lower CO2 emissions. As with coal gasification, this CO2 can be captured and sequestered, and if done, the CO2 releases will be very small.
The largest barrier to widespread use of central natural gas reforming technology is the availability and price of natural gas. Since the incremental natural gas supply to the United States is currently from imported liquefied natural gas (LNG) and imports are expected to grow in the future, using natural gas to make hydrogen will increase the requirement for imports. Although natural gas pricing is a complex issue, it is likely that a significant number of HFCVs using natural gas will increase natural gas demand enough to affect natural gas prices, which in turn would have a great impact on the power sector (a heavy user of natural gas). If natural gas is the source of hydrogen for 10 million HFCVs, the demand for natural gas in the United States would increase by about 2 percent, probably not enough to have a significant impact on prices. However, 50 million cars, less than 20 percent of the light-duty vehicles expected in the country in 2020, would increase natural gas demand by 10 percent, which probably would increase prices.
Centralized Biomass Gasification
Biomass may consist of waste by-products of agriculture, such as corn stover or wheat straw, or forest residues; it also can be expressly cultivated as an energy crop, for example, switchgrass. It could be gasified in the same type of high-pressure oxygen-fed gasifier used for coal, but that alternative may not be the best for gasifying biomass to make hydrogen. High-pressure gasifiers tend to be less economical at small scales than at a large scale. Much of the feedstock and some of the process issues with biomass gasification are similar to those for biofuels discussed in Chapter 4.
Because biomass is produced in relatively small quantities per farmed acre in a dispersed agricultural system, a biomass plant is likely to be much smaller than other central production methods such as a coal gasification plant. The size of
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any biomass plant will be determined by its proximity to a large acreage of land that has available agriculture biomass, that is appropriate to grow energy crops, or that contains forest residue, while also being near large population centers. Biomass starts out with an inherent environmental advantage versus coal or natural gas since CO2 is cycled from the atmosphere in its growth and cycled back to the atmosphere in its processing, which can result in little net CO2 emission to the atmosphere without the need for carbon sequestration if land use issues are kept to a minimum.
Given the economic reasons for smaller plants, a different gasification technology could prove to be a better choice for making hydrogen from biomass. There have been several small-scale (100 to 300 tons per day of biomass feed) biomass gasification test plants operated using a low-pressure, indirectly heated air gasification process, for example, a 300 tons per day Battelle gasifier unit producing fuel gas for electric power generation in Vermont. In this process the biomass is gasified with air at high temperature and atmospheric pressure to produce a mixture of CO and hydrogen. Because the Battelle gasifier operates at low pressure, it has the potential to be less capital intensive than the high-pressure oxygen gasifier, which also requires an air separation unit for oxygen feed.
DOE bases its future technology plans on the indirect-heated low-pressure air gasifier type plant at 155,000 kg hydrogen per day. The biomass feed rate required for a plant this size is 2,125 tons per day (Mann, 2007), and the land needed to supply such quantities is about 180 square miles for an energy crop such as switchgrass. The number of available sites must be determined that could support such a large plant and still have acceptable delivered biomass cost and delivered hydrogen cost with limited land use issues. The DOE estimates roughly 50 potential sites throughout the country at current biomass yields and upward of 100 sites with future crop technology (Joseck, 2007).
With future technology, DOE targets biomass crop yields per acre increasing 50 percent because of applied plant genetics and crop rotation practices. This is based on a model that assumes switchgrass, a 45 percent component of projected biomass availability, will develop in crop yield similar to the achievements with corn. However, the potential for yield improvements in other components of biomass, for example, corn stover and wheat straw, is uncertain.
The total hydrogen production cost at the plant gate based on this future technology is $1.80/kg hydrogen with a biomass feedstock cost of $38 per dry ton (Table 3.2). Delivery and dispensing will add additional costs of about $1.70/kg (pipeline delivery is higher than for coal plants because biomass plants are smaller) to $3.50/kg (liquid truck delivery) to the plant gate cost. Total projected biomass availability at $38 per dry ton is 200 million dry tons in 2015 and 500 million dry tons in 2025, based on DOE estimates reviewed with this committee (Hess, 2007). If all of the 500 million dry tons were converted into hydrogen, this would be about 37 billion gallons of gasoline equivalent, or 26 percent of today’s gasoline market.2
Biomass gasification is promising, but much remains to be done to put it on a solid basis. Crop yield assumptions need to be demonstrated. Preparation of the different types of biomass feedstock for ease of delivery and reliable processing in the gasifier needs to be determined. The true number of sites that can actually supply large amounts of biomass without incurring large land use problems has to be understood.
Significant research, development, and technology demonstration is required before the future costs shown in Table 3.2 can be achieved. Although individual parts of the biomass gasification process have been demonstrated, the entire process has not been demonstrated. Bench-scale, pilot plant, and semicommercial-scale work is needed to have a firm basis for scale-up to a 2,125-ton-per-day plant or larger. Also, gas cleanup and separation technologies into pure hydrogen need to be demonstrated while dealing with contaminants and tar. The committee judges that technology readiness by 2015 will be difficult to achieve; several years more may be needed. However, if successful, hydrogen supply from biomass gasification could phase in with other supply sources of hydrogen.
HYDROGEN FUEL CELL VEHICLE TECHNOLOGIES
The HFCV is an all-electric automobile. It differs from previous generations of electric cars in that the power is provided by a hydrogen fuel cell on an as-needed basis. Previous generations of electric vehicles stored energy only in batteries whereas the HFCV stores its energy primarily in a hydrogen tank. Most major automakers have demonstrated different iterations of HFCVs, with each version demonstrating new concepts to achieve performance that is approaching that of today’s gasoline vehicles. Some HFCV prototype vehicles also include some degree of energy storage in batteries using the same technology that is in today’s gasoline hybrid vehicles. These prototype vehicles have demonstrated significant success in overcoming difficult technological challenges, such as reducing the size and weight of the fuel cell and improving operation in cold weather. However, even with the significant improvements of the past few years,
2
The biomass gasification technology discussed in The Hydrogen Economy is based on a conventional high-pressure oxygen gasifier at just 24,000 kg hydrogen per day, a small scale to ensure economic biomass supply (NRC, 2004). This is in contrast to the larger plant and broader feedstock supply reach envisioned in the future technology and the low-pressure indirect heated gasifier of the future technology discussed above. The biomass feed rate for this small plant is 442 dry tons per day from a 57 square mile collection area. The total hydrogen cost estimate is $7.00/kg hydrogen at a biomass feedstock cost of $53 per ton. The total cost is particularly high since hydrogen liquefaction and tanker transport are required because pipeline supply is not economic at such a small scale.
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there are still several areas that need further improvement. The key component technology challenges for the HFCV are (1) making the fuel cell system as durable and cost-effective as today’s gasoline internal combustion engine vehicle, and (2) engineering a small, lightweight hydrogen storage system to provide an acceptable driving range, 300 miles or more. The degree of success in these areas will determine when the HFCV can be commercialized and how effectively it can compete with today’s ICEVs. This section discusses these issues and provides a context for how they can be viewed to meet the maximum practicable rate of penetration for HFCVs.
Recent History
Several major automakers have been developing the HFCV in earnest since the early 1990s. By the mid-1990s Daimler-Benz announced that it would begin production of HFCVs in about 2004. Although a small number of test vehicles has been produced, commercial production has not yet begun. In 2003 GM announced that production could begin in 2010, but more recently GM has pushed this date back to 2011 or 2012.3 Because of the highly competitive nature of the auto industry, not every automaker has made its plans available to the public.
This situation suggests the uncertainty and risks involved in introducing a new vehicle technology to the market. One of the benefits of the FreedomCAR and Fuel Partnership (FCFP) is that all of the known areas that require further development for HFCV commercialization are included with developmental targets and dates for completion specified. This permits more realistic assessments of the state of overall development. To date, only a few hundred HFCVs have been produced, with none of the advantages of mass production. Costs in high-volume manufacturing can be estimated only roughly, because several major subsystems are still in the development stage and “tight” manufacturing estimates are not available. In the traditional process for developing a new-technology power train for commercialization, once the technology is developed, hundreds of vehicles are put into experimental stressful applications (such as police vehicles) to ensure that there are no “unknown-unknowns” that could cause premature durability problems. Following that step, small-scale volume production in the thousands can begin.
Since the HFCV will require a new fuel as well as a new power train, the automotive and fuel companies are working together to develop standards for the vehicle-fuel interaction (e.g., the purity of hydrogen required for the vehicle and the fueling protocol). Hydrogen fuel standards are currently under study by the Society of Automotive Engineers (SAE) and the International Organization for Standardization (ISO) (i.e., SAE TIR J2719 and ISO 14687-2, respectively). Once the fuel standards are developed (expected in 2008), fuel companies can then begin to build a large enough number of distribution outlets to satisfy early HFCV customers that they will be able to acquire fuel safely and conveniently.
HFCVs and Fuel Cell Technology
Progress in fuel cell development has been rapid. Vehicle fuel cells are much smaller and lighter than they were just several years ago. Fuel cell costs have decreased, while performance and durability have increased considerably. However, production-quality vehicle fuel cells are still in the development stage.
To the best of this committee’s knowledge, no vehicle fuel cell system has yet met the full set of rigorous automotive specifications required for high-volume sales to customers. In some sense, these requirements must be met before an automobile company can get on the high-volume manufacturing (500,000 units) cost reduction curve. Furthermore, there is a degree of uncertainty about the manufacturing cost estimates because fuel cells have not yet been manufactured on a large scale. Thus, current cost estimates are derived from detailed engineering studies, as they were in NRC (2004, 2005, 2008), Walsh et al. (2007), and Brunner (2006). On the other hand, all major automotive manufacturers have seen enough progress that, as a group, they are spending billions of dollars to bring fuel cell vehicles to high-volume production. The main debate among the manufacturers appears to be concerned with “when,” not “if.”
More recently, the NRC FCFP review committee noted, “Fuel cell stack life currently limits the overall demonstrated powerplant durability to only about one fourth of what is needed to meet the performance targets set forth by the Partnership. A major reduction in stack life occurs in actual vehicle applications because of the many stops and starts and transients with vehicle operations, fuel composition, and related phenomena when compared to what is observed with the testing methods and conditions in laboratory development work. In addition, as laboratory fuel cell stack lifetimes lengthen, new failure modes are surfacing and must be better understood and resolved. One such example is platinum catalyst dissolution, which impairs long-term performance. The prompt resolution of these and new failure modes, as they are discovered, is critical to achieving 2010 and 2015 targets” (NRC, 2008, pp. 56-57).
Fuel cell costs have been reduced significantly over the past 4 or 5 years. Cost projections for high-volume (500,000 units per year) automotive fuel cell production are estimated to be $100/kW for relatively proven technologies and $67/kW for newer laboratory-based technologies (which may be compared with the DOE/FCFP commercialization goal for 2015 of $30/kW). The cost of platinum is 57 percent of the fuel cell stack costs and is the greatest challenge to
3
Larry Burns, GM vice president of R&D and Strategic Planning, said, “I don’t know how many of them we’ll make at the time, but we should have them in showrooms by early next decade, around 2011 or 2012. Post-2012, the goal is to ramp up production to about a million vehicles a year, worldwide” (Burns, 2007).
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FIGURE 3.1 ZEV panel vehicle market penetration estimates. SOURCE: Walsh et al. (2007).
further cost reductions.4 Future platinum supply is a critical issue in forward projections of fuel cell costs. Fuel cell stack life has increased to over 1,500 hours compared to the DOE/FCFP 2015 goal of 5,000 hours. Focused research on problems, together with recent advances in electrode and membrane technology, should further reduce costs and increase stack life.
Walsh et al. (2007) reports on an extensive analysis of fuel cell systems, as well as competing technologies that produce very low emission vehicles in the study called Status and Prospects for Zero Emissions Vehicle Technology: Report of the ARB Independent Expert Panel. These analysts visited 10 automotive manufacturers, reviewed proprietary information, and developed the following assessment after their visits and data gathering: “Each of the developers believes that the simultaneous requirements can be met but on different time schedules. For example, one major developer’s objective is to compete with the ‘upper’ segment of ICE vehicles in the year 2020 at volumes of 100,000 units per year. Another major developer’s assessment is that a commercially viable fuel cell system would be available in 2010, if a production rate of 500,000 units per year could be realized” (p. 8). The panel also noted: “There are large technical barriers that can be solved but there are other issues that are beyond the control of any single auto manufacturer. Widespread deployment of FCEVs will require continuous strong support from government agencies. This support must include a clear message of long term commitment to … FCEVs. These include adequate and affordable hydrogen refueling, as well as a host of sustainable financial incentives to help minimize the capitalization risks of all key stakeholders during the initial transition years. Ultimately, consumer knowledge and willingness to buy these vehicles in high volume is required” (p. 130).
Walsh et al. (2007) contained an overall estimate of market introduction time frames for the various low-emission vehicle technologies they analyzed (Figure 3.1). That ZEV expert panel’s estimate is that production of thousands per year could occur by 2009, with tens of thousands per year by 2020, and then mass commercialization by 2025, with the statement that “the panel remains cautiously optimistic for fuel cell system commercialization” (p. 130). The estimates just discussed along with presentations from auto manufacturers and information included in the other resources noted were used in developing the HFCV market penetration scenarios in the Chapter 6 analysis.
The committee concludes that the current state of fuel cell development does not yet meet all of the performance and cost requirements needed for large-scale commercial production. If the recent progress in size and weight reduction, cold-weather operation, and durability improvements can be continued over the next few years, a usable fuel cell technology may be made ready for introduction by 2015. The costs of the early fuel cells are likely to be higher than the commercial targets, but these costs can drop with continued development and large-volume manufacturing.
4
The stack is the heart of the fuel cell. It contains the membrane through which hydrogen passes to react with oxygen, generating electricity.
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FIGURE 3.2 BMW assessment of on-board liquid hydrogen storage. SOURCE: Brunner (2006).
HFCVs and Hydrogen Storage
Hydrogen can be stored on board a vehicle as a gas, liquid, or solid. All of these techniques have been demonstrated in HFCVs in recent years. All continue to be developed through government research and industry programs. At this point there is no consensus as to which storage state will be the best long-term solution. However, there is a growing consensus that in the short term, high-pressure gaseous storage is the most practical solution.
Solid hydrogen storage systems that are made up of a low-pressure tank filled with a solid storage material with a thermal management system have the potential to be small and lightweight, which aids in overall weight savings and improved fuel mileage. They may present the best long-term storage solution but at present are still mainly in the research stage (to identify the best solid medium for storing hydrogen). Thus, it is important to develop solid hydrogen storage systems as well as to integrate them into the vehicle in an energy-efficient manner. For further discussion of solid storage technical readiness, see NRC (2008) and Walsh et al. (2007). Based on the committee’s current knowledge that no solid storage medium has yet met all of the developmental targets, it is unlikely that solid hydrogen storage systems will be production ready in 2015.
Liquid hydrogen currently provides the densest form of storage, which means that the most fuel can be stored on board. BMW has recently demonstrated a liquid storage system. Two formidable problems must be overcome to make liquid storage practical for widespread use. Liquid hydrogen must be kept at about −252°C (about 20°C abve absolute zero). The BMW system has impressive insulation, but some heat still gets in and gradually boils off the hydrogen. This can result in serious safety issues. The other issue is cost, currently on the order of $500/kWh, with a goal of approximately $100/kWh in the “next generation” (Brunner, 2006). The eventual goal is $15/kWh. To put these numbers in perspective, the FreedomCar targets for 2010 and 2015 are $4/kWh and $2/kWh, respectively. As shown in Figure 3.2, today’s system suffers from performance, durability, and maintenance issues in addition to the noted major cost issues. The figure shows just inside the rectangle the areas in which R&D is being performed, and the goals are on the perimeter of the 10-sided figure (e.g., keeping evaporation losses to less than 25 percent per month for the infrequent driver). Inside this is the current status of progress toward the goal (e.g., less than 50 percent of the way for evaporation loss). Because of these concerns, the committee does not believe liquid storage systems will be commercially viable in the 2015-2020 time frame without unexpected breakthroughs in liquefaction and insulation.
As noted by Walsh et al. (2007), “With the exception of BMW, every other OEM [original equipment manufacturer] contacted indicated that this (compressed gas) was the only realistic short term (5-10 years) choice available and only Honda indicated that they intend to limit the storage pressure to 350 bar.5 All the other OEMs preferred 700 bar, which will provide storage of over 50% more fuel in the
5
One bar equals one atmosphere of pressure (14.7 pounds per square inch [psi]), so 350 bar is about 5,000 psi and 700 bar is 10,000 psi.
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same space envelope and correspondingly provide almost 50% more range.”
The DOE goal for hydrogen storage systems is enough fuel to travel about 300 miles (a similar range to that of today’s gasoline ICEV). The amount of hydrogen needed for this depends on the fuel consumption of the HFCV. Toyota demonstrated in September 2007 a 4,145-pound, five-passenger HFCV with 700-bar compressed hydrogen storage that traveled 350 miles in real-world on-the-road conditions in a drive from Osaka to Tokyo. Toyota calculated that the vehicle is now capable of achieving a cruising distance of 466 miles. It appears that the latest HFCV designs using high-pressure hydrogen storage can meet the 300-mile goal.
Less progress has been made in meeting the cost targets for such a system. The 2005 NRC review of the Freedom-CAR and Fuel Partnership listed the circa 2004 cost status as $15/kWh and $18/kWh for the 350- and 700-bar systems, respectively. The 2008 NRC review of the FCFP did not update these costs, and discussions with auto companies indicated that little has changed with regard to costs for compressed hydrogen storage.
Based on these facts, the committee concludes that compressed hydrogen storage systems that provide practical driving ranges (300 miles) should be available in 2015, but the cost will be higher than that of the current FreedomCAR targets. There is potential to lower the costs in the future through the use of lower-cost carbon fiber tanks or by using future solid storage systems.
In summary, onboard hydrogen storage to achieve a 300-mile driving range has been the greatest technical challenge of all in trying to develop an HFCV. The quest to identify solid storage materials to achieve the DOE-FCFP 2015 goals, including the cost goal of $2/kWh, is in the research stage. It is not clear at this time whether a suitable material will be identified that can meet these goals and timing targets, but to achieve the desired driving range between refueling stops, the industry is prepared to use more expensive high-pressure hydrogen storage tanks that consume more space and add to vehicle weight while research progresses toward a commercially viable solid hydrogen storage material.
Technology Basis for the Scenario Analysis
The committee concludes that not all the FreedomCar goals for 2015 are likely to be met, but the technology may be good enough for high-volume HFCVs to be introduced then anyway. For the scenarios analyzed in Chapter 6, the committee assumes that the hydrogen storage system will be larger and more costly than the targets but will be able to provide adequate driving distance. The fuel cell system will be more costly than the target initially but will provide the necessary performance expected of an early commercial vehicle. Although the initial costs will be high, there is considerable scope for continued cost improvement through technology improvements and high-volume production. For the maximum practicable case, the committee estimates that the fully learned out cost for the fuel cell drive train (the fuel cell system, hybrid battery, motor, and auxiliaries) for the automaker (OEM) will be $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 the plant. Hydrogen storage costs the OEM $10/kWh compared to DOE 2015 goal of $2/kWh for solid storage. The fuel cell cost is the same as the 2015 DOE goal, while the storage costs are higher than the DOE 2015 goal because high-pressure hydrogen gas storage was assumed in the latter.
CONCLUSIONS
CONCLUSION: If appropriate policies are adopted to accelerate the introduction of hydrogen and HFCVs, hydrogen from distributed technologies can be provided at reasonable cost to initiate the maximum practicable case. If technical targets for central production technologies are met, lower-cost hydrogen should be available to fuel HFCVs in the latter part of the time frame considered in this study. Additional policy measures are required to achieve low-carbon hydrogen production in order to significantly reduce CO2 emissions from central coal-based plants.
CONCLUSION: Lower-cost, durable fuel cell systems for light-duty vehicles are likely to be increasingly available over the next 5-10 years and, if supported by strong government policies, commercialization and growth of HFCVs could get underway by 2015, even though all DOE targets for HFCVs may not be fully realized.
Considerable progress has been accomplished since The Hydrogen Economy (NRC, 2004) toward a commercially viable hydrogen fuel cell vehicle due to the concentrated efforts of private companies and governments around the world. Although considerable progress is still required in fuel cell costs, durability, and storage before commercialization can begin, the automotive industry appears committed to the technology for the long run. Thus, lower-cost, durable fuel cell systems for light-duty vehicles are likely to be available in a growing number of vehicles over the next 5-10 years, but meeting all 2015 DOE commercialization targets will be difficult.
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