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Transitions to Alternative Transportation Technologies — A Focus on Hydrogen
5
Role of the Stationary Electric Power Sector in a Hydrogen Fuel Cell Vehicle Scenario
The U.S. stationary electric power system is composed of generating facilities that convert primary energy sources into electricity, transmit that electric power at high voltage over distances ranging from a few miles to hundreds of miles, and distribute it, at reduced voltages, to an array of customers ranging from residences to large, industrial complexes. The most important primary energy sources today are coal, oil, natural gas, nuclear fuels, solar, wind, and hydroelectric power.
Unlike hydrogen, which can be produced and stored, electricity must be produced instantaneously to meet the demand for electric power, because there are very limited viable methods for large-scale electrical energy storage. This difference may provide a useful mechanism for the production of hydrogen. Hydrogen and electricity do share an important characteristic—namely, both energy carriers are derived from other primary energy resources, another fact that may prove to be synergistic. Figure 5.1 shows schematically the various ways in which the stationary power sector can interact with the transportation sector.
In 2005 the nation’s electric power system, owned by hundreds of investor-owned, cooperative, and government utilities was composed of 978 gigawatts (GW) of generating capacity and produced 4,055 (TWh; terawatt-hours (billions of kilowatt-hours) of electricity) (EIA, 2007). Because of the typical daily load cycle of the generation, there is a meaningful fraction of generation capacity that is not used in the off-peak period. One could not fully utilize all of that unused
FIGURE 5.1 Stationary power and the transportation system. SOURCE: Beriesa (2007).
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capacity for other purposes. However, as a measure of potential resource availability, off-peak capacity could in principle fuel more than a third of the light-duty fleet for a daily drive of 33 miles on average (Kintner-Meyer et al., 2006).
In considering the current and future electric power sector, there are three ways in which it could be a significant factor in a hydrogen fuel cell vehicle (HFCV) future: (1) hydrogen production, either through electrolysis or co-production with electricity, (2) synergies between fuel cells for transportation and stationary applications, and (3) use of electric power for battery-powered vehicles. On this basis, three groups of questions emerge:
To increase the hydrogen available for transportation by 2020 and/or 2035, what could be done in the stationary power sector to accelerate hydrogen production? What are the technological requirements? What incentives would help?
How best can we develop and accelerate the use of hydrogen in the stationary power sector by 2020 and/or 2035? Again, what are the technological requirements and incentives?
Is there a plausible alternative use of the stationary power sector’s excess capacity and infrastructure that can result in a viable alternative to hydrogen use in transportation in 2020 and/or 2035?
TECHNOLOGICAL READINESS
It is useful first to examine the technological readiness of the systems mentioned earlier and the likelihood of their deployment in 2020 and 2035.
Hydrogen Production in the Power Sector
Producing hydrogen as a transportation fuel is somewhat similar to producing electricity for stationary use because both are energy carriers that require primary energy sources (mainly coal, nuclear, natural gas, and hydropower). About 40 percent of all energy used in the United States goes to producing electricity, which is the main form of energy in the residential and commercial sectors. Less than 3 percent of electricity is produced from oil as shown in Figure 5.2.
Furthermore, power plant emissions have declined significantly even though electricity demand continues to grow. This is shown for nitrogen oxides (NOx) and sulfur dioxide (SO2) in Figure 5.3. In the future, expected pressures for cleaner electricity production processes will continue the evolution toward low or zero emissions. In addition, the power industry is facing a significant challenge to reduce greenhouse gas (GHG) emissions in anticipation of a future carbon constraint. This has resulted in a move toward low or zero-carbon emitting technologies (i.e., renewable energy, nuclear energy, and fossil energy with carbon capture and storage). Tying hydrogen production to the industry’s assets
FIGURE 5.2 Energy source consumption for electricity generation. Renewable energy includes hydroelectric power. SOURCE: EIA (2007).
FIGURE 5.3 Nationwide NOx and SO2 emissions from the power sector. SOURCE: Srivastava et al. (2005).
and processes could extend electric power benefits into the transportation sector, which is currently heavily oil dependent, with attendant pollutant and GHG emissions. Toward this end, an ad hoc group, the Hydrogen Utility Group, was formed in 2005 by nine power companies with the support of the Department of Energy/National Renewable Energy Laboratory, Electric Power Research Institute and National Hydrogen Association to explore the potential synergies between electricity and hydrogen production.
Hydrogen Production in the Power Sector: Electrolysis (Near Term)
As explained in Chapter 3, electrolysis (splitting water molecules to release hydrogen) is a proven, commercially
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available technology. Electrolysis, although more expensive than natural gas reformation, offers some unique features as an alternative method:
Since the infrastructure to deliver electricity exists in every corner of the United States, hydrogen can be produced close to or at the point of distribution, thereby minimizing initial capital investments in hydrogen infrastructure.
Unlike the reformation process where natural gas is the sole primary energy source, the energy sources for electricity production are diverse, including fossil fuel such as coal and natural gas; nuclear; and renewable energy, such as hydro, wind, solar and biomass.
The cost of electricity has been and is expected to remain much more stable than natural gas prices due to fuel diversification in the power generation sector. (In specific regions, factors such as regulated-deregulated market and marginal cost of power generation for electrolytic hydrogen production could impact such comparisons.)
Hydrogen produced by electrolysis emits no harmful substances at the point of production, which would be beneficial in environmentally sensitive urban areas. CO2 emissions from power plants would be easier to capture and sequester than those from small natural gas reforming plants.
Continuing progress to clean up power plant criteria and CO2 emissions will ensure that hydrogen produced from electricity in the future will benefit from the increased cleanliness fossil fuel power generation.
As a side benefit, the electrolysis process also produces oxygen that may have a market value.
As explained in Chapter 3, large electrolyzers using alkaline technology (producing more than 500 kg of hydrogen per day (kg/d) constitute a proven, commercially available technology. Smaller electrolyzers, using proton exchange membrane (PEM) technology, require more research, development, and demonstration (RD&D) to improve durability and efficiency and to reduce capital cost. For example, the capital cost per unit of production of a 10 to 100 kg/d PEM electrolyzer is four to seven times that of a 1,500 kg/d unit (EPRI, 2007). These smaller PEM units, if successfully developed, could provide an alternative or complementary approach to natural gas reformation for hydrogen production during the early commercialization stage.
From the power industry’s perspective, the installed generation capacity of any utility is built to meet peak power demand. Thus, a portion of this capacity sits idle during off-peak periods, such as during the night when demand is reduced. This results in cycling of the power plants to respond to time-varying demand. While some plants are explicitly designed for peaking operations (e.g., combustion turbines), others are designed for base load operation (e.g., coal, nuclear). To the extent that base load plants are not used for base load operation, they must be cycled on a daily basis, and this carries a significant “wear-and-tear” cost penalty from cycling them up and down. If that capacity could be used to produce hydrogen during the off-peak period, via electrolysis, power plants could minimize such cycling and hence increase overall capacity factor and asset utilization. If 10 percent of all light-duty vehicles were fueled with hydrogen produced solely from electrolysis off-peak, the U.S. grid could realize an average of 8 percent increase in load factor. However, the electrolyzer plant would operate only about 50 percent of the time, and the increased capital charge per kilogram of hydrogen produced would to some extent offset the reduced power cost.
Today the electrolysis process is only moderately efficient, which makes it applicable only in certain niche markets when high-purity hydrogen is required. However, it would be beneficial to develop more efficient and cost-effective electrolysis technology. Capital cost reduction and improvements in electrolysis efficiency would be very useful, potentially making the economics of electrolysis more competitive with natural gas reformation.
Hydrogen Production in the Power Sector: Co-production (Long Term)
If HFCVs become widespread and hydrogen vehicle penetration increases in the longer term, large central hydrogen production facilities become more viable due to economies of scale. As described in Chapter 3, hydrogen production from coal with carbon capture and sequestration (CCS) could become one plausible way to meet the larger demand.
Integrated gasification-combined cycle (IGCC) power generation technology using coal is being developed, demonstrated, and commercialized. IGCC is more efficient in both power generation and emission control and, hence, could become the preferred alternative to pulverized coal power plants using a conventional combustion process. Furthermore, capturing and storing carbon dioxide (CO2) produced from the coal in geologic formations 5,000 to 10,000 feet under the ground would reduce its impact on climate change, if long-term burial with minimal leakage can be achieved. Essentially complete storage is guaranteed in depleted or partially depleted oil and gas reservoirs, which have demonstrated long-term storage capability by the nature of their past storage capacity. Storage in aquifers, deep coal beds, and other formations is likely but yet to be fully demonstrated. Capturing CO2 involves adding a water-gas-shift reactor to the IGCC process to convert the CO in the synthetic gas to CO2 and hydrogen. CO2 then would be separated from hydrogen, compressed, and sent underground via a pipeline for storage (sequestration), while the nearly pure hydrogen stream could enter a combustion turbine for power generation. The hydrogen produced in this process could be utilized for transportation fuel. This approach allows one to leverage a significantly higher upfront capital investment through the co-production of electricity and hydrogen, thereby making
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FIGURE 5.4 FutureGen concept for co-production of power and hydrogen. SOURCE: FutureGen Alliance (http://www.futuregenalliance.org/).
both products more competitive because of shared costs for gasification and gas cleanup and operational flexibility (constant output of the syngas with swings between electric power and hydrogen production). A partnership between the Department of Energy and several industrial companies has been working to develop such a concept, FutureGen (Figure 5.4).1 Success of a FutureGen-type power generation concept would establish a plausible pathway for both clean power generation and hydrogen co-production. The question that electric utilities (or independent power producers) will have to confront is to what extent utilities will be willing to invest in co-production facilities. While utilities may not want to enter the “new” hydrogen market, their reluctance could be lessened by policy actions by their state public utility commissions (PUCs) to provide incentives for them.
Nuclear power offers another alternative to support large-scale hydrogen production to meet high market demand in the long term. Nuclear power is receiving renewed interest since it produces neither harmful air pollutants nor greenhouse gases (although minor amounts of CO2 are emitted in the fuel fabrication process). DOE has an active program to consider the co-production of hydrogen with advanced high-temperature gas-cooled nuclear reactors, but the time line for such development efforts is currently lagging the IGCC-CCS efforts and is unlikely to be ready to serve the hydrogen demand by 2025-2030 when centralized hydrogen production facilities are needed. As a result, it is not considered in this study. However, this does not diminish its potential beyond the 2025-2030 time frame to compete with or complement the IGCC-CCS technology.
Potential for Synergy from Large-scale Stationary Fuel Cells for Stationary Power
As discussed in Chapter 3, PEM is the technology being developed by all major vehicle manufacturers for primary power in their prototype fuel cell vehicles. In addition, PEM fuel cell systems are currently being developed for stationary applications, ranging from very small capacity backup power applications providing less than 1 kW to primary or standalone power applications of several hundred kilowatts. To the best of the committee’s knowledge there are no PEM fuel cells systems currently in high-volume commercial production, although several companies have low rate commercial production and/or extensive field tests under way.
Many anticipated high-volume manufacturing target dates for stationary power have been missed, and potential consumers are now somewhat wary. Furthermore, many developers’ initial product offerings target specialized, high-value, but relatively low-volume, market segments such as remote telecommunications or data center backup. Taken together, these considerations make it unlikely that stationary PEM fuel cell systems will precede vehicle fuel cell systems into
1
DOE announced restructuring of the FutureGen project on January 30, 2008, citing cost escalation and technology advancement over the last 5 years since it was first announced in 2003. Under the restructuring plan, DOE intends to demonstrate the commercial viability of CCS technology at multiple commercial power plant projects that are either under way or in the planning stage. DOE will fund 100 percent of the incremental cost of the CCS portion of the projects if they are included in the plans, and it anticipates spending up to $1.3 billion (in as-spent dollars) between FY 2007 and FY 2020. These demonstrations should achieve the same technical specs as those of the original FutureGen plant with 90 percent CO2 capture according the DOE’s Request for Information document and, therefore, will have the same opportunity for hydrogen co-production.
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the market in large-scale, mass market production by more than a few years, if at all.
Significant synergies between stationary and transportation PEM fuel cells during the time frame covered by this report might be expected in the area of ongoing product development, both in technology improvement and in manufacturing cost reduction. However, product requirements for PEM fuel cells in stationary and light-duty transportation applications are not the same. The DOE (2007) states on its website that the fuel cell stack cost target to be competitive with conventional technology for automotive is $30/kW, whereas cost targets for stationary applications range from $450 to $700 per kilowatt for widespread commercial applications, with up to $1,000/kW for some specific high-value, low-volume applications. The costs are higher because durability requirements for stationary applications are much higher; stationary fuel cells would operate for far more hours per year than those in automobiles. The DOE states that a 5,000-hour lifetime (approximately equivalent to 150,000 miles) will be required for fuel cell technology to be acceptable in automotive applications, while as much as a 40,000-hour lifetime may be required for widespread stationary power applications to be economically viable. Similarly, duty cycles, operational environment requirements, fuels, and other key performance parameters are likely to be quite different for automotive and stationary applications.
Stationary and transportation PEM fuel cells do share some common underlying development needs. The most important of these is reduction of installed costs. Estimates of anticipated costs for both stationary and transportation PEM fuel cell systems in volume production have been carried out by Battelle and the National Renewable Energy Laboratory (Kintner-Meier et al., 2006; NREL, 2005; Stone, 2005). These analyses show that in each system, most of the cost of a fuel cell system comes from the fuel cell stack itself. Thus, although fuel cell stack cost reduction or performance improvement specific to one application may not be directly transferable to the other, it is likely that general benefits would still accrue to both applications. For example, if transportation lifetimes were easily met with more stable long-life membranes developed for stationary applications, the “excess” lifetime capability might be used to benefit the transportation system in some other way, such as reducing materials costs and/or improving performance by using a thinner membrane.
Similarly, manufacturing process development for the PEM stack is likely to benefit both stationary and transportation applications. Some examples (not exhaustive) might include a better understanding of how to mold composite bipolar plates and/or better processes for forming and passivating metal bipolar plates, improved processes for production of membrane electrode assemblies (MEAs; e.g., membrane handling, application of catalyst, etc.), better methods for pre-testing MEAs or cells, and better methods for assembling the stacks themselves.
Beyond such basic stack activities, however, the picture is murkier. The product requirements, and thus the overall system designs, for the two applications are quite different. As a result, it is more difficult to identify significant synergies between stationary and transportation PEM systems either in detailed stack design or at the system level.
Long-term Potential for Synergy from Large-scale Stationary Fuel Cells for Stationary Power
Large (utility)-scale stationary power production currently accounts for about 38 percent (EIA, 2006) of the carbon emissions in the United States. As fuel prices rise and emissions standards are tightened, power equipment manufacturers spend increasingly large sums to achieve small efficiency gains (1 percent or less) and to reduce emissions. Further improvements of such gas-steam turbine combined-cycle systems (now a maximum of about 60 percent efficient) will be even more difficult to attain.
In the future, high-temperature fuel cells offer the possibility of further gains in efficiency and reductions of emissions, especially when operated in a hybrid mode with a turbine bottoming cycle to recover additional energy from the high-temperature exhaust and residual fuel stream exiting the fuel cell. Figure 5.5 shows a conceptual schematic for such a high-temperature hybrid fuel cell system. Theoretical fuel-to-electricity conversion for such systems approaches 70 percent.
Efficiency and emissions benefits in this system result primarily from the direct conversion of approximately two-thirds of the chemical energy in the fuel to electricity in the fuel cell stack, thus avoiding the efficiency limits gas and steam turbine and production of emissions associated with combustion processes. Further reduction of emissions also occurs due simply to the improved efficiency and resulting reduction in fuel consumption. It should be noted that such high-temperature fuel cell systems do not readily provide co-production of hydrogen for other purposes. The high-temperature fuel cell stack is able to use higher-order hydrocarbons (e.g., methane, natural gas) as fuel either directly or with limited external pre-reformation of the fuel. Thus, unlike the situation with low-temperature fuel cells (e.g., PEM), there is no place in the system where a ready source of pure hydrogen is available.
Several companies are pursuing such high-temperature fuel cell hybrid systems. However, significant technical challenges remain for these systems, and in the judgment of this committee it is unlikely that any significant reductions in oil imports or carbon dioxide emissions will result from widespread commercialization of these systems during the time frame studied in this report. Nevertheless, these systems do offer long-term potential for significant reductions in oil imports and CO2 emissions and should form part of a portfolio of development activities that might potentially address these concerns.
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FIGURE 5.5 Schematic of high-temperature fuel cell hybrid system. SOURCE: General Electric Corporation, presentation to the committee.
Competitive Use of the Electric Power System for Electric Vehicles or Plug-in Hybrid Electric Vehicles
The stationary power sector could serve the transportation market in another way by providing electric power to charge batteries. These could then power electric vehicles (EVs) or plug-in hybrid vehicles (PHEVs). In this case, electric power, generally off peak at attractive prices, would be used to recharge batteries, normally at the vehicle’s long-term “parked” location (home of a residential customer, garage for a fleet vehicle, etc.). PHEVs might have a range of about 20-40 miles. When the battery charge is depleted, a regular gasoline engine would start to operate the vehicle. PHEVs are described in Chapter 4.
Either type of electric vehicle would be much easier to implement than HFCVs, especially the PHEV. Little new infrastructure would be needed for the introduction of PHEVs, although new generating capacity and possibly transmission lines would be needed eventually. Infrastructure and logistics are much bigger problems for the introduction of HFCVs. EVs might require the construction of public charging stations to permit long-distance operation. The viability of both EVs and PHEVs depends on significant improvements in battery capability.
Two types of PHEVs are under consideration: the AER (all-electric range) and the “blended” PHEV. The AER has a large electric motor that provides all the traction power and a large battery to allow considerable all-electric vehicle operation. It also has a small engine that acts as a range extender when the battery is depleted. The blended PHEV has a larger engine and a smaller electric motor which operate in parallel to drive the wheels. The blended configuration is similar to current hybrids but with a larger battery to allow some operation on just electric power though less than the AER.
The use of off-peak power is particularly attractive. If off-peak power is available for $0.07/kWh, it is equivalent to gasoline at $0.77 per gallon after taking into account the differences in efficiency (Pratt et al., 2007).2 As this example demonstrates, time-of-day pricing would have to be available to make off-peak power economical. This is an excellent example of how an electric utility, with the approval of its state PUC, could help make electric vehicles financially attractive. Similar incentives could be put in place for any plug-in or hydrogen-based concept.
The near-term focus should be on the blended version since the AER approach essentially has the same problems as full electric vehicles—namely, the need for a large, advanced battery and the need for rapid growth of charging stations. In a blended PHEV, the advanced batteries will be closer in size to those found in today’s hybrid vehicles. With currently envisioned technologies, it would take an AER PHEV up to 6.5 hours to recharge (at 110 V) for a 40-mile battery range, whereas a blended PHEV would require only 2 hours (at 110 V) for a 5-mile battery range (Kawai, 2007).3 It should be emphasized that the critical path developmental item for PHEVs is the advanced battery (e.g., lithium ion) that either the AER or the blended version will require.
The stationary power sector itself could supply the needs of about 40 percent of the current light-duty fleet for an average 30+ miles/day using off-peak power from current power
2
It should be noted that gasoline prices include federal and state gasoline taxes, which are used to build and maintain roads.
3
At 220 V, the charging times would be much shorter.
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FIGURE 5.6 Fueling capacity for plug-in hybrid electric vehicles (PHEVs) in the U.S. power sector. SOURCE: Kintner-Meier et al. (2006).
plants if PHEVs and EVs were available, equivalent to what it could do for HFCVs via electrolysis. The Pacific Northwest National Laboratory (Kintner-Meier et al., 2006) found that if all light-duty vehicles were plug-in hybrids, 70 percent or more of them could be charged if 24-hour per day charging were carried out utilizing otherwise reserve power generation capability. This relationship is shown in Figure 5.6.
In the scenarios presented in Chapter 6, the continued introduction of hybrid electric vehicles (some of which could be PHEVs) has been considered as an alternative to the introduction of hydrogen vehicles and the contrasts in infrastructure requirements are factored in. The most important factors are the time horizons under consideration (both 2020 and 2035) since the rollout of stationary hydrogen production (electrolysis and co-production) and stationary applications for fuel cells require time for technology development, permitting or regulatory approvals, and development of an infrastructure to support any such effort.
The EV and PHEV alternatives have a more limited, but also challenging, technological requirement, namely, the development of a high capacity battery to make this option viable. However, the permitting or regulatory approvals and infrastructure needs are much smaller, especially for the early, transitional period. This is shown in Figure 5.6 as well as in the qualitative estimate from Toyota (Figure 5.7).
INCENTIVES FOR THE ELECTRIC POWER SECTOR
The regulatory regime for electricity is well known and evolving. That regime can be extended to the hydrogen production (and plug-in hybrid) market without major changes except, possibly, for an incentive tariff.
One question, then, is what regulatory mechanisms might be put into place to provide utilities with incentives to produce hydrogen at either distributed or central locations. It is clear that additional revenues from hydrogen business and carbon emission credits would be reasonable incentives to
FIGURE 5.7 Advanced vehicle market penetration. SOURCE: Kawai (2007).
make utilities consider branching out into hydrogen production, but would they be sufficient?
Let us start with the expected availability of the stationary electric power system to provide the power either for electrolysis (or PHEV charging) as well as the expected capacity for co-production of hydrogen and electricity by the new-generation options explained above.
In the stationary electric power sector, a variety of mechanisms have been used to encourage the introduction of new technologies or new approaches to doing business. These range from such federal approaches as production tax credits and carbon credits to state mechanisms such as rate structures and portfolio standards. The early introduction of such mechanisms would expedite action on the part of utilities to become players in this field sooner rather than later. This should be seriously considered, since utilities can be major players in the rollout of the systems described here.
The synergies for the use of stationary power for either hydrogen production and/or plug-in hybrids are quite significant. Improved asset utilization (increased capacity factors using electrolysis at distributed locations, i.e., substations and/or charging batteries) could (1) help increase generation capacity factors, (2) shave peak loads, (3) reduce wear and tear on cycling generation, and (4) provide hydrogen to transportation refueling stations or plug-in locations.
In the longer term, the co-production of electricity and hydrogen could leverage investments that would otherwise be required anyway, for electric power production. The coproduction of hydrogen and electricity using IGCC technology with carbon capture and storage (as in the FutureGen concept) represents a potentially significant opportunity. Such an approach would leverage the capital investment since the fossil fuel, in this case coal, would be required to go through the gasification process, producing hydrogen that can be combusted to create electricity as well as producing hydrogen for transportation use. Through this process, carbon would be captured and sequestered.
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CONCLUSIONS
CONCLUSION: With appropriate policies or market conditions in place, potential synergies between the transportation sector and the electric power sector could accelerate the potential for reduced oil use and decreased CO2 emissions as benefits from the use of hydrogen in both sectors. In the near term, electrolysis of water at refueling sites using off-peak power, and in the longer term (after 2025), cogeneration of low-carbon hydrogen and electricity in gasification-based energy plants, are potential options that offer additional synergies. See Chapter 5.
More specifically, in response to the three framing questions posed at the beginning of this chapter, the committee reached the following conclusions:
In the near term (until 2020), existing electric power facilities (generation, transmission, substations, etc.) could produce hydrogen for transportation fuel purposes. In particular, small-scale electrolyzer plants, when successfully developed to meet more competitive cost and performance standards, at or near the points of distribution, could be important during the transition when the cost burdens of larger-scale reformation plants would be a potential barrier.
In the longer term (2035), the successful demonstration of one or more technologies could result in the widespread deployment of “co-production plants.” One benefit from this approach would be the reduction in the use of natural gas that will increasingly have to be imported and is a source of greenhouse gases.
Incentives are likely to be necessary for full involvement of electric power companies. Mechanisms such as production tax credits, rate adjustments, carbon credits, and so forth, would be options for near-term action.
PEM fuel cell systems, whether for transportation or stationary systems, still require significant cost, reliability, and lifetime improvements to be truly competitive in the market. In many basic technology and product development issues, and basic manufacturing process development for the PEM stack, synergies between stationary electric power and transportation fuel cells might be realized.
The introduction of high-temperature fuel cells (solid oxide fuel cells or molten carbonate fuel cells) does not enhance the production of hydrogen since one advantage of these technologies is their ability to use a variety of feedstocks with an internal reformer.
Plug-in hybrid vehicles could help reduce reliance on imported oil (and natural gas). The reductions in overall CO2 production will be a function of the reliance on fossil fuels for electricity production and the success of CCS technologies. The introduction of PHEVs depends on the timely introduction of advanced batteries.
The power industry could be of further assistance by providing a special electricity rate structure to support the early implementation of electrolysis. This is particularly important during the hydrogen market transition period. (See Chapter 3 for detailed discussions of the impact of the cost of electricity on the hydrogen production cost.) Utilities, working with their regulatory commissions could provide economic incentives to hydrogen producers to lessen the cost burden of the electrolysis process.
REFERENCES
Bereisa, J. 2007. Energy Diversity: The Time Is Now. Presentation to the committee, June 25.
DOE (Department of Energy). 2007. Fuel Cell Technology Challenges. Available at http://www1.eere.energy.gov/hydrogenandfuelcells/fuelcells/printable_versions/fc_challenges.html.
EIA (Energy Information Administration). 2006. Emissions of Greenhouse Gases. Available at http://tonto.eia.doe.gov/FTPROOT/environment/057306.pdf.
EIA. 2007. Annual Energy Review. Available at http://www.eia.doe.gov/emeu/aer/contents.html.
EPRI (Electric Power Research Institute). 2007. Electrolyzer Competitive Benchmarking: Pathways to Electrolysis-Powered Hydrogen Fueling Stations. Palo Alto, Calif.: 1014877.
Kawai, T. 2007. Sustainable Mobility and the Development of Advanced Technology Vehicles. Presentation to the committee, June 26.
Kintner-Meyer, M., K. Schneider, and R. Pratt. 2006. Impacts Assessment of Plug-in Hybrid Vehicles on Electric Utilities and Regional U.S. Power Grids. Part 1: Technical Analysis. Richland, Wash: Pacific Northwest National Laboratory. Available at http://www.pnl.gov/energy/eed/etd/pdfs/phev_feasibility_analysis_combined.pdf. Accessed September 2008.
NREL (National Renewable Energy Laboratory). 2005. Cost Analysis of PEM Fuel Cell Systems for Transportation. NREL Subcontract Report NREL/SR-560-39104. December.
Pratt, R., M. Kintner-Meyer, K. Schneider, M. Scott, D. Elliott, and M. Warwick. 2007. Potential Impacts of High Penetration of Plug-in Hybrid Vehicles on the U.S. Power Grid. Richland, Wash.: Pacific Northwest National Laboratory. Available at http://www1.eere.energy.gov/vehiclesandfuels/avta/pdfs/phev/pratt_phev_workshop.pdf. Accessed June 2008.
Srivastava, R., N. Hutson, and F. Princiotta. 2005. Reduction of Mercury from Coal-fired Electric Utility Boilers. Presentation at the DOE/NETL Mercury Control Technology R&D Program Review, Pittsburgh, Pa., July 12, 2005.
Stone, H.J. 2005. Economic Analysis of Stationary PEM Fuel Cell Systems. Battelle Memorial Institute, Project ID # FC 48.