4

Hydrogen, Alternative Fuels, and Electricity

The U.S. DRIVE Partnership is focused on reducing petroleum consumption and greenhouse gas (GHG) emissions by employing three power systems: hydrogen fuel cell vehicles (HFCVs), advanced combustion engines, and plug-in hybrid electric vehicles (PHEVs) and battery electric vehicles (BEVs) using electricity. Hydrogen is an energy carrier produced from a variety of energy sources, but at present it is mostly produced from natural gas. Biofuels, energy carriers for solar energy and thus renewable fuels, are produced from a variety of biological sources, including plant materials and algae. Electricity is an energy carrier that is generated from a variety of sources today, but in the United States mostly from coal and natural gas. This chapter reviews the programs relating to hydrogen that are under the U.S. DRIVE Partnership effort. (Budget information was provided by U.S. DRIVE and the U.S. Department of Energy [DOE] in response to questions from the committee.) The chapter also includes an overview of issues relating to the Partnership’s role in biofuels, natural gas, and electricity for PHEVs and BEVs.

FUEL PATHWAYS

Strategic Input Needed from Executive Steering Group

One of the challenges of the U.S. DRIVE Partnership is to have critical fuels and vehicle technologies both commercially ready so that the required fuels can be in place when vehicles with advanced technologies become available in the marketplace. The Partnership is focused on having advanced vehicle technologies with cost and performance comparable to those of conventional technologies by 2020, and so critical fuel technologies will also need to meet that time line.



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4 Hydrogen, Alternative Fuels, and Electricity The U.S. DRIVE Partnership is focused on reducing petroleum consumption and greenhouse gas (GHG) emissions by employing three power systems: hydro- gen fuel cell vehicles (HFCVs), advanced combustion engines, and plug-in hybrid electric vehicles (PHEVs) and battery electric vehicles (BEVs) using electricity. Hydrogen is an energy carrier produced from a variety of energy sources, but at present it is mostly produced from natural gas. Biofuels, energy carriers for solar energy and thus renewable fuels, are produced from a variety of biological sources, including plant materials and algae. Electricity is an energy carrier that is gener- ated from a variety of sources today, but in the United States mostly from coal and natural gas. This chapter reviews the programs relating to hydrogen that are under the U.S. DRIVE Partnership effort. (Budget information was provided by U.S. DRIVE and the U.S. Department of Energy [DOE] in response to questions from the committee.) The chapter also includes an overview of issues relating to the Partnership’s role in biofuels, natural gas, and electricity for PHEVs and BEVs. FUEL PATHWAYS Strategic Input Needed from Executive Steering Group One of the challenges of the U.S. DRIVE Partnership is to have critical fuels and vehicle technologies both commercially ready so that the required fuels can be in place when vehicles with advanced technologies become available in the marketplace. The Partnership is focused on having advanced vehicle technologies with cost and performance comparable to those of conventional technologies by 2020, and so critical fuel technologies will also need to meet that time line. 112

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 113 The level of DOE funding in FY 2012 for the hydrogen production portion of the U.S. DRIVE Partnership will be 8.6 percent lower than the FY 2011 level, which was significantly reduced from FY 2009. Pressures to reduce expenditures are likely to have important impacts on program areas outside of U.S. DRIVE that provide important technology input. The Partnership is dependent on DOE’s Office of Fossil Energy (FE) and Office of Basic Energy Sciences (BES), as well as the Biomass Program in the Office of Energy Efficiency and Renewable Energy (EERE), for technologies relating to hydrogen generation, biofuels, and electric- ity, all of which affect the U.S. DRIVE Partnership strategically. The Fuel Cell Technologies Program (FCTP) has done an admirable job of coping with these changes and the uncertainty, and it has provided coordination links with programs in other parts of DOE. However, managing the various pro- grams under U.S. DRIVE to ensure that the required fuel technologies will be available as new vehicle technologies emerge remains a challenge, and there is a compelling need to maximize the impact of funds spent toward completing criti- cal fuels and vehicle programs at the same time. The Partnership has diligently involved its various technical teams to gain “user” input, but these teams have not provided overall guidance across all fuel categories. Given the changes that have taken place, the continuing environment of uncertainty, and the approaching dates for planned commercial readiness, the committee believes that U.S. DRIVE should seek strategic “user” input from its Executive Steering Group (ESG) on the program direction, focus, and timing to ensure that critical fuel technologies are available when needed. Recommendation 4-1. The DOE should seek the strategic input of the Execu- tive Steering Group (ESG) of U.S. DRIVE. The ESG could provide advice on all DOE fuel programs potentially critical to providing the fuel technologies needed in order for advanced vehicle technologies to achieve reductions in U.S. petro- leum dependence and greenhouse gas emissions, and DOE should subsequently make appropriate program revisions to address user needs to the extent possible. Hydrogen Fuel Pathways In the United States today, hydrogen is a major industrial gas with an annual production and consumption, mostly from centralized natural gas reforming plants, of approximately 20 million metric tons (20 billion kg) (NHA, 2010).1 A study of the transition to alternative transportation technologies (NRC, 2008, pp. 31-35) concluded that 2 million fuel-cell-powered vehicles would be the maxi- mum practical number in 2020. Two million vehicles would increase hydrogen 1 The figure of approximately 20 million metric tons reported by the National Hydrogen Associa- tion (NHA, now called the Fuel Cell and Hydrogen Energy Association) includes hydrogen produced from merchant plants.

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114 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP demand by about 2 percent2 based on today’s production, an increase that could be readily met in centralized plants by utilizing existing excess capacity or by building additional capacity. Thus, the issues during transition do not concern having enough hydrogen available overall but rather, having it available where needed at an acceptable cost and overall efficiency. Three principal pathways appear feasible to meet the need: (1) transmission and distribution from centralized plants of gaseous hydrogen by tube trailer, (2) distribution of liquefied hydrogen by tanker, and (3) on-site generation of hydrogen at the fueling site using natural gas reforming or electrolysis of water. Hydrogen demand for transportation would thus be satisfied by combinations of centralized and on-site hydrogen production. The “lighthouse scenario” is likely to play an important part initially in sup- plying needed hydrogen. In this scenario, widespread use of hydrogen fuel is encouraged in high-density cities and regions to achieve high market penetration in those areas and thus, it is hoped, a reduction in the cost of the fuel. These light- house areas would serve as a starting point for the development of a nationwide network. Such a system has already been proposed for Germany, and Honda is working in California on a similar approach.3 In addition, the California Fuel Cell Partnership, with support from the University of California, Davis, has been actively pursuing this approach.4 Needless to say, regulation could also play an important part in providing early hydrogen stations. A regulation being considered in California would require oil refiners to provide hydrogen stations on a schedule that meets the automotive original equipment manufacturers’ (OEMs’) projected introduction of hydrogen vehicles once the number reaches 10,000 (CARB, 2011). Considerable work remains to be done to identify pathway scenarios that fill the needs of specific market segments in the United States while minimizing cost and maximizing efficiency. The hydrogen fuel/vehicle pathway integration effort is charged with look- ing across the full hydrogen supply chain from well (source) to tank for fuel cell vehicles and has been expanded to include the vehicle components, or life-cycle 2 This assumes that 5.6 kg of H per tank yields a 400-mile range. If each hydrogen fuel cell vehicle 2 travels 15,000 miles per year, then each vehicle would consume 210 kg per year. A fleet of 2 million would then consume 420 million kg of H2 per year. 3 Sasha Simon, Mercedes-Benz, “The Mercedes-Benz Hydrogen Roadmap,” presentation to the NRC Committee on the Potential for Light-Duty Vehicle Technologies, 2010-2050: Costs, Barriers, Impacts and Timing, March 22, 2011, Washington, D.C.; R. Bienenfeld, Honda Motor Company, “Honda’s Environmental Technologies Overview,” presentation to the committee, June 5, 2012, Washington, D.C. 4 “Incentivizing Hydrogen Infrastructural Investment. Phase 1: An Analysis of Cash Flow Support to Incentivize Early Stage Hydrogen Investment,” June 2012, prepared by Energy Independence Now in conjunction with the California Fuel Cell Partnership Roadmap, available at http://www.einow. org/resources/reports.html, and “A California Road Map: Bringing Hydrogen Fuel Cell Vehicles to the Golden State,” California Fuel Cell Partnership, July 2012, available at http://cafcp.org/sites/ files/20120720_Roadmapv(Overview)_0.pdf.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 115 analysis. The goal of this effort is to support the U.S. DRIVE Partnership in the identification and evaluation of implementation scenarios for fuel cell technology pathways in the transportation sector, both during the transition period and in the long term, by (1) analyzing issues associated with complete hydrogen produc- tion, distribution, and dispensing pathways; (2) commenting to the Partnership on methodologies for setting targets for integrated pathways and pathway com- ponents; (3) providing observations to the Partnership on needs and gaps in the hydrogen analysis program; and (4) enhancing the communication of analysis parameters and results so as to improve consistency and transparency in all analy- sis activities. All of this work is considered by the committee to be important and an appropriate use of federal funds. This effort is overseen by the fuel pathway integration technical team (FPITT), with representation from DOE, four energy companies, and the National Renew- able Energy Laboratory (NREL). The expertise of this group supports analysis efforts of the Partnership on fuel cell technology pathways, coordinating fuel activities with the vehicle systems analysis effort, recommending additional pathway analyses, providing input from industry on practical considerations, and acting as an honest broker for the information generated by other technical teams. The Partnership continues to make significant and important progress toward understanding and preparing for a transition to hydrogen fuel. During the past 2 years, a methodology for documenting and reporting assumptions and data for well-to-wheels analysis has been developed and is available.5 In addition, a methodology was developed for analyzing the optimal placement of central (large) hydrogen production facilities, and there was an evaluation of other industrial options and synergies for the use and supply of hydrogen, such as the coproduc- tion of hydrogen from stationary fuel cells. With guidance from a recently developed prioritized list of gaps and barriers, current efforts include an analysis of hydrogen fueling station costs during the early phase of hydrogen deployment and an update of the well-to-wheels analy- sis. In order to provide additional guidance to the program, a study is underway to identify specific issues that could threaten achievement of a commercially sustainable system. The Phase 3 NRC report on the FreedomCAR and Fuel Partnership (NRC, 2010) recommended that DOE broaden the role of FPITT to include an inves- tigation of hydrogen, biofuels utilization in advanced combustion engines, and electricity generation requirements for PHEVs and BEVs. Subsequently, the Partnership elected to maintain FPITT’s focus on hydrogen. Although the cur- rent committee recognizes that DOE maintains communications and coordina- tion among the various fuels-related programs within DOE, the mechanism for balancing program priorities and identifying gaps among different fuel options to 5 See the NREL publication Hydrogen Pathways, Cost, Well-to-Wheels Energy Use, and Emis- sions for the Current Technology Status of Seven Hydrogen Production, Delivery and Distribution Scenarios, available at http://nrel.gov/docs/fy10osti/46612.pdf.

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116 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP increase energy security and reduce GHG emissions is not apparent, as discussed above in the section “Strategic Input Needed from Executive Steering Group.” Recommendation 4-2. The fuels pathways integration effort provides strategi- cally important input across different hydrogen pathways and different technical teams to guide U.S. DRIVE Partnership decision making. In this time of budget restraints, the program of the fuel pathway integration technical team should be adequately supported in order to continue providing this important strategic input. HYDROGEN PRODUCTION The hydrogen production program includes hydrogen generation from a wide range of primary energy sources, including natural gas, coal, biomass, solar, and wind. Thermal, electrolytic, photolytic, biological, and photoelectrochemical (PEC) processes are being investigated to convert these primary energy sources to hydrogen for use in fuel-cell-powered vehicles. The hydrogen production technical team (HPTT) helps guide this program toward commercially viable technologies through nonproprietary dialogue. This team includes representatives from DOE, four energy companies, and the Pacific Northwest National Labora- tory (PNNL). In addition, SunCatalytix has recently been added as an associate member. As noted in Chapter 1, a number of important programs related to the U.S. DRIVE Partnership are carried out in other parts of DOE. Work on biomass and algae production as well as work on using solar heat and wind to produce hydrogen are not part of the Partnership. The Office of Fossil Energy supports the development of technologies to produce hydrogen from coal and related carbon- sequestration technologies, and the Office of Basic Energy Sciences supports fundamental work on new materials for hydrogen storage, catalysts, and biologi- cal or molecular processes for hydrogen production, as well as work potentially affecting other areas of U.S. DRIVE.6 The Partnership has coordination links to each of these programs. Past programs of the Office of Nuclear Energy have included an investigation of high-temperature nuclear reactors for hydrogen pro- duction, but no funds are included for this approach currently. 7 The hydrogen production program includes short-term and long-term approaches. In the short term, when a hydrogen pipeline system is not in place, hydrogen would be supplied from centralized plants using on-road trailers similar to (but larger than) those in commercial use today, or by small-scale genera- tion at fueling stations using natural gas reforming or electrolysis of water. As the fleet of fuel-cell-powered cars and hydrogen demand increase, centralized 6 BES also manages the Energy Innovation Hub called the Joint Center for Artificial Photosynthesis, which is allocated $122 million over 5 years to make hydrogen from sunlight and water. 7 C. Sink, Department of Energy, “High Temperature Nuclear Reactors for Hydrogen Production,” presentation to the committee, June 4, 2012, Washington, D.C.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 117 hydrogen generation plants with pipeline distribution would become increas- ingly attractive and would be expected to satisfy an increasing fraction of the total need with time. The program includes pathways with which considerable commercial experi- ence exists, as well as longer-term pathways, and is reviewed below. Pathways with Commercial Experience As already noted, the consumption of hydrogen in the United States is high- est among industrial gases, and so there is extensive commercial experience in its production. DOE programs in coal gasification, biomass gasification, low- temperature electrolysis, and steam reforming of bio-derived liquid fuels benefit from this experience while seeking to achieve significant improvements in cost and performance. A section on natural gas reforming, the commercial process most used today in centralized plants, is not included among the sections that follow for several reasons. The Partnership, through DOE studies, has already shown the feasibility of building small reformers for distributed generation at fueling sites and meeting the cost target, and opportunities to improve large-scale reforming are considered marginal. DOE now projects that reformers at fueling stations could produce hydrogen for $4 per gallon gasoline equivalent (gge) or less and thus reach the target range of $2 to $4/gge.8 Details regarding investment and operating costs are available online.9 The committee agrees with DOE that at this point other parts of the program are more appropriate for U.S. DRIVE than continuing cost-reduction efforts on this approach. Hydrogen Production from Coal and Biomass The production of hydrogen from coal and/or biomass will likely utilize a relatively mature technology, most appropriate for the later stages of a hydrogen transition (NRC, 2008). Reasonable estimates of the timing of these later-stage requirements suggest that hydrogen production from new large-scale coal and/ or biomass facilities will not be needed before 2020. Prior to that time, central production of hydrogen appears manageable from natural gas feedstocks, which currently may offer environmental and cost advantages over coal and biomass. Status of the Department of Energy Coal and Biomass Programs Commercial large-scale gasification plants using coal, petroleum coke, or heavy oils have been in place for many years, and a large body of experience has 8 T.Rufael, Chevron, and S. Dillich, Department of Energy, “Hydrogen Production Technical Team (HPTT),” presentation to the committee, January 26, 2012, Washington, D.C. 9 See http://www.hydrogen.energy.gov/h2a_production.html.

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118 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP accumulated concerning their cost and operation. Using biomass as a feedstock adds different physical and chemical properties to the fuel mix (see below), but does not fundamentally alter the relevance of this deep base of commercial gas- ifier experience. The DOE program plan for coal speaks of “transitioning from hydrogen production for transportation applications to electric power applications,” but the technology remains relevant for central station hydrogen, either exclusively for transportation or (more likely) for the coproduction of electricity and vehicular hydrogen, and various approaches to purification of product hydrogen are being investigated. The goals of the program are “to support the goals of FE’s Office of Clean Coal in development and demonstration of advanced, near-zero emission coal-based power plants” (DOE, 2010a, p. iii). The thermochemical conversion of biomass to a syngas is supported by NREL.10 Three aspects of the programs involving coal and biomass to hydrogen reach beyond the commercial experience base with gasifiers: • The capture and sequestration of the carbon dioxide (CO2) produced in the process; • The integrating of operations downstream of the gasifier, especially the production of electricity and fuels; and • A significant lowering of the capital cost. Whatever budget resources are devoted to research and development (R&D) in high-priority process components, these resources are likely to be quite inadequate for demonstrating a near-scale facility and working out the systems integration issues that inevitably arise. Environmental Issues Concern for global climate change is much greater with coal than with biomass. The DOE hydrogen-from-coal activity has held the proving of the feasibility of a near-zero emissions plant as a key program goal. Achieving wide-scale deployment, however, will depend on the pace and accomplishment of the DOE’s carbon sequestration programs. Until the commercial availability and societal acceptance of full-scale carbon sequestration can be assured, there seems to be little point in demonstrating a hydrogen-from-coal plant. Unless the carbon emissions can be addressed in a satisfactory way, commercial production seems unlikely to go forward regardless of the other merits of the technology. In contrast, hydrogen from biomass could be partially carbon neutral but might raise other environmental concerns around land use. 10 See http://www.nrel.gov/biomass/proj_thermochemical_conversion.html.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 119 Feedstock Issues In contrast with coal, a biomass production plant faces cost issues inherent in its feedstock. Whereas the coal feedstock is relatively cheap and abundant, the biomass feedstock raises a number of cost-related issues. First, the availability of feedstock limits the scale and location of biomass production plants. As a result, these are likely to face larger capital cost and transportation challenges. Second, the seasonal variability of biomass, both in its quantity and in its physical and chemical properties, will pose operating challenges. And third, storage, handling, and preparation of the feedstock to the specifications of individual gasifiers will add to cost. In addition, the type of biomass employed—for example, cellulosics, lignins, and so on—and variability of that feed will affect the gasification process. Conclusions Regarding Hydrogen Production from Coal and Biomass The chief issues for both the coal and biomass feedstocks center around capital cost, an observation made in the NRC (2008, p. 37) report. As that report noted: “Although coal gasification is a commercially available technology, to reach the future cost estimates . . . further development is needed. Standardization of plant design, gas cooler designs, process integration, oxygen plant optimiza- tion, and acid gas removal technol­ gy show potential for lowering costs. Other o 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.” Yet as long as natural gas remains as abundant, secure, and inexpensive as the current Energy Information Administration (EIA, 2012) projections indicate, a hydrogen transition appears supportable at least through 2020, and quite possibly beyond. Thus the hydrogen from coal and biomass efforts should remain focused on fundamental R&D, as noted above, and on scientific fields that might offer value in programs beyond hydrogen production, such as separation membranes, for example. Recommendation 4-3. While a hydrogen-from-coal demonstration plant could address many of the downstream integration issues and thus provide more cer- tainty around the probable capital costs, the committee recommends that any hydrogen-from-coal demonstration should be paced (1) to match the pace and progress of commercial-scale carbon sequestration and (2) to support a mature hydrogen fuel cell vehicle fleet in the event that natural gas becomes too costly or unavailable. Regarding item 1 in Recommendation 4-3, the committee notes that progress in commercial-scale carbon sequestration remains highly uncertain. As a recent interagency report notes, “The lack of comprehensive climate change legislation

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120 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP is the key barrier to CCS [carbon capture and sequestration] deployment. Without a carbon price and appropriate financial incentives for new technologies, there is no stable framework for investment in low-carbon technologies such as CCS” (DOE, 2010b, p. 10). Until this fundamental policy issue is resolved and the CCS process is demonstrated to be effective and safe for long-term storage of CO2, private investment in unsubsidized coal-to-hydrogen plants is likely to pose commercially unacceptable risks. Regarding item 2 in Recommendation 4-3, the opening stages of a transition to the HFCV appear supportable from natural gas feedstocks. For these reasons, continuing DOE’s basic R&D while deferring any demonstration of hydrogen from coal until conditions warrant seems appropriate. Low-Temperature Water Electrolysis The low-temperature (below 100°C) electrolysis of water is a mature hydrogen generation technology that has been used in military and industrial applications for decades. Electrolysis is an attractive solution to on-site hydrogen demand, as electrolyzers can be sited in nearly any location and can be scaled to meet volume requirements. Furthermore, the two primary electrolyzer technologies, alkaline and proton exchange membrane, can generate hydrogen without carbon emissions if powered by a renewable energy source. Although the membrane process has received the most attention in recent years, the alkaline process is the most com- monly utilized, especially in large-scale industrial applications. The attractiveness and potential benefit to the fuel cell community stem from the fact that high-purity hydrogen can be generated by a relatively simple process and sited in geographical locations where other hydrogen generation processes are not feasible. Additionally, with respect to vehicle refueling, the hydrogen can be generated at high pressures, thereby eliminating the need for mechanical compressors. Due to the nature of the electrolysis process, the technology can be used in small or large operations, making it ideal for lower-volume opportunities, includ- ing distributed, point-of-use applications such as home refueling or large-scale centralized production. Additional attractive aspects of the current electrolysis processes are durability and lifetime, as decades of operation without significant performance degradation and losses have been the norm. The electrochemical efficiency of the electrolysis process itself is approximately 80 percent (higher heating value [HHV]); when the entire system (balance of plant) is taken into account, efficiencies in the high 50s or low 60s can be achieved (excluding the power source efficiency contribution) (NREL, 2004, 2009, 2012). Primary Disadvantage: Cost. The primary disadvantage of water electrolysis is cost, both operating expenditure (OPEX) and capital expenditure (CAPEX). The energy requirement to split the water alone is significant (more than 50 kWh/kg), as are the capital costs related to the hardware—for example, stack components and the balance of plant. It should be noted that the balance between OPEX

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 121 TABLE 4-1 Draft Targets (2015, 2020, and Ultimate) and Current Status for Hydrogen Production Using Water Electrolysis ($/kg H2) (Excluding Cost of Hydrogen Delivery) Method of Generation Current Status 2015 Target 2020 Target Ultimate Target Distributed $4.00 $3.70 $2.20 $1.00-$2.00 Central $4.60 $3.10 $2.00 $1.00-$2.00 NOTE: During the committee’s review, U.S. DRIVE representatives noted that the targets were under review for possible revision. SOURCE: T. Rufael, Chevron, and S. Dillich, Department of Energy, “Hydrogen Production Techni- cal Team (HPTT),” presentation to the committee, January 26, 2012, Washington, D.C. and CAPEX is volume-dependent, as the smaller, lower-volume units are more capital-intensive, whereas the higher-volume units are more expensive to operate on a per kilogram of hydrogen basis. The current cost of producing hydrogen by the electrolysis process, central or distributed, is still significantly above the 2020 DOE targets of $2.20/kg H2 and $2.00/kg H2, respectively (see Table 4-1).11 Although the annual budget for hydrogen production (all technologies) has been reduced over the past 3 years, from approximately $28 million (FY 2008) to approximately $11 million (FY 2011), the DOE appropriately continues to support the longer-term initiatives that ultimately could reduce electrolysis stack hardware costs, advanced membranes, and new catalysts. Generating electrolytic hydrogen without emissions is possible with a number of renewable energy sources—wind, solar, and hydroelectric power, to name a few. In order to better understand this approach, in recent years DOE has funded studies through NREL to assess hydrogen generation costs by means of a renew- able wind energy electrolysis process (NREL, 2008a, 2008b). Conclusions from the cost-benefit configuration studies indicate that plant size (volume), utilization, and energy availability (wind source and strength) are critical factors in achiev- ing the cost targets. The studies further show that under a number of conditions and assumptions, $3.00/kg H2 (gge) production costs could be achieved. The significant disadvantage of the wind electrolyzer approach is that the system must still be grid-connected for off-wind periods. The reports further highlight the impact on cost of the system architecture and engineering, including controls and software, water conditioning, the power electronics, and gas cleanup and drying. These assessments provide valuable insight into how hydrogen production rates and system utilization can impact cost, thereby providing direction to DOE about where funding would be best allocated. As noted above, a number of sources indicate that electrolysis may be a viable hydrogen production pathway if costs and greenhouse gas emissions from electric 11 Note that the energy value of a kilogram of H is approximately the same as a gallon of gasoline 2 equivalent (gge); thus, these targets can also be expressed as $/gge.

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122 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP power generation can be reduced. The DOE’s response has been appropriate, proactively supporting long-term projects focused on next-generation technical solutions. As reported at the DOE Annual Merit Review meetings (2010, 2011, 2012), progress has been made in recent years. According to one effort, focusing on hardware elements has yielded significant cost-reduction advancements (see Figure 4-1). New cell materials, architecture, and ultimately advanced manufac- turing methods will impact the capital on a kilogram-of-generated-hydrogen basis. Performance characteristics of the electrochemical process are predominately tied to membranes, electrodes, and catalysts, topics also currently supported. The membrane R&D is appropriately focusing on conductivity improvements and alternative polymers, while the primary electrode development effort is evaluat- ing thin-film nanocatalyst materials (3M), similar to those developed for the fuel cell industry. Regardless of the source of hydrogen, it is clear that for there to be the pos- sibility of widespread HFCVs, there must be the availability of hydrogen for refueling. One possibility being pursued is that of using on-site electrolysis of water to locally produce hydrogen using wind power, which would both avoid GHGs produced (by the power plants) and reduce energy lost in the process of energy conversion at the power plant and transmission and distribution. Appropriateness of DOE Funding. The operating and capital costs of electro- lyzers as presented in Table 4-1 and Figure 4-1 must be reduced if they are to become a viable option and the hydrogen cost targets of $2 to $4/kg H2 are to be met. Research and development activities on the stack as well as on the bal- ance of plant (predominately the power electronics) need to continue, as does integration with the energy sources. As the cost issue is related to the technology, the currently funded research topics previously discussed in the DOE portfolio of long-term projects continue to be needed. It seems appropriate that the DOE Component Cost >60% Reduction 2007 2011 FIGURE 4-1  Cost-reduction progress between 2007 and 2011 in membrane electrolysis stacks. SOURCE: Hamdan (2011).

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 133 overall infrastructure, the initial investment cost per CNG vehicle could be lower than that for electric vehicles, HFCVs, and biofuel vehicles (NRC, 2013). With the existing very large natural gas pipeline system, a large part of the country could be supplied with CNG. Although an attractive opportunity exists based on the current and midterm supply of natural gas, cost, and GHG emissions compared with those related to gasoline, the very long term role in the entire LDV fleet for the CNG vehicle is not clear. The lower GHG emissions compared with those from gasoline are beneficial but are not large enough to reach the 2050 goal of 80 percent reduction from 2005 levels without significant increases in ICE vehicle efficiency and/or reduction in vehicle miles traveled. Questions exist and are being investigated about the amount of GHGs (CO2 and methane) actually released during natural gas production. In addition, there are other general public concerns with water contamination and some production methods (hydraulic fracturing or “fracking”). As a commodity, natural gas is subject to price variations based on supply and demand, and there is no assurance of its long-term cost advantage compared with petroleum-derived gasoline. CNG Light-Duty Vehicle and Infrastructure R&D Needs Several areas could benefit from further technology development primarily to lower costs for both the LDV and the fuel infrastructure. They include the following: 1. The CNG storage tank in the LDV is bulky, high-pressure (about 25 MPa, or 3,600 psi), and expensive. Improvements in volumetric and gravimetric densities are needed to be comparable in many character- istics to liquid fuel tanks. The high-pressure operation makes the tanks expensive and also increases the cost of refueling at the high pressure. 2. CNG refueling stations are commercially available today, but the high- pressure operation results in high costs. Home refueling could be benefi- cial in some markets, as many homes have natural gas. Home refueling equipment is expensive primarily because of the high-pressure operation. Although natural gas and the CNG LDV are not part of the U.S. DRIVE effort, these R&D areas are being addressed by DOE through its Advanced Research Projects Agency-Energy (ARPA-E). The ARPA-E Methane Opportuni- ties for Vehicular Energy (MOVE) program is a new effort to address both of the above issues. The ARPA-E has plans to fund projects at about $30 million over a 3-year period to help resolve these issues. Success in these areas is not guaranteed, but if it occurs, success in these areas combined with continued growth in natural gas reserves and production could make a compelling case for rapid growth in the CNG vehicle fleet.

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134 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP Recommendation 4-7. U.S. DRIVE should include the CNG vehicle and pos- sible improvements to its analysis efforts in order to make consistent comparisons across different pathways and to help determine whether CNG vehicles should be part of its ongoing vehicle program. ELECTRICITY AS AN ENERGY SOURCE FOR VEHICLES The amount of electricity required for individual plug-in vehicle16 travel depends on vehicle size, weight, and other characteristics. The Environmental Protection Agency (EPA) estimates that the midsize Nissan Leaf uses an aver- age of 34 kWh per 100 miles and that the Transit Connect Van uses 54 kWh per 100 miles.17 Most forecasts of plug-in vehicle demand suggest that the national electric-supply-system grid will be able to support the number of electric vehicles likely to be on the road, at least to 2020. Some local supply problems could appear, possibly in Texas, for example, where a combination of grid isolation and weak incentives for new generation appear likely to cause shortages. And in some neighborhoods the clustering of plug-in vehicles might overload local circuits and transformers. But from a national perspective, the near-term grid capacity appears adequate. Beyond that time, the energy capacity projected for the U.S. electric system also appears ample as long as the projected capacity additions are brought online (see Box 4-1). Nevertheless, three kinds of uncertainty—demand uncertainty, technology uncertainty, and policy uncertainty—will require leadership from DOE and the U.S. DRIVE Partnership to ensure the most rapid, environmentally benign market penetration and cost-effective penetration of plug-in vehicles. Three Consequential Uncertainties Even though the national grid appears adequate, the three uncertainties listed above remain. Their resolution will strongly influence the environmental and economic consequences of recharging plug-in vehicles as well as the pace of the acceptance of plug-in vehicles in the marketplace. Resolving the uncertainties in a favorable manner will require rapid learning and effective response on the part of DOE, the U.S. DRIVE Partnership, and state policy makers. Discussed in the sections below, the uncertainties can be briefly described as follows: • Demand uncertainty regarding the ways that consumers will recharge these vehicles, and how (or whether) customers will use “smart-home” 16 “Plug-in vehicle” here is meant to include any vehicle relying on electric energy that is supplied externally, most likely from the national electric grid. In the terms most commonly used, this includes battery electric vehicles (BEVs), plug-in hybrid electric vehicles (PHEVs), and extended-range elec- tric vehicles (EREVs). Generically, since all of these vehicles are dependent to one extent or another on electricity from the grid, they are sometimes all referred to as electric vehicles (EVs). 17 See, for example, http://www.fueleconomy.gov/feg/evsbs.shtml.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 135 BOX 4-1 The Plug-in Vehicle and the U.S. Electric Supply System    The impact of the plug-in vehicle on the grid depends on the market penetra- tion of electric vehicles (EVs, which include both plug-in electric vehicles [PHEVs] and battery electric vehicles [BEVs]). Forecasts vary widely. For example, Deloitte Consulting projects the 2020 U.S. market share for EVs to range from 2.0 to 5.6 percent of the new-vehicle market, or between 285,000 and 840,000 vehicles per year (LaMonica, 2010). Also, Edmunds.com projects annual EV sales of 250,000 by 2017, which would put it within the Deloitte range by 2020 (Shepardson, 2012).    If it is assumed conservatively that the number of PHEVs sold increases linearly to reach 1 million per year by 2020, that would imply an EV fleet of, at most, 4 mil- lion vehicles operating in that year. If each of these vehicles recharges a 10-kWh (usable depth-of-discharge) battery twice a day, every day for a year, the total kilowatt-hours consumed in 2020 would be about 29 billion. In contrast, the Energy Information Administration estimates that the national electric grid will be able to produce 4,159 billion kWh in 2020 (EIA, 2012). Thus even a highly optimistic case for plug-in vehicle penetration suggests that the electric energy demand of plug-in vehicles will prove manageable.    To be sure, a national or even state restriction on carbon emissions severe enough to shut down large numbers of coal-fired power plants could make this forecast unachievable. But absent such an occurrence and from a national per- spective, the energy demands imposed by the EV fleet appear to be manageable. technologies in ways that offset the grid impacts of plug-in vehicle charging; • Technology uncertainty regarding the speed of deployment of smart-grid technologies and advanced charging systems that allow rapid charging; and • Policy uncertainty regarding the nature and strength of rate incentives for consumers to recharge their vehicles and for the electric utility com- panies or others to invest in the necessary infrastructure. These uncertainties cannot be addressed independent of one another, but rather must be resolved in their entirety. Leadership from DOE and the U.S. DRIVE Partnership will prove essential for their timely and effective resolution. Absent that leadership, the market penetration of all plug-in vehicles could be delayed and their environmental and economic benefits blunted. Demand Uncertainty The location and time at which the users of plug-in vehicles will choose to recharge their batteries remain quite uncertain for several reasons. First, regarding location, many grid analysts note the tendency of plug-in ownership to occur in

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136 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP neighborhood clusters (May and Johnson, 2011). According to this “cul-de-sac effect,” plug-in vehicles tend to gravitate toward wealthy neighborhoods and environmentally conscious communities. The consequence can overload local circuits and transformers. Consider, for example, a Nissan Leaf recharging on a 240-volt, 15-amp circuit. This imposes a 3.3-kW load on the circuit, which is greater than the load of the average home in Berkeley, California. Similarly, a Chevy Volt recharging on a 240-volt, 30-amp circuit imposes a 6.6-kW load, about the average for homes in San Ramon, California (May and Johnson, 2011, p. 56). Since utility circuits and transformers tend to be sized to accommodate five or six homes, just a few vehicles can change the power loading of a circuit markedly. Thus, the charging issues posed by clusters of activity could challenge many early-adopter communities and utilities. Second, regarding time, the chief concern of vehicle users is the worry about becoming stranded with a depleted battery. And so vehicle owners have an incen- tive to recharge their vehicles’ batteries at every opportunity: while at work, in parking garages, while parked at airports, and so forth. Thus, utility planners cannot assume that all charging will be done at night when the electric grid has off-peak power. Third, the prospect for fast charging (see the section below) could make the plug-in vehicle much more desirable for customers to own because the charg- ing could be completed in 15 or so minutes instead of many hours. Thus, fast charging might accelerate market penetration if it can be accommodated on the vehicle. However, this practice poses a power challenge, as distinct from an energy challenge, to the grid. Recharging a 10-kWh battery in, say, 15 minutes would require more than 40 kW of power. Larger batteries could impose a power requirement exceeding 50 kW per charge. And since the probable high cost of the early fast chargers would appear to prohibit their use in residences, fast charging would most likely be done in public places and hence while the vehicle is in daily use. Thus fast charging could exacerbate the peak-demand problem in some localities. Finally, smart-grid technologies applied to the home could enable consumers to manage their vehicle recharging like any other appliance, and respond easily to price signals. The extent to which they adopt and use this capability and the extent to which such response might offset the local challenges posed by plug-in vehicle charging remain unknown. Technology Uncertainty In May 2012, eight automotive OEMs announced their adoption of a standard charging system, the Combined Charging System. The standard is a product of the Society of Automotive Engineers (SAE) and the European Automobile Manufac- turers’ Association (ACEA). Operating under this standard, Combined Charging Systems would integrate the following into one vehicle connector: (1) regular

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 137 alternating current (ac) charging, (2) fast ac charging, (3) direct current (dc) charg- ing in homes, and (4) ultrafast dc charging. Thus, a Combined Charging System could offer a single-port fast-charging system that still enables plug-in owners with vehicles designed for Level 1 or Level 2 to recharge at public stations. The companies endorsing this system include three U.S. DRIVE members: Chrysler Group LLC, Ford Motor Company, and General Motors Company. The ACEA has asserted that the Combined Charging System will become the standard for all European vehicles by 2017. However, other auto companies, notably Nissan and Mitsubishi, have protested the standard, and Tesla Motors (a U.S. DRIVE partner) has not adopted it. The technology uncertainty concerns the rate at which the following might occur: (1) the Combined Charging System or some other widely accepted charging standard will be adopted, (2) a new generation of plug-in vehicles able to accept fast charging will appear in the marketplace, and (3) electric utility companies can upgrade transformers, substations, and distribution networks to accommodate the increased power demand. At the same time, uncertainty exists over the pace of adoption of smart-grid technologies. On the utility side of the meter, smart-grid systems could prove more resilient to unanticipated changes in power demand brought about by fast charging. And on the customer side of the meter, smart micro-grids could manage the recharging of a plug-in vehicle in any prearranged manner. However, the rate of adoption of these technologies cannot be assured to match the rate of adoption of the vehicles. Policy Uncertainty The economic incentives for owners to charge their vehicles during times of low grid impact and for electric utility companies or unregulated entities to invest in charging infrastructure fall largely to the utility rate-making authori- ties in each state. This poses a challenge to achieving the uniformity of national (indeed, international) infrastructure required to support electric vehicle deploy- ment. Here, DOE can exercise its national leadership capabilities to encourage a stable and productive policy environment. This, in turn, would likely reduce the other uncertainties in customer behavior, technology adoption, and infra- structure investment. A DOE strategy that would exercise leadership from the national perspective will be essential for the prompt and efficient deployment of an electric charging infrastructure. The kind of leadership needed cannot be left to the grid interaction technical team alone. Effective leadership can help clarify the policy environment and lead to more uniform state policies for the build-out of charging infrastructure. Reducing policy uncertainty could, in turn, lower the anxiety felt by prospective plug-in vehicle owners about charging their vehicles in a cost-effective, timely, and environmentally friendly way.

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138 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP Recommendation 4-8. The senior DOE leadership should consider joining with their counterparts at U.S. DRIVE to work with non-U.S. DRIVE OEMs, equipment suppliers, electric utility leadership, and state regulators to build a uniform and stable policy environment for the deployment of electric charging infrastructure. RESPONSE TO PHASE 3 RECOMMENDATIONS NRC Phase 3 Recommendation 4-1. The DOE should broaden the role of the fuel pathways integration technical team (FPITT) to include an investigation of the pathways to provide energy for all three approaches currently included in the Partnership. This broader role could include not only the current technical subgroups for hydrogen but also subgroups on biofuels utilization in advanced internal combustion engines and electricity generation require- ments for PHEVs and BEVs, with appropriate industrial representation on each. The role of the parent FPITT would be to inte­ rate the efforts of these g subgroups and to provide an overall perspective of the issues associated with providing the required energy in a variety of scenarios that meet future personal transportation needs. [NRC, 2010, p. 118.] The Partnership, while recognizing the importance of investigating all three approaches, has elected to maintain the FPITT’s focus on hydrogen. The current committee also believes that broader integration and coordination are needed, and it has in fact broadened its recommendation in the current report (current Recommendation 4-1). NRC Phase 3 Recommendation 4-2. The DOE’s Fuel Cell Technologies program and the Office of Fossil Energy should continue to emphasize the importance of dem­ nstrated CO2 disposal in enabling essential pathways for o hydrogen production, especially for coal. [NRC, 2010, pp. 120-121.] The DOE responded well to this recommendation in 2010. Although the Office of Fossil Energy and the Office of Fuel Cell Technologies continue to consider carbon when setting program priorities, the post-2010 availability of natural gas as a feedstock has diminished the urgency of demonstrating hydrogen from coal. (See Recommendation 4-3 in the current report.) NRC Phase 3 Recommendation 4-3. The Fuel Cell Technologies program should adjust its Technology Roadmap to account for the possibility that CO2 sequestration will not enable a midterm readiness for commercial hydrogen production from coal. It should also consider the consequences to the program of apparent large increases in U.S. natural gas reserves. [NRC, 2010, p. 121.]

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 139 The DOE has indicated that it will add steam reforming of natural gas with cogeneration of steam to the roadmap for midterm readiness in response to the large increases in natural gas, but this option would produce more CO2 than coal gasification with carbon capture and sequestration.  Thus, the response to the recommendation is only partial.  The committee believes that other midterm options should be identified. NRC Phase 3 Recommendation 4-4. The EERE should continue to work closely with the Office of Fossil Energy to vigorously pursue advanced chemical and biological concepts for carbon disposal as a hedge against the inability of geological storage to deliver a publicly acceptable and cost- effective solution in a timely manner. The committee also notes that some of the technologies now being investigated might offer benefits in the small- scale capture and sequestration of carbon from distributed sources. [NRC, 2010, p. 121.] The DOE has responded to this recommendation with laboratory and pilot- scale projects to utilize CO2, including algal production. NRC Phase 3 Recommendation 4-5. The DOE should continue to evaluate the availability of biological feedstocks for hydrogen in light of the many other claims on this resource—liquid fuels, chemical feedstocks, electricity, food, and others. [NRC, 2010, p. 121.] The DOE Biomass Program continues to evaluate the availability of feed- stocks for use in various energy and chemical pathways. NRC Phase 3 Recommendation 4-6. The Partnership should prioritize the many biomass-to-biofuel-to-hydrogen process pathways in order to bring further focus to develop­ ent in this very broad area. [NRC, 2010, p. 123.] m The DOE and the hydrogen production technical team continue to evaluate whether biomass-based pathways can meet the hydrogen production cost targets and have conducted an independent review of these costs. NRC Phase 3 Recommendation 4-7. The Partnership should consider con- ducting a workshop to ensure that all potentially attractive high-temperature thermochemical cycles have been identified, and it should carry out a systems analysis of candidate systems to identify the most promising approaches, which can then be funded as money becomes available. [NRC, 2010, p. 123.] The DOE has conducted analyses of various high-temperature thermochemi- cal cycles and prepared a comprehensive report of the results (Perret, 2011). The

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140 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP report identified significant technical challenges and should be valuable in DOE’s program planning. NRC Phase 3 Recommendation 4-8. The EERE funding for high-­temperature thermochemical cycle projects has varied widely and was very low in FY 2009. The committee believes that these centralized production techniques are im- portant, and thus adequate and stable funding for them should be considered. [NRC, 2010, pp. 123-124.] The EERE funds three solar thermochemical production projects. The fund- ing in FY 2011 was $1.7 million. The funding level is insufficient to overcome the identified significant technical challenges. The committee believes that DOE should either increase funding consistent with the technical challenges or dis- continue the effort. NRC Phase 3 Recommendation 4-9. Water electrolysis should remain an integral part of the future hydrogen infrastructure development. The DOE should continue to fund novel water electrolysis materials and methods, including alternative membranes, alternative catalysts, high-temperature and -pressure operation, advanced engi­ eering concepts, and systems analy- n sis. Additional efforts should be placed on advanced integration concepts in which the electrolyzer is co-engineered with subsequent upstream and downstream unit operations to improve the overall efficiency of a stand-alone system. [NRC, 2010, p. 126.] In general, DOE’s program is responsive to this recommendation, particularly in view of budget constraints and limitations on other high-priority programs. Existing programs continue to address the membranes, components, and operation of the electrolysis technologies, all consistent with the recommendation. NRC Phase 3 Recommendation 4-10. Commercial demonstrations should be encouraged for new designs based on established electrolytic processes. For newer concepts such as high-temperature solid oxide systems, efforts should remain focused on labora­ ory evaluations of the potential for lifetime t and durability, as well as on laboratory performance assessments. [NRC, 2010, p. 126.] Prototype-scale demonstrations are planned as funding allows. SunHydro filling stations along the East Coast are recent commercial demonstrations of Proton’s electrolytic process, and electrolytic technologies developed with EERE funding by Proton, Giner, and Avalence are installed at NREL for an independent assessment. The response was appropriate, given existing budget constraints.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 141 NRC Phase 3 Recommendation 4-11. Work on close coupling of wind and solar energy with electrolysis should be continued with stable funding. Fur- ther improvements in electrolyzers, including higher stack pressure, and in power electronics will ben­ fit this application. [NRC, 2010, p. 126.] e Work at NREL is responsive to this recommendation. The Wind2H2 project is evaluating the integration of EERE-funded improved electrolytic technologies with wind and solar resources. NRC Phase 3 Recommendation 4-12. The Partnership should examine the goals for the photolytic approach to producing hydrogen using microorgan- isms and formulate a vision with defined targets. Otherwise, this approach should be deemphasized as an active research area for hydrogen production. [NRC, 2010, p. 128.] The DOE has responded to this recommendation with analyses of biological and photochemical hydrogen production, leading to prioritization of R&D focused on photolytic technologies. NRC Phase 3 Recommendation 4-13. Hydrogen delivery, storage, and dis- pensing should be based on the program needed to achieve the cost goal for 2017. If it is not feasible to achieve that cost goal, emphasis should be placed on those areas that would most directly impact the 2015 decision regarding commercialization. In the view of the committee, pipeline, liquefaction, and compression programs are likely to have the greatest impact in the 2015 time frame. The cost target should be revised to be consistent with the program that is carried out. [NRC, 2010, p. 129.] The DOE has been responsive by updating the technical targets and revising its cost target (as discussed further in Chapter 4 in the current report). NRC Phase 3 Recommendation 4-14. A thorough systems analysis of the complete biofuel distribution and end-use system should be done. This should include (1) an analysis of the fuel- and engine-efficiency gains possible through ICE technology development with likely particular biofuels or mix- tures of biofuels and conventional petroleum fuels, and (2) a thorough analy- sis of the biofuel distribution system needed to deliver these possible fuels or mixtures to the end-use application. [NRC, 2010, p. 132.] The response from DOE to item 1 in the recommendation is adequate. There is no response to item 2 other than saying that it is the responsibility of the Biomass Program rather than that of the FreedomCAR and Fuel Partnership. The purpose of the recommendation was to formalize a structure to help develop

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142 REVIEW OF THE RESEARCH PROGRAM OF THE U.S. DRIVE PARTNERSHIP answers to this complicated system involving the engine, the biofuel quality, and the fuel distribution system. Given the partial response, the committee cannot determine the extent to which that purpose has been fulfilled. REFERENCES CARB (California Air Resources Board). 2011. California Environmental Protection Agency, Staff Report: Initial Statement of Reasons, Advanced Clean Cars, 2012 Proposed Amendments to the Clean Fuels Outlet Regulation, December 8. Available at http://www.arb.ca.gov/regact/2012/ zev2012/zevisor.pdf. DOE (U.S. Department of Energy). 2010a. Hydrogen from Coal Program: Research, Development, and Demonstration Plan for the Period 2010 Through 2016. September. DOE. 2010b. Report of the Interagency Task Force on Carbon Capture and Storage. August. Wash- ington, D.C. Available at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskFor- ceReport2010.pdf. EIA (Energy Information Administration). 2008. “The Impact of Increased Use of Hydrogen on Pe- troleum Consumption and Carbon Dioxide Emissions.” Report No. SR-OIAF-CNEAF/2008-04. August. Available at www.eia.doe.gov/oiaf/servicerpt/hydro/appendixc.html. EIA. 2012. Annual Energy Outlook 2012: Early Release. Available at http://www.eia.gov/forecasts/ aeo/er/pdf/0383er(2012).pdf. Hallenbeck, P.C., M. Abo-Hashesh, and D. Ghosh. 2012. Strategies for improving biological hydrogen production. Bioresource Technology 110:1-9. Hamdan, M. 2011. “PEM Electrolyzer Incorporating an Advanced Low Cost Membrane.” Presenta- tion at the DOE Annual Merit Review, May 11, Washington, D.C. Available at http://www. hydrogen.energy.gov/pdfs/review11/pd030_hamdan_2011_o.pdf. Keskin, T., and P.C. Hallenbeck. 2012. Hydrogen Production from sugar industry wastes using single- stage photofermentation. Bioresource Technology 112:131-136. LaMonica, Martin. 2010. “Will Electric Cars Spread Like Cell Phones or Washing Machines?” CNET, May 14. Lee, H.-S., W.F.J. Vermaas, and B.E. Rittman. 2010. Biological hydrogen production: prospects and challenges. Trends in Biotechnology 28:262-271. Lipp, L. 2012. Electrochemical Hydrogen Compressor. “Presentation at the DOE 2012 Annual Merit Review,” May 14-18, Arlington, Va. Available at http://www.hydrogen.energy.gov/pdfs/ review12/pd048_lipp_2012_o.pdf. Maeda, K., and K. Domen. 2010. Photocatalytic water splitting: recent progress and future challenges. Journal of Physical Chemistry Letters 1:2655-2661. May, Ed, and Stephen Johnson. 2011. Top ten EV challenges. Public Utilities Fortnightly. June: pp. 56-60. NHA (National Hydrogen Association). 2010. “U.S. Market Report: Hydrogen and Fuel Cells.” Washington, D.C.: NHA. NRC (National Research Council). 2008. Transitions to Alternative Transportation Technologies—A Focus on Hydrogen. Washington, D.C.: The National Academies Press. NRC. 2010. Review of the Research Program of the FreedomCar and Fuel Partnership: Third Report. Washington, D.C.: The National Academies Press. NRC. 2011. Renewable Fuel Standard: Potential Economic and Environmental Effects of U.S. Biofuel Policy. Washington, D.C.: The National Academies Press. NRC. 2012. Sustainable Development of Algal Biofuels in the United States. Washington, D.C.: The National Academies Press. NRC. 2013. Transitions to Alternative Vehicles and Fuels. Washington, D.C.: The National Academies Press.

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HYDROGEN, ALTERNATIVE FUELS, AND ELECTRICITY 143 NRC/NAE (National Research Council/National Academy of Engineering). 2004. The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs. Washington, D.C.: The National Academies Press. NREL (National Renewable Energy Laboratory). 2004. Summary of Electrolytic Hydrogen Produc- tion: Milestone Completion Report. Johanna Ivy. NREL/MP-36734. September. Available at http://www.nrel.gov/docs/fy04osti/36734.pdf. NREL. 2008a. Wind Electrolysis: Hydrogen Cost Optimization. NREL/TP-50600-50408. May. G ­ olden, Colo.: NREL. NREL. 2008b. Wind-to-Hydrogen Project: Electrolyzer Capital Cost Study. NREL/TP-550-44103. December. Golden, Colo.: NREL. NREL. 2009. Current (2009) State-of-the-Art Hydrogen Production Cost Estimate Using Water Elec- trolysis. NREL/BK-6A1-46676. September. Golden, Colo. Available at http://www.hydrogen. energy.gov/pdfs/46676.pdf. NREL. 2010. Sunlight advances hydrogen-production technology. Energy Innovations: Science and Technology at NREL. Available at http://www.coolerado.com/wp-content/uploads/2010/03/nrel. pdf. NREL. 2012. National Fuel Cell Electric Vehicle Learning Demonstration Final Report. K. Wipke, S. Sprik, J. Kurtz, T. Ramsden, C. Ainscough, and G. Saur. Task No. HT12.8110. NREL Technical Report NREL/TP-5600-54860, July 2012, Contract No. DE-AC36-08GO28308, p. 27. Available at http://www.nrel.gov/hydrogen/pdfs/54860.pdf. Perret, R. 2011. Solar Thermochemical Hydrogen Production Research (STCH) Thermochemical Cycle Selection and Investment Priority. Sandia National Laboratories Report SAND2011-3622. May. Available at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/solar_thermo_h2.pdf. Shepardson, David. 2012. “Battery-Powered Autos Proving a Tough Sell.” Detroit News Washington Bureau, April 17. TIAX. 2011. Support for Cost Analyses on Solar-Driven High Temperature Thermochemical Water- Splitting Cycles. Final Report. February 22. Lexington, Mass.: TIAX.