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Energy Policy 37 (2009) 56–67
Contents lists available at ScienceDirect
Energy Policy
0301-42
doi:10.1
� Corr
E-m
journal homepage: www.elsevier.com/locate/enpol
Greenhouse gas reduction benefits and costs of a large-scale transition tohydrogen in the USA
William Dougherty a,�, Sivan Kartha a, Chella Rajan b, Michael Lazarus a, Alison Bailie c,Benjamin Runkle d, Amanda Fencl a
a Stockholm Environment Institute—US Center, 11 Curtis Avenue, Somerville, MA 02143, USAb Indian Institute of Technology Madras, I.I.T. Post Office, Chennai 600 036, Indiac The Pembina Institute, #200, 608—7th Street, S.W. Calgary, AB Canada T2P 1Z2d Department of Civil and Environmental Engineering, University of California, Berkeley, CA 94720, USA
a r t i c l e i n f o
Article history:
Received 12 February 2008
Accepted 25 June 2008Available online 18 September 2008
Keywords:
Hydrogen
Greenhouse gases
Energy
15/$ - see front matter & 2008 Elsevier Ltd. A
016/j.enpol.2008.06.039
esponding author. Tel.: +1617 627 3786; fax:
ail address: [email protected] (W. Dougherty).
a b s t r a c t
Hydrogen is an energy carrier able to be produced from domestic, zero-carbon sources and consumed
by zero-pollution devices. A transition to a hydrogen-based economy could therefore potentially
respond to climate, air quality, and energy security concerns. In a hydrogen economy, both mobile and
stationary energy needs could be met through the reaction of hydrogen (H2) with oxygen (O2). This
study applies a full fuel cycle approach to quantify the energy, greenhouse gas emissions (GHGs), and
cost implications associated with a large transition to hydrogen in the United States. It explores a
national and four metropolitan area transitions in two contrasting policy contexts: a ‘‘business-as-
usual’’ (BAU) context with continued reliance on fossil fuels, and a ‘‘GHG-constrained’’ context with
policies aimed at reducing greenhouse gas emissions. A transition in either policy context faces serious
challenges, foremost among them from the highly inertial investments over the past century or so in
technology and infrastructure based on petroleum, natural gas, and coal. A hydrogen transition in the
USA could contribute to an effective response to climate change by helping to achieve deep reductions
in GHG emissions by mid-century across all sectors of the economy; however, these reductions depend
on the use of hydrogen to exploit clean, zero-carbon energy supply options.
& 2008 Elsevier Ltd. All rights reserved.
1. Introduction
Mounting concerns over climate change have intensifiedinterest in hydrogen as a potential strategy to mitigate greenhousegas emissions in the US. Over the last 10 years, technologicaladvances in fuel cells, renewable energy and hydrogen productiontechnologies have helped to spur the notion of a potential H2
transition. While many analysts concede the general appeal andpotential of a future hydrogen economy in the abstract, muchdebate focuses on whether the enormous investments requiredare best targeted toward other more cost-effective mitigationstrategies (Eyre et al., 2002; Funk, 2001; Perry and Fuller, 2002;Romm, 2004; Rose, 2007a).
A considerable literature has emerged that has helped to shapean understanding of key elements involved in a hydrogentransition. Several ‘‘well-to-wheel’’ studies have focused onspecific aspects of a transition and conducted comparativeassessments of different feedstock’s energy demands and avoided
ll rights reserved.
+1617449 9603.
GHG emissions known (ADL, 2002; EU, 2004; Weiss et al., 2003).Mazza and Hammerschlag (2004) undertook a comparative studyfocused on a range of potential future systems that could meet theenergy demands of either or both the electrical grid and thetransportation sector while accounting for changes in greenhousegas emissions. A central consideration of their paper was whetherrenewable are best employed to replace petroleum in vehicles ordisplace coal- and gas-generated electricity. The primary dis-advantage of using H2 technologies identified in their paper andothers are the large inefficiencies associated with energy conver-sion. Despite the energy penalties hydrogen could play a role intransport and storage where electricity, to date, falls short (Mazzaand Hammerschlag, 2004). McDowall and Eames’ (2006) took aliterature survey approach in which they identified various driversfor a hydrogen economy that underlie much of such research, aswell as barriers, challenges, and likely characteristics of ahydrogen economy. They found that technological immaturity isa key constraint throughout the literature. Key technologyimprovements, for any transition pathway, are needed in fuel cellpower density, longevity, economics, and fuel storage (McDowalland Eames, 2006). The analysis in our study includes thecommercial scale deployment of technological pathways that
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W. Dougherty et al. / Energy Policy 37 (2009) 56–67 57
are still being proven. The production and transmission ofhydrogen has emerged as a critical element of any potentialtransition to hydrogen (Mazza and Hammerschlag, 2005; NRC,2003; Brown, 2001). Centralized production facilities are moreefficient, they also require storage systems, a pipeline transmis-sion network, and pose physical energy security and environ-mental externality issues (Sørenson, 2005). Centralized hydrogenproduction could be achieved by several processes, includingreforming natural gas or biomass and electrolysis from large-scalerenewable installations, like solar ranches and wind farms whosegeneration potential are theoretically limitless (Mazza andHammerschlag, 2004; Korpas and Greiner, 2008). Decentralizedproduction is one way to overcome many of the infrastructuralbarriers to a transition (McDowell and Eames, 2006). Decentra-lized or on-site hydrogen production could take place inresidential or commercial buildings, as could hydrogen storagefor vehicles to be re-filled after daytime driving. This option couldbe particularly interesting as residential installation could provideresidential and commercial users with their own electricity, heatand fuel for their vehicles (Rifkin, 2002; Sørenson, 2005).
Fuel cycle implications of potential hydrogen feedstocks arealso an important aspect of understanding the GHG mitigationbenefits of a hydrogen transition in the USA. The upstreamprocessing to produce hydrogen affects its price, its net GHGreduction benefits, and its primary energy conversion efficiency(ADL, 2002; Lipman et al., 2004; Pembina, 2000; Ramesohl andMerten, 2006). Renewable energy-based fuel cycles have thelowest overall GHG emissions, but low-energy efficiency and highcosts complicate their use. In the short-term, on-grid renewableenergy yields greater emissions reductions when used to replacecoal and not when used to produce hydrogen to replace gasolinein vehicles (Bossel et al., 2005; Bossel and Eliasson, 2003;Ramesohl and Merten, 2006). As such, the advancement ofrenewable energy-based hydrogen economy depends on a surplusof lower cost renewable energy on the grid (EU, 2004; Eyre et al.,2002; Mazza and Hammerschlag, 2004; Romm, 2004).
Until renewable sources become more abundant, reformednatural gas is the cheapest source of large-scale hydrogen—inboth centralized and decentralized systems—and poses thefewest technical challenges (Eyre et al., 2002; Pembina, 2000).Bossel et al. (2005) argue that for most practical applications,natural gas can do what hydrogen does and is easier to packageand distribute suggesting that merely transforming grid electri-city and natural gas into hydrogen does not resolve the energychallenges we currently face. Many others argue that natural gasis best considered a transition fuel towards the ultimate goal of arenewable energy-based hydrogen economy (Dunn, 2001; EU,2004; Weiss et al., 2000, 2003).
Demand side issues are an integral part of a transition and havebeen addressed in several ways. Smil (2003) argues that it willtake several decades to make a transition, mostly due to the lackof infrastructure and the as yet unresolved chicken-and-eggproblem (i.e., of particular concern for the transport sector, fuelcell vehicles will not be mass produced without sufficientconsumer demand, which will not exist without a well-function-ing hydrogen refueling infrastructure in place). Romm (2004)argues similarly, estimating that hydrogen vehicles are not likelyto achieve even a 5% market penetration by 2030. A more rapidtransition to hydrogen would likely only occur after stronggovernment policy, a major shift in public’s environmental values,and/or the presence of a major energy security threat. Events likethese could force the necessary rapid and large shift towardsdomestic and renewable energy production that would enable arenewable energy-based hydrogen transition.
Other analysts have applied scenario analysis techniques tobetter understand the GHG reductions and cost implications of
different transition strategies (Arnason et al., 2001; Bunger, 2004;Eyre et al., 2002; DOE, 2002; Shimura, 2007; Toshiaki, 2003). TheUS National Research Council’s scenario analysis is one of themost aggressive for the introduction of fuel cell vehicles, with 40%of all vehicles in the US being FCVs by 2030, and 100% by 2038(NRC, 2004). For the UK, Owen and Gordon (2002) analyzed aroadmap to achieving zero-carbon hydrogen powered vehicles,concluding that it would need to be implemented along with thedevelopment of a low-carbon national energy system strategy.Sweden, in working towards oil independence, has also promisedsizeable investments in hydrogen research and development(Commission on Oil Independence, 2006). In Iceland, a six-phaseplan for a national transition was analyzed. The final phase, slatedfor 2040, includes the export of hydrogen to Europe (Arnason etal., 2001; Arnason and Sigfusson, 2000).
At the policy level, debate has converged on several keyobstacles and barriers (see, for instance, Solomon and Banerjee,2006). First, the inertia of existing energy infrastructure and thelarge amount of investment in conventional energy resourcescontinues to slow the transition towards less polluting energysources. Second, much more research would be needed on thehydrogen supply chain—from well to wheels—to increase energyefficiency and cost-effectiveness; benefits of a hydrogen economydepend on how and from what sources hydrogen is produced.Third, the transportation sector, and in particular the passengervehicle sector, is stuck in the ‘‘chicken-and-egg’’ problem. Someare optimistic, however, that research and development willovercome the chicken-and-egg problem. Ohi (2000) argues that‘‘there are no technical showstoppers to implementing a near-term hydrogen fuel infrastructure for direct hydrogen fuel cellvehicles [y there are] other institutional issues to resolve, butfundamentally the technologies required are available [ythe]issue here is timing and coordination of capital investments.’’Clearly, the chicken-and-egg problem is not unique to a hydrogentransition but applies to many other supply sources. One of themain benefits, in fact, of any fuel cell technology is theapplicability of a more diverse fuel supply selection, rather thanreliance on a single fuel like oil.
The current study takes the main technology and policychallenges identified in the literature review as a point ofdeparture for a quantitative scenario analysis of how a hydrogentransition in the USA could plausibly unfold. This study exploreshydrogen transitions in two contrasting policy contexts in fourmetropolitan areas: a ‘‘business-as-usual’’ (BAU) context wherethere is a continued reliance on fossil fuels, and a ‘‘GHG-constrained’’ context where the reduction of greenhouse gasemissions is a strong policy objective. The goal of the study was tounderstand the magnitude of the GHG reduction benefits in eachmetropolitan area (Boston, Denver, Houston, and Seattle) acrossdifferent transition scenarios, together with the costs of thetransition and the energy use implications for the study regions.The analysis applied an integrated framework linking vehicle andinfrastructure technology, as well as environmental, regulatory,and economic systems in a full fuel cycle approach. Forconciseness, this paper highlights results from the nationaltransition and the case study of Boston with some cross-citycomparison. Complete results from all study areas as well as acomplete treatment of the fundamental calculation assumptionsand technical material in support of our analysis is available inseveral online annexes (see Tellus, 2006).
2. Hydrogen supply
One of the primary appeals of hydrogen is that it can beproduced from several energy sources and delivered in various
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ways. Hydrogen can be produced from natural gas, coal, biomass,grid electricity and electricity from dedicated renewables. It canbe produced by either small, on-site units installed at refuelingstations, or centrally at large stations remote from the demandsource. Hydrogen delivery, which can be achieved through tubetrailer and/or by pipeline, was analyzed as provided by anintegrated transmission and distribution pipeline network. Thecarbon dioxide produced from centralized hydrocarbon to hydro-gen production activities can be captured and geologicallysequestered in depleted oil and gas wells or saline aquifers. Thereare several issues yet to be resolved regarding where the storagesites are located, what technology will be used, how much storagecapacity is underground, and monitoring and verification (Herzog,2001; Stevens et al., 1999). Fig. 1 provides an overview of the basicelements of the hydrogen supply infrastructure considered in theanalysis.
The chain connecting a primary energy source to end-useenergy service is—energetically speaking—long and tenuous.Hydrogen production suffers from considerable conversion, dis-tribution, and end-use losses. Even though fuel cell end-usedevices are relatively efficient, hydrogen production losses aregenerally comparable to—or greater than—the losses in energypathways for other energy carriers, such as gasoline andelectricity. For example, a commonly cited analysis comparestransmission of wind energy via both hydrogen pipelines and highvoltage direct current lines. This study found that wind energysent as hydrogen retains 45–55% of the original energy whileelectricity retains 92% of the original energy and therebyproviding nearly twice the end-use benefits as wind energydelivered as hydrogen (Mazza and Hammerschlag, 2004).
2.1. Hydrogen production options
Hydrogen production from natural gas is well proven anddeployed on a commercial scale already. Our analysis considers
Transmission pipelineTransmission feeder pDistribution pipelineSequestration pipelineSequestration feeder pCentral reforming facil
Central electrolysis fac
Supply source
Legend
Fig. 1. Idealized hydrog
this method viable at both large-scale central facilities as well assmall-scale facilities located at on-site at refueling stations. Alarge percentage of the hydrogen produced today in the US isproduced by steam reforming of natural gas (DOE, 2006a).
Hydrogen production from coal and biomass, both viagasification and syngas reforming, was assumed viable only atlarge-scale central facilities. Though not nearly so widelypracticed, hydrogen production from coal has been proven on anindustrial scale, primarily for production of hydrogen as an inputto ammonia fertilizer (Mueller-Langer et al., 2007). Hydrogenproduction from biomass is a process very similar to hydrogenproduction from coal. Biomass gasification is also well demon-strated and under continuing development for power production.The downstream synthesis steps are highly analogous and indeedsimplified by the lower level of sulfur and heavy metalcontaminants in biomass compared to coal (US DOE, 2006b;Spath and Dayton, 2003).
Production from grid electricity (via electrolysis) was consid-ered at both small-scale facilities located at refueling stations, aswell as at large-scale facilities located at sites of remote butabundant non-grid-connected renewable energy resources. Elec-trolytic production of hydrogen is also commercially practiced,though generally at small scales (Mueller-Langer et al., 2007).Each of these hydrogen production technologies displays differentcarbon emission characteristics, as summarized in Fig. 2. Theimportance of carbon capture and sequestration is highlighted (incomparing columns with and without sequestration), as is thecontrast between central biomass reforming and the otherproduction technologies. Centralized biomass reforming has netnegative emissions per kg of hydrogen produced because thebiomass feedstock is used sustainably without sequestration,thereby emitting no net GHGs. Centralized electrolysis frompower generation by large dedicated wind farms is the onlyzero-carbon technology considered in this study. For some ofthese technologies, there are likely to be improvements over timeon the efficiency of the production process.
ipeline
ipelineity
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en supply network.
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-20,000
-10,000
0
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40,000
gm C
O2
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g H
2 pr
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Sequestration 0Process fuels 0Feedstock losses 10,994
Feedstock 23,337
on-site electrolysis on-site NGreforming
Central NGreforming (nosequestration)
Central NGreforming (withsequestration)
Central coalreforming (nosequestration)
Central coalreforming (withsequestration)
Central biomassreforming (nosequestration)
Central biomassreforming (withsequestration)
Centralelectrolysis (from
wind)
0 0 816 0 816 0 816 0536 399 399 399 399 2,930 2,930 0
2,126 2,073 311 4,491 404 0 -3,576 0
00 -11,9731,039011,5451,0136,756 6,756
Fig. 2. CO2 emissions per kg hydrogen for various production technologies.
W. Dougherty et al. / Energy Policy 37 (2009) 56–67 59
There are many other options, most of them longer-term andstill very much in the development phase (Lipman, 2004). Theseare not included among the hydrogen production options in theanalysis although they may ultimately prove important. Theseinclude various chemical, biological, and nuclear paths tohydrogen production that are currently under development.Chemical paths involve using chemical reagents acting underhigh-temperature conditions to disassociate water and segregatethe oxygen and hydrogen into separately recoverable streams.
Nuclear paths involve using nuclear reactor heat coupled witheither electrolysis (‘‘hot electrolysis’’) or chemical cycles todisassociate water and recover hydrogen. Biological paths (otherthan biomass gasification) employ hydrogenic algae to usesunlight to produce hydrogen. The chemical, biological, andnuclear options are in various stages of research and development,and any of them could conceivably prove competitive in the long-term with the conventional options on which this study is based.Indeed, it would be surprising—and disappointing—if the optionsconsidered in this study remain the most technologicallyattractive and cost-effective options throughout the cominghalf-century. To the extent that other hydrogen productionoptions might become viable, as mentioned previously, thescenarios constructed for the analysis are technologically con-servative.
2.2. Hydrogen delivery options
Hydrogen delivery is important for two main reasons. The firstis that it is a challenging and costly element of the hydrogentransition. As many observers have pointed out, hydrogen has amuch lower energy density than fuels such as gasoline and dieseloil. This adds technical difficulty and cost to all the major modesof delivery—gaseous hydrogen tube trailers, liquid hydrogentanker trucks, and pipelines. Tube trailers can typically carry300 kg of gaseous hydrogen, or approximately 20 passenger-vehicles worth of fuel. Hydrogen tanker trucks can carryapproximately 4000 kg of liquid hydrogen supply for about 265passenger-vehicles. This option approaches the capacity of atypical gasoline tanker truck, which carries roughly 300 passen-ger-vehicles worth of fuel. However, liquid hydrogen suffers froma significant energy penalty due to the compression requirementsfor hydrogen liquefaction and the hydrogen lost due to pressurerelease valves (ADL, 2002). Until tube trailer and tanker deliverymethods prove more cost effective through significant advances invessel technology, neither will likely play more than a transitional
or niche role in the long-term hydrogen delivery infrastructure(Aceves et al., 2005). Barge and rail delivery are additional optionsoffering higher load-carrying capacities and higher weight limitsthan over-the-road trailers and might play roles in particulargeographic settings like remote areas (DOE, 2007).
With respect to long-term strategies for providing the end-userwith a reliable hydrogen supply, the analysis focuses on two majoroptions: on-site hydrogen production at refueling stations, andcentralized production with pipeline delivery. On-site productionis preferred to centralized hydrogen production when bothabsolute hydrogen demand and hydrogen demand density arerelatively low. Hydrogen demand density, a variable central to thecity-based analysis, refers to the amount of hydrogen consumedwithin an area of demand and is expressed in units of energy perland area (i.e., trillion Btu per square mile). Pipeline deliverybecomes economically feasible when absolute hydrogen demandgrows large enough to warrant a large centralized facility, anddemand density becomes high enough to make pipeline distribu-tion less costly than the on-site alternative (Yang and Ogden,2007). Without pipelines, the use of hydrogen cannot have anycarbon reduction benefits in cogeneration, or significant benefitsin the transport sector.
2.3. Carbon capture and sequestration technologies
Geological sequestration of carbon dioxide is a technologicaloption that can be coupled with the production of hydrogen fromnatural gas, coal, and biomass in large-scale centralized facilities.While technologically possible for small-scale hydrogen produc-tion at refueling stations, the costs of a pipeline system forcollecting carbon dioxide from multiple dispersed refuelingstations would be prohibitively costly.
It is important to note that while carbon capture relies onstraightforward and well-understood technology, sequestration ismore speculative. Sequestration in depleted oil and gas wells is amature technology and used widely to enhance recovery from oiland gas fields (Herzog, 2001). However, these sequestration sitesare not widely distributed, and the total estimated storagecapacity in oil and gas fields in the continental United States hasbeen estimated to be approximately 98 billion MtCO2 (Stevens etal., 1999).
In contrast, deep saline aquifers are much more widelydistributed with much greater storage capacity; however, experi-ence with saline sequestration is much more limited. Questionsremain regarding the long-term security of sequestered carbon
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dioxide, and the potential for environmental impacts due to theacidification of groundwater by carbon dioxide and the subse-quent mobilization of heavy metals.
The analysis acknowledges the uncertainty surrounding se-questration, especially in deep saline aquifers. The potential forCO2 sequestration to address the climate problem in the context ofhydrogen production, has such potential that we have consideredtwin variants of each of the main hydrogen scenarios, BAU+H2 andGHG+H2, by comparing scenarios that do not use carbon captureand sequestration with variants that do.
0
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Car
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eco
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pgge
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ICE gas cars Hybrid gas carsFuel cell cars Dual fuel (gas/H2) cars
ICE gas LDTs Hybrid gas LDTsFuel cell LDTs Dual fuel (gas/H ) LDTs
2000 2010 2020 2030 2040 2050
3. Hydrogen demand
Since hydrogen is a carrier, much like electricity, it can beemployed in a variety of applications. The greatest demand forhydrogen will likely be in the transport sector, which currentlyaccounts for roughly one-third of primary energy demand in theUS, about three quarters of which is consumed by passenger traveldemand and the rest by freight (EIA, 2003). Depending on whichenergy conversion techniques emerge as commercially feasible, aplausible alternative pathway could be that the greatest demandinitially for hydrogen would be for heat and power in theresidential sector. All transportation modes other than aircraftcan potentially use hydrogen as a fuel using near-term technology,potentially displacing significant amounts of petroleum by 2050.While air travel is a significant source of greenhouse gasemissions, hydrogen is not under serious consideration as anaviation fuel except in some early research programs, in large partbecause of its low density and storage challenges for long-haulflights. The analysis considers that hydrogen displaces gasolineand diesel (non-military) in cars, light trucks, heavy-duty vehicles,marine vessels, and trains. In 2000, total energy consumed bythese on- and off-road categories represented about 80% of totaltransportation energy use (EIA, 2003).
Hydrogen for other sectors can be employed most fruitfully incogeneration applications, by providing heat and electricity forindustrial, residential and commercial establishments (Dietzler,1997; Zabalza et al., 2006). Here, the growth of a hydrogen supplyinfrastructure faces different constraints than in the transportsector. For stationary applications, the ‘chicken–and–egg’ problemis mitigated by the fact that the hydrogen supply infrastructureneed not be ubiquitous—it can be confined to a bounded regionwhere significant demand exists. In stationary applications, thecarbon benefits of using hydrogen are modest (or non-existentbenefits from using hydrogen become substantial only whencoupled with a carbon capture and sequestration strategy. In2000, total energy consumed in cogeneration facilities repre-sented about 5% of total energy use in the residential, commercial,and industrial sectors (EIA, 2003).
2
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Truc
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my
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2010 2020 2030 2040 2050
Fig. 3. New car and light duty truck fuel economy assumptions.
3.1. Cars and light trucks
The greatest impact of hydrogen will be for cars and lighttrucks, or light-duty vehicles (LDVs). LDVs currently comprise thelargest stock of vehicles (over 200 million) and greatest share ofenergy demand (about 58%) in the transportation sector (EIA,2003). The average fuel economy of LDVs has actually declinedover the past two decades, primarily because of a trend towardincreasing sales of heavier vehicles, including light-duty trucks(EIA, 2003). Any change in LDV stock in the US, and likely othercountries, will be largely due to education campaigns thatheighten consumer awareness to the benefits of purchasingvehicles with high fuel economies rather than continuing thetowards purchasing heavier, less-efficient ones.
On the basis of per unit of service delivered—in this case,passenger miles traveled—the switch to hydrogen could poten-tially provide large efficiency improvements over today’s vehicles.This is so not only because fuel cells offer substantial efficiencygains over conventional internal combustion engines, but becausetoday’s internal combustion engine vehicles (ICEVs) are currentlywell below their potential efficiency levels compared to techni-cally feasible and commercially viable choices for conventionalcombustion and hybrid-electric technologies (Frank, 2007). Fig. 3illustrates fuel economy assumptions for new LDVs.
As shown in the figure, hydrogen fuel cell vehicles (HFCVs)stand to offer marked improvements over internal combustionvehicle technologies, including hybrids. Hydrogen offers thepossibility of dramatically reducing transport sector emissions,provided that upstream carbon emissions associated with hydro-gen production and delivery are low or zero. Fig. 4 shows the‘‘well-to-wheels’’ greenhouse gas emissions of various car-fuelchain combinations assuming current year fuel economies. Thefuel economy assumptions noted on this chart reflect valuesexpected at the end of the scenario period. Natural gas (NG)reforming options assume the use of domestic resources. Thisfigure illustrates the level of greenhouse gas emissions that occurbetween extraction and delivery to the vehicle (‘‘upstream’’emissions) and those that occur during operation of the vehicle(‘‘vehicle’’ emissions).
The factory costs of HFCVs are expected to be anywhere from20% to 60% above those of ICEVs (ADL, 2002; Demirdoven andDeutch, 2004; Ogden et al., 2001) at production volumes reaching500,000 units per year. Further learning may bring the costpremium down, but significant technological challenges remain,including on-board hydrogen storage, further reducing the needfor noble metal catalysts, and increasing the lifetime of the fuel
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0100200300400
500600700800900
Conventionalgasoline ICE(24 mpgge)
Advancedgasoline ICE(34 mpgge)
Diesel ICE(32 mpgge)
Alternative-fueled
(CNG) (23mpgge)
Hybridelectric gas(65 mpgge)
Fuel cell (on-site
electrolysis)(78 mpgge)
Fuel cell (on-site
NGreforming)(78 mpgge)
Fuel cell(centralized
NGreforming)
(78 mpgge)
Fuel cell(centralized
biomassreforming)
(78 mpgge)
Fuel cell(centralized
coalreforming)
(78 mpgge)
Fuel cell(centralizedelectrolysisfrom wind)(78 mpgge)
gm C
O2
per m
ile
VehicleUpstream
Fig. 4. Well-to-wheels comparison of CO2 emissions per mile for cars.
W. Dougherty et al. / Energy Policy 37 (2009) 56–67 61
cell stack (Berry and Aceves, 1998; Brown, 2001; Kempton andKubbo, 2000; Rose, 2007b). On-board storage is a concern giventhe high storage pressure and the associated cost and weight ofthe pressure vessel to meet reasonable vehicle ranges.
Breakthrough technologies, such as carbon nano-tubes andmetal and chemical hydrides are at incipient stages of develop-ment and do not yet fully satisfy storage requirements (Ross,2006). For the purposes of this analysis, however, most, if not all,of these problems will have been resolved over a 20-yeartimeframe, which is supported by the expected technical progressdescribed in Chalk and Miller (2006).
Two transitional strategies for light-duty vehicles wereconsidered to help overcome the notorious chick-and-egg pro-blem plaguing the hydrogen transition. The first strategy is toinvolve private and government fleets (currently comprising closeto one-fifth of annual vehicle sales) as early adopters of HFCVs,since many have dedicated refueling facilities and do not dependon the existence of a universally available hydrogen retailrefueling infrastructure. While the same argument could be madefor any alternative fuel and/or technology (e.g., introducingelectric vehicles into private and government fleets), the focuswas on early adopters and strategies to induce improvedeconomies of scale for hydrogen use. Providing fleet operatorsincentives to provide hydrogen on a retail basis to private vehiclesover time would build up hydrogen demand among vehicle fleetsand help launch the ‘‘take-off’’ phase of a hydrogen transition.
The second transitional strategy is the limited introduction ofdual-fuel ICEVs (with hybrid-electric technology for efficiencygains) during the early years of the hydrogen transition in boththe passenger and fleet markets. ICEVs that can burn eithergasoline or hydrogen are already available from BMW, and onesthat run only on hydrogen are being developed by Mazda and Ford(Cho, 2004). Like fleet vehicles, these dual-fuel vehicles can helpovercome the chicken-and-egg problem by providing an earlysource of demand for hydrogen without the need for a ubiquitoushydrogen refueling infrastructure. Given that the technology fordual-fuel ICEVs is readily available, they can serve as a transitionaltechnology that helps build demand for hydrogen (and thecorresponding supply infrastructure) at relatively low risk toconsumers, timed to pave the way for the commercialization ofprivate HFCVs. We assume that first such vehicles are introducedin the early stages of the transition, and the share of hydrogenvehicles on the road gradually increases from 25% and approach100% by 2021.
Of course, building up a hydrogen demand through fleets andthrough dual-fuel vehicles will require financial incentives for
suppliers and consumers during the early years of the transition.Dual-fuel hybrid ICEVs will likely be less efficient than FCEVs oreven advanced hybrid gasoline ICEVs. However, the efficiencypenalty may be a justified price to pay to facilitate the speedieradoption of FCEVs, which would be introduced into a market that,by that time, should reflect and benefit from a growing record ofsuccessful technology diffusion in other parts of the industrializedworld.
To account for the need for a faster ramp up, an additionalstrategy is introduced that focuses on a gradual phase-out ofconventional vehicles once they reach an age of 5 years, with areplacement with new fuel cell LDVs. Through this strategy,roughly the same HFCV stock levels are reached by 2050.
3.2. Heavy-duty and off-road vehicles
Collectively, heavy-duty vehicles (HDVs), marine vessel, andtrains currently consume close to a third of total energy use in thetransportation sector (EIA, 2003). Heavy-duty vehicles consideredin this study include commercial delivery trucks, medium toheavy freight trucks, as well as transit, intercity, and school buses.Marine vessels include domestic shipping used in the transport ofcargo and passengers, as well as recreational boats. Rail applica-tions are focused on transit and freight trains.
A doubling or so in the efficiency of this segment of thetransport sector could be expected as a result of conversiontoward hydrogen fuel cells. HDVs, marine and rail vehicles are, insome ways, better candidates than LDVs for hydrogen fuel cellsbecause they have less severe volume constraints, and hencesufficient capacity for hydrogen storage tanks. Similarly, whilelong-haul freight trucks will need a national network of hydrogenfueling stations, their needs could well be met by centralizedfueling facilities. A focus on this sector’s transition to hydrogenfueling is suggested in greater detail by Farrell et al. (2003).
3.3. Combined heat and power
There are limited opportunities for significant gains inefficiency for stationary uses of hydrogen. Nevertheless, onepotentially strategic end use is for cogeneration at smallcommercial and large industrial facilities. Combined heat andpower (CHP) in small commercial facilities and large industrialfacilities with excess electricity sold back into the central gridoffers important reliability benefits.
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Cogeneration at commercial and industrial facilities is as-sumed to use natural gas. Annual levels of natural gas demand forCHP are based directly on outputs from the Annual Energy Outlook
2003 (AEO, 2003) up through 2025, and extrapolated to 2050assuming levels of cogeneration were consistent with thetechnical potential (i.e., roughly 75% more demand by 2050)(EIA, 2003). In the hydrogen transition scenarios, cogenerationuses gaseous hydrogen piped from central production facilities.
4. Analytical framework
The economic, political, and technological environment influ-ences the type, extent, costs, and potential benefits of transition toa hydrogen economy in the United States. A full fuel cycle analysiswas undertaken within a 2000–2050 period using H2M; a modeldeveloped by the authors for the analysis of energy use, GHGemissions, and delivered H2 cost impacts of an expanding demandfor hydrogen. The H2M model incorporates databases on regionalenergy supply and regional demand characteristics, includingrefueling station information, hydrogen production facility costand performance characteristics, fossil-fuel prices, electric systemcharacteristics, annual vehicle sales, fuel economy trajectories,and other variables. Fig. 5 illustrates the major components of themodel. (For a more complete description of the model used forthis paper’s analysis, see Volume IV of the original report—Tellus,2006).
• H2 production cost, performance • ICE and FCV cost, performance • Fuel cycle feedstock & process
fuel inputs • Carbon-equiv emission factors • Electric supply cost, performance • Cogeneration cost, performance
• Benchmarking to AEO2• LDV & HDV stock turn• Central H2 production e• On-site production expa• Pipeline network (H2 an• Electric supply expansio• Cogeneration expansion• Off-road energy use (ma• Upstream energy use (p
Total energy use (by fueHydrogen production inHydrogen demand levelCarbon-equivalent emisH2 demand and supply cT&D, end use)
Fig. 5. H2M modeli
Hydrogen transitions were modeled in H2M using a scenarioapproach, benchmarked against two counterfactual scenarios: theBAU counterfactual embodied by the Energy Information Agency’sAnnual Energy Outlook 2003 reference case (EIA, 2003), and theGHG-constrained counterfactual based in large part on America’s
Global Warming Solutions (Bernow et al., 1999). The modelingframework explored three plausible and techno-economicallyfeasible policy contexts as follows:
�
003ovexpansiod Cn (p rin
roce
l cyfrass sionost
ng f
The ‘‘Business-As-Usual’’ scenario (i.e., BAU+H2) assumes that ahydrogen transition occurs in the context of a non-GHG-constrained trajectory reflected by a continued dependence onfossil fuels and notable absence of aggressive energy efficiencyand renewable energy strategies
� The ‘‘Greenhouse Gas Constrained’’ scenario (i.e., GHG+H2)assumes that a hydrogen transition occurs in the context of aGHG-constrained trajectory reflected by commitment to large-scale improvements in energy efficiency and widespread use ofrenewable energy.
� The ‘‘Shock’’ scenario (i.e., BAU+Shock H2) assumes that ahydrogen transition occurs in the context of the BAU scenariountil a point in the future in which a hydrogen transition isdetermined to be a far more critical response to the climatecrisis than originally thought and an accelerated transitiontakes place.
The model projects changes in the national and regionalenergy systems by a focus on hydrogen demand density, vehicle/
• Base year energy use • Demographic/economic growth • Regional travel behavior • FCV penetration rates • H2 CHP penetration rates • Fuel price growth rates • Refueling station infrastructure
r nsion n and stock turnover
O2) expansion ower stations, T&D)
e, rail) ss fuels)
cle stage and fuel type) tructure
s s (capital, fuel, O&M,
ramework.
ARTICLE IN PRESS
W. Dougherty et al. / Energy Policy 37 (2009) 56–67 63
equipment stock turnover, upstream/end-use carbon emissions,and cumulative costs associated with hydrogen infrastructurerequirements. Underlying the analysis are several major premises,as follows:
�
Equivalent mobility. The same levels of mobility in the transportsector exist in each of the scenarios, meaning that the refuelinginfrastructure should be as ubiquitous and dependable afterthe transition as it is in the current system. The case studyanalyses for the four cities assumed a concurrent nationaltransition. � Resource constraints. Annual reductions in domestic energysupplies (i.e., coal, natural gas) and annual biomass supplieswere tracked to ensure that sufficient feedstocks exist withouttriggering price shocks stemming from approaching resourcescarcity.
� Regional variation. There will be significant regional variationsin the shape of the hydrogen transition, depending ondemographic patterns, travel behavior, economic activity, fuelprices, electric supply systems, and land use characteristics.For this reason, the study emphasized the integration of asmuch city-specific information and characteristics as possible.
� Vehicle stock turnover. One of the key limiting factors on therate of a hydrogen transition is the inertia in the large currentstock of light and heavy-duty vehicles. To capture the processof gradual evolution of vehicle stock, a detailed stock turnovermodel was developed and integrated into H2M. Two maintransitional strategies were modeled: first, government fleetsas early adopters of HFCVs and second, the limited introduc-tion of dual-fuel ICEVS, with hybrid-electric technology forefficiency gains, during the early years of the hydrogentransition in both the passenger and fleet markets.
� Feedstocks for hydrogen production. Natural gas was consideredviable for both on-site and large-scale production facilities.Electrolysis from grid electricity was modeled at small-scaledistributed sites, while large-scale electrolysis relies on non-grid-connected renewable energy resources.
� Hydrogen production facilities. On-site hydrogen productionunits (electrolysis or natural gas reforming) are sites forhydrogen production during the early years of the transitionin response to the initially low and relatively dispersedhydrogen demand. Centralized hydrogen production facilities(natural gas, biomass, electrolysis), and the necessary pipelinetransmission/distribution infrastructure are built once abso-lute hydrogen demand grows large enough.
� Energy choices. The BAU+H2 and BAU+Shock scenarios wereanalyzed as primarily fossil fuel based (i.e., coal and naturalgas), consistent with the Energy Information Administration’sAnnual Energy Outlook for future trends in the energy sector atlarge. The GHG+H2 scenario was analyzed as primarily basedon renewables (wind, solar, biomass), consistent with thetrends toward greater reliance on renewable energy.
� Price and cost feedback effects. The supply and demandintegration framework explicitly models several interactiveeffects related to technology capital costs and fuel prices. Theseinteractions, which can be either positive or negative, areessentially impacts on cost or price in one city or region basedon changes in the overall market.
� Electric system expansion. Insofar as electricity is needed toproduce hydrogen, the hydrogen transition will affect how theelectric system expands. The electric sector was modeled asevolving in a manner consistent with the underlying premisesof the corresponding base case situation. Up through 2025,electric sector expansion is modeled using the US Departmentof Energy’s National Energy Modeling System (NEMS) and
maps its results to the four focus cities. Beyond 2025, trends inthe preceding period were extended to meet regional elec-tricity demand, and consistent with resource constraints.
� Sequestration. Carbon sequestration is assumed a viable optionthat is broadly pursued. While the availability and efficacy ofcarbon capture and sequestration options have large uncer-tainty bounds, the study assumed that future improvementsoccur in carbon capture and storage technology such thatgreenhouse gas emissions from central reforming units can besequestered at reasonable carbon capture levels: 91% for coaland biomass and 85% for natural gas. Nevertheless, given theinherent uncertainties regarding long-term storage, the studyalso considered a no-sequestration sensitivity.
5. Results
At the national level, the results show that overcoming theinertia inherent in current energy infrastructure based onpetroleum, natural gas, coal, and electricity will require sub-stantial investment in new infrastructure and technology. On theother hand, the results indicate the USA can achieve significantreductions of greenhouse gas emissions, especially when coordi-nated with national energy policy that seeks to contain economy-wide growth in greenhouse gas emissions for non-hydrogenconsuming end uses.
At the national level, total hydrogen demand by 2050 reachesbetween 120 and 190 million metric tons, depending on thescenario (Fig. 6a). By 2050, 80% of hydrogen is centrally producedand delivered by pipeline. Meeting these levels of demandrequires substantial new production and delivery infrastructure(Fig. 6b). Annual delivered costs of hydrogen for the USA convergeto about $2.3/kg H2 in the BAU+H2 and BAU+Shock H2 scenarios,and to just over $2.4/kg H2 in the GHG+H2 scenario (Fig. 6c).
Regarding GHG emissions associated with energy use in the USeconomy, greenhouse gas emissions nearly double by 2050 in theBAU scenario relative to 2000 levels (see Fig. 7). It is important tonote that even with a large-scale switch to hydrogen for major enduses, GHG emissions would still increase in absolute terms by2050 by about a billion tons metric tons of CO2-equivalent (CO2eq)for both the BAU+H2 and BAU+Shock H2 scenarios relative to 2000levels. These levels are still about 400 million tons less than whatthey would have been in 2050 in the BAU scenario; equivalent to areduction of about 15%.
The GHG+H2 scenario contrasts significantly with the otherscenarios analyzed. For the GHG+H2 scenario, a large-scale switchto hydrogen would avoid nearly 700 million ton of CO2-equivalentemissions relative to 2000 levels, or about a 40% reduction fromemission levels in that year. Compared to expected BAU levels in2050, the GHG+H2 scenario would avoid about 2 billion ton metrictons to what they would have been in the absence of strengthenedenergy efficiency and renewable energy policies.
These results illustrate the importance of the energy policycontext for the transition to hydrogen. In the BAU+H2 andBAU+Shock H2 scenarios, with their continued dependence onfossil fuels and lack of aggressive energy efficiency and renewableenergy strategies, switching to hydrogen still leads to higher GHGemission levels in absolute terms relative to year 2000 levels. Inthe GHG+H2 scenario, with its underlying support for energyefficiency and renewable energy, switching to hydrogen leads toless tons of carbon released in 2050 relative to year 2000 levels.
This point is further emphasized when one considers hydrogentransitions without carbon sequestration. Given the uncertaintiesregarding the long-term security of sequestered carbon dioxide,
ARTICLE IN PRESS
Type of InfrastructureBAU+
H2
GHG+H2
BAU+Shock H2
Hydrogen refueling stations200,000200,000200,000Total
On-site production unitson-site electrolysison-site NG reforming
41,71460,46639,484latoTCentralized production units
Large NG reformingLarge biomass reformingLarge coal reformingCentralized electrolysisSmall NG reformingSmall biomass reformingSmall coal reforming
1,5002,3301,816latoTPipelines (miles)
TransmissionDistributionSequestration
444, 106897, 301639, 793Total
19,750 36,512 20,86120,85323,95419,734
496 70 332100 693 67397 278 2650 279 0
411 68 41883 672 84
329 270 334
151,532382,814105,447
135,793 133,018219,277371,988
389,520 91,811
0
50
100
150
200
250
BAU+H2 BAU+Shock H2GHG+H2
Mill
ion
tonn
es
Light duty vehicles Heavy duty vehicles MarineRail Cogeneration
0
2
4
6
8
10
205020402030202020102000
2001
$/kg
H2
BAU+H2 GHG+H2BAU+Shock H2 gasoline price ($/gallon)
Fig. 6. Hydrogen demand, infrastructure requirements and costs by 2050, USA: (a) hydrogen demand, (b) infrastructure requirements, and (c) delivered H2 costs.
0
1,000
2,000
3,000
4,000
205020402030202020102000
mill
ion
tonn
es C
-equ
iv
BAU GHGBAU+H2 GHG+H2BAU+Shock H2
Fig. 7. Carbon emissions (sequestration included)—all end uses, USA.
W. Dougherty et al. / Energy Policy 37 (2009) 56–6764
investments in the required carbon capture and sequestrationmay not be warranted. In such a case, the carbon reductionbenefits from a transition to hydrogen would be roughly halvedfor the BAU+H2 and BAU+Shock H2 scenarios, and largelyunaffected for the GHG+H2 scenario.
At the metropolitan area level, trends are similar to thosereported above for national trends. Total hydrogen demand—aswell as the spatial distribution of areas serviced by centralfacilities and pipeline distribution networks—shows significantvariation across the cities of Boston, Seattle, Denver, and Houston.Moreover, on a cost of hydrogen basis, some urban areas will bebetter positioned to embark on a hydrogen transition given arange of city-specific factors like demographic characteristics,feedstock resource availability, regional fuel prices, travel beha-vior, and industrial activity. For instance, Houston’s higherindustrial level encourages greater hydrogen use for cogeneration.Denver’s more dispersed population creates less use at any onerefueling station or production facility, increasing initial capitalcosts but allowing for greater infill development as the scenariosprogress. As modeled, Boston has higher urban hydrogen demand,while the Seattle metropolitan area includes a larger low-demand,on-site production region. Such on-site production zones areprojected to be twice the cost of centrally produced hydrogen by2050, yet may be unable to adequately support a pipelinedistribution network. Finally, expected hydrogen feedstocksdepend on current regional trends, and suggest that Seattle andBoston would supply hydrogen through a mix of central naturalgas reforming and biomass reforming, while Denver and Houston
ARTICLE IN PRESS
Fig. 8. Boston metropolitan area hydrogen transition spatial summary details for the BAU+H2 scenario, 2050.
Table 1
Type of infrastructure BAU+H2 GHG+H2 BAU+Shock H2
Hydrogen refueling stations
Total 200,000 200,000 200,000
On-site production units
On-site electrolysis 19,750 36,512 20,861
On-site NG reforming 19,734 23,954 20,853
Total 39,484 60,466 41,714
Centralized production units
Large NG reforming 329 270 334
Large biomass reforming 83 672 84
Large coal reforming 411 68 418
Centralized electrolysis 0 279 0
Small NG reforming 397 278 265
Small biomass reforming 100 693 67
Small coal reforming 496 70 332
Total 1816 2330 1500
Pipelines (miles)
Transmission 105,447 389,520 91,811
Distribution 382,814 371,988 219,277
Sequestration 151,532 135,793 133,018
Total 639,793 897,301 444,106
W. Dougherty et al. / Energy Policy 37 (2009) 56–67 65
would supply hydrogen through a coal-reforming system. Anonline annex provides an overview of the spatial, demographic,and refueling infrastructure for the four study metropolitan areas;see Tellus, (2006).
For the Boston greater metropolitan area, a spatial summaryof hydrogen production infrastructure requirements is shown inFig. 8 for the BAU+H2 Scenario in 2050. The left side of the figureprovides a spatial summary of hydrogen infrastructure showingthe location of hydrogen refueling stations, with blue dotsreferring to retail refueling stations and red dots referring to fleetrefueling stations. It also illustrates the area (shaded dark green)within the overall metropolitan region where hydrogen distribu-tion pipelines are connected to refueling stations. These darkgreen-shaded areas represent the spatial boundaries within theoverall metropolitan area where the demand for hydrogen is largeenough so that production of hydrogen from central facilities ismore cost-effective than production from on-site equipment.
The right side of the figure provides a tabular summary ofhydrogen demand, infrastructure requirements, and deliveredcosts. Specifically, Table 1 summarizes the annual hydrogendemand, the total number of hydrogen refueling stations, thenumber and type of on-site units still in service by 2050, thenumber and type of central facilities operating to meet municipaldemand, total lengths of the various types of pipelines installedand delivered costs in units of $/mm Btu and $/kg of hydrogen.Fig. 9 shows the spatial evolution in central hydrogen production.The dark green-shaded areas represent those counties wherehydrogen demand exceeds 10 billion Btu per square mile andwhich is met by centralized hydrogen production facilitiesdelivered via transmission pipelines.
6. Conclusions and recommendations
The following points aim to identify the broad, high-levellessons and conclusions that can be drawn from this study. Theyare reasonably robust to modest changes in the techno-economicassumptions that underlie this analysis. That said, there remainsconsiderable uncertainty in how hydrogen and fuel cell technol-ogies will develop, and even more so in how the socio-economicand political context will evolve.
Hydrogen is only as compelling as its feedstock supply. Thebenefits of hydrogen do not derive from its greater life-cycleefficiency, but rather from the prospect of using hydrogen to
exploit clean, zero-carbon energy supply options. Hydrogenderived from some production pathways (e.g., using fossil energyresources without sequestration) could well have greater negativeimpacts than our conventional energy systems.
Hydrogen has stiff competition from other energy options. Otheroptions such as biofuels and electricity from renewable energyresources are strong contenders for secure, clean, low-GHGenergy. Battery technologies for electric vehicles continue toadvance. Cellulosic ethanol and biodiesel, in particular, have thepotential for making a significant contribution to total transportfuel supply.
Hydrogen could be an important component of a national climate
policy based on renewables and efficiency. The GHG+H2 scenarioavoids over 2 billion tons CO2-equivalent of GHG emissions in2050 across the full fuel cycle relative to the BAU scenario. Of this,approximately 0.8 billion tons can be attributed to the transitionto hydrogen. In contrast, the BAU+H2 transition scenario avoidsonly 0.4 billion tons in 2050, which is still about 1 billion moretons of GHG emissions in 2050 relative to year 2000 levels. Thus,uncoupled from a simultaneous transition to renewables and
ARTICLE IN PRESS
Enhanced metafile
4BOSTON 2000 4BOSTON 2010 4BOSTON 2020
4BOSTON 2030 4BOSTON 2040 4BOSTON 2050
Fig. 9. Boston metropolitan area hydrogen transition spatial summary for the BAU+H2 scenario, 2000–2050.
W. Dougherty et al. / Energy Policy 37 (2009) 56–6766
efficiency, the hydrogen transition alone does not put us on atrajectory of ambitious GHG reductions.
Hydrogen may represent a ‘‘step backward’’ in the early years in
both the BAU+H2 and GHG+H2 scenarios, in terms of GHG emissions.Near-term hydrogen supply options have disbenefits because theyrely on on-site production (electrolysis and natural gas reform-ing), and thus the ultimate energy sources are mostly fossil fuelbased. Long-term hydrogen supply options, which are able to yieldthe GHG benefits that make hydrogen attractive, are all centra-lized options that arise later in the transition.
A coordinated shift toward hydrogen that avoids serious economic
disruption would likely entail a several decades transition. In theBAU+H2 and GHG+H2 scenarios modeled, the hydrogen transitiongradually unfolds over the course of roughly 50 years. There areseveral reasons why a transition could require at least this amountof time, and perhaps more. Fundamental aspects of a hydrogensystem are awaiting R&D advancements in achieving cost-effectiveness and performance targets. Stock turnover in theexisting energy and vehicle infrastructure imparts a considerableamount of inertia. The chicken-and-egg problems intrinsic in thetransformation of the energy system call for a staged andinherently slower approach. If, however, the demands of anincreasingly urgent climate crisis and the limits of oil resourcesrequire quicker action, and a more rapid transition is possible asdemonstrated in the Shock+H2 scenario. The costs are higher, buta successful transition is technically feasible.
Finally, a hydrogen transition will not happen ‘‘spontaneously’’: it
demands a coherent national effort. For both the BAU+H2 andGHG+H2 scenarios, overcoming the lock-in inherent in currentenergy infrastructure based on petroleum, natural gas, and coalrequires substantial investments in new infrastructure andtechnology. Moreover, the chicken-and-egg difficulty associatedwith simultaneously building up a hydrogen fueling infrastructurewhile expanding hydrogen demand leads to a considerable ‘‘firstmover’’ problem. A transition to hydrogen will require concertedpolicy interventions on the grounds of environmental and energysecurity objectives, and cannot be expected to arise from market-driven investments alone.
Without a coherent national strategy whose objective is tofoster an orderly shift away from conventional energy carriers and
toward hydrogen, it is implausible to consider that markets willspontaneously transform and that a hydrogen transition willhappen. A coherent national transition strategy would have toinclude sustained investments in R&D specifically identifyingniche applications, targeting incentives for centrally fueled fleetvehicles and dual-fueled ICEVs, developing several transitionaltechnologies, and incentivizing hydrogen demand to attack thechicken-and-egg problem, ensuring policy consistency acrosssectors such that the current fossil-fuel infrastructure is graduallydisplaced by new H2 infrastructure.
Acknowledgments
The authors were supported by funding from the NationalRenewable Energy Laboratory (NREL) under Subcontract no. LDZ-2-32066. Any opinions, findings, and conclusions expressed in thispublication are those of the authors and do not necessarily reflectthe views of NREL.
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