Energy Policy 32 (2004) 1231–1242

Hydrogen from renewable resources—the hundred yearcommitment$

Kerry-Ann Adamson*

Institute for Energietechnik, Fuel Cell and Hydrogen Research Centre, Technical University of Berlin, Energy Systems, Sekr. TA8, Einsteinufer 25,

10587 Berlin, Germany

Abstract

During the last decade interest in a potential ‘Hydrogen Economy’ has increased and is now discussed in main stream literature

and political debates. This is largely due to the promise that fuel cell technology, which uses a hydrogen-rich gas, has shown. Though

hydrogen can be produced from a number of sources, it is steam reforming of natural gas that has gained a substantial support base,

and is seen as an important bridge to a sustainable hydrogen production from renewable energy. What this paper examines is the

synergy that exists now between hydrogen from renewable resources and the inception of the fuel cell market. It argues that

although the natural gas pathway will be necessary for the short to medium term, there should not be a complete dominance of the

production route. The paper also brings together a number of policy documents from the EU and argues that what is needed from

the level of the EU is a long term, binding commitment to ensure that the natural gas pathway does not become locked in.

r 2003 Elsevier Science Ltd. All rights reserved.

Keywords: Hydrogen; Natural gas; Renewables

1. Introduction

Energy that can be produced and used, whichdecreases the environmental footprint, that helps toaddress the challenge of sustainable development whilstenabling economic growth, is the goal of a number ofgroups in modern society. Nuclear power has so farfailed to live up to its initial promise of providing acheap, clean nuclear economy (Bupp and Deian, 1981;Cohn, 1997) and more traditional systems of powergeneration such as coal fired power plants and extensiveuse of crude oil products have come under increasingcriticism for their use of nonrenewable resources andpollution of the local and global environment. (Elliott,1997).Over the past 30 years, interest has been increasing in

the potential use of hydrogen as an energy carrier.Hydrogen, which must first be produced, can be used ina number of technological applications, but it was not

until the last 10 years when technology such as fuel cellsbegan to show real promise, that the idea of a hydrogen-based economy started to gain mainstream interest. Thebenefits of a shift to a post-fossil fuel hydrogen-basedeconomy, are well documented in published and greyliterature (Winter, 2000; Hoffman, 2001; Siblerud,2001). Though discussions still abound concerningabsolute levels the three main potential benefits are:

(a) diversification of energy production and security ofsupply,

(b) decrease in urban pollution,(c) decrease in greenhouse gas emissions.

Fuel cells, an enabling technology, have high efficien-cies and potentially substantially lower negative extern-alities than current energy systems, which has madethem an attractive future option in micro, stationary,and automotive applications.Stationary applications for fuel cells are commonly

split in scale to either microapplications, such asproducing power for laptops or mobile phones, or smallto large scale for distributed, or grid connected powergeneration. Small-scale systems for distributed energygeneration, could be used as back up generators forhospitals, or primary applications for Polar bases and

ARTICLE IN PRESS

$This paper is drawn from the project ‘Timing and Socio-Economic

Impacts of Fuel Cell vehicles’ which is funded by a Marie Curie

Research Fellowship, MCFI-2000-01421.

*Corresponding author. Tel.: +49-314-79123; fax: +49-314-26908.

E-mail address: kerry-ann.adamson@tu-berlin.de

(K.-A. Adamson).

0301-4215/03/$ - see front matter r 2003 Elsevier Science Ltd. All rights reserved.

doi:10.1016/S0301-4215(03)00094-6

more exotically the proposed NASA moon base.Current systems in development range from 1kW unitsfor single family homes (Sulzer Hexis, 2001) to mid-scalesystems (Plug Power, 2001) who, in conjunction withGeneral Electric, intend to market and distribute their7 kW residential systems as soon as they deem thetechnology to be commercially viable. The AmericanFuel Cell Corporation (Barlow, 1999) have also devel-oped a residential system of 10 kW. Alstom at the otherend of the scale produced a unit of 250 kW for large-scale power generation (Alstom, 2001). These systemsoperate with an electric efficiency of between 30% and40% and are being developed in a packaged unit withfuel reformers (Barlow, 1999).Though stationary applications are a highly valuable

and important aspects in the fuel cell portfolio, it is thefuel cell electric vehicle, more commonly known as thefuel cell vehicle (FCV) that has so far created themajority of interest. The fuel cell in an FCV replaces theinternal combustion engine as the primary propulsionunit, producing electricity for vehicle traction. All majorautomotive manufacturers have, or have had, fuel celldevelopment programs. Of these only BMW have beenlooking into the possibility of using fuel cells asAuxiliary Power Units whilst the majority of theresearch has been on fuel cells being the primary powerunits. It should be noted though that BMW have had along standing program of research in using hydrogendirectly in an internal combustion engine and areplanning on releasing into the market place a fleet ofhydrogen fuelled seven Series vehicles.Though there are currently a number of questions

surrounding the timing of mass market commercialisa-tion of light duty FCVs, the next few years will see, inEurope, the launch of a number of limited size test fleets.Two high-profile examples are the Clean UrbanTransportation for Europe (CUTE) project and CleanEnergy Partnership Berlin. The project CUTE will havea fleet of 30 fuel cell buses in 10 European cities. TheClean Energy Partnership Berlin will see a small fleet, inBerlin, of over 30 vehicles, a mix of cars and buses, indaily use from 2004.To operate fuel cells currently need hydrogen-rich

gas.1 Today, there appears to be amongst the energyproviders and some of the automotive industry anemerging consensus that if the FCV uses directhydrogen, i.e. not reformed on board from methanolor gasoline, then this hydrogen production will be fromsteam reforming of natural gas (GM, 2001; Barlow,1999). This is seen as a possible ‘stepping stone’ to a

future hydrogen economy based on hydrogen fromrenewable energy. The timing of any future renewablehydrogen-based economy is not a realistic short-termoption but what this paper examines is the political issueof the production of hydrogen from renewables in anEuropean context. It suggests that not only may it bepossible for renewables to provide an important fractionof hydrogen from the inception of a commercial fuel cellmarket but by doing this it creates a number of positivebenefits and also, importantly, potentially provides a‘bridging market’ for large-scale commercialisation ofrenewable energy for the electricity market.The rest of this paper examines renewable energy, in

particular solar and wind, as future pathways forhydrogen production and discusses the benefits of thesesystems for the early adopters of the fuel cell market.The discussion section of the paper looks at the policyimplications of reliance on one pathway and argues for a‘100 year commitment’ to clean hydrogen from theEuropean Union.

2. Hydrogen production techniques

The production of hydrogen can be split into threemain groups, photobiological, photoelectrochemicaland thermochemical (Sandia National Laboratories,1995), with current large, industrial, scale productionof hydrogen taking place at oil refineries to be used as ablend for improving the gasoline output (Ogden et al.,1996).

2.1. Natural gas

Steam reforming of natural gas is a well-understoodprocess that is being used in existing commercial plants.Methane, in the natural gas, reacts with water toproduce carbon monoxide and hydrogen. The carbonmonoxide is put through a water–gas shift reactionwhere it combines with water to produce hydrogen andcarbon dioxide (Larson and Katofsky, 1992). Larson(1992) suggests a thermal efficiency of 84.8% for a750MW NG to Hydrogen plant. Assuming a 95%operation time and using the HHV of Natural Gas as37.3MJ/m3 this plant could produce around 133,807tonnes of hydrogen per annum.Economically, the costs of steam reforming of natural

gas are heavily dependent on the cost of the feedstock.Between 52% and 68% of the overall costs of hydrogenproduction can come from the cost of the natural gas(Basye and Swaminathan, 1997).

2.2. Electrolysis of electricity

Hydrogen is also produced by electrolysis of water.The system uses an electrolyser powered by electricity.

ARTICLE IN PRESS

1There is a Direct Methanol Fuel Cell being developed which uses

methanol as its input but that will not be discussed further here. For

stationary applications, high-temperature fuel cells (solid oxide fuel

cells, for example) are developed that may directly use natural gas or

heating oil.

K.-A. Adamson / Energy Policy 32 (2004) 1231–12421232

The required electricity may come from conventionalpower plants, such as coal or nuclear, but can also userenewable energy resources such as wind, solar thermal,PV and hydropower.The efficiencies of the hydrogen conversion process

are heavily dependent on the efficiency of the electricityproduction process. This can range from 11.5%efficiency for PV arrays (Vidueira et al., 2003) to alarge-scale coal power plant which has an electricalefficiency of 42% (World Energy Council, 2001). Thesecond step in the system, the electrolyser, has anefficiency depending on the level of use.

2.2.1. The Electrolyser

Though electrolysers are known technology, linkingthem into this renewable system to produce hydrogen atany large scale is still pretty much at the level ofdemonstration projects. A large hurdle for producinghydrogen from renewable energy is the issue ofintermittence of the supply. The majority of thesetechnologies have no form of energy storage, powertowers and solar trough technology being two excep-tions; therefore, energy supply to the electrolyser will beintermittent in line with the energy supply. An Italian,EU funded project (which appears, uniquely for EUprojects, not to have a project acronym) has been set upto test the technological problem with the electrolyser ofintermittent wind energy (Dutton et al., 2000). Duttonet al. (2000) reported a drop of efficiency, throughintermittent supply of 2.3% to 62.7% from 65%efficiency for a 2.5MWe electrolyser. Though the resultsindicate that in the short term the intermittence ofsupply does not have dramatic effects on the technicalperformance of the electrolyser, they raised concernsover costs (the capacity utilisation depends on theavailability of renewable electricity) and long-term use.Companies such as Stuart Energy and Vandenborre,which has just been bought by Stuart Energy, bothproduce units that can accommodate, initially, verysmall-scale requirements and have a modular designwhich can be quickly scaled up. Stuart Energy has twosmall-scale designs, its ‘Personal Fuel Appliance’ isdesigned to run on household current and fills the tankof a hydrogen car over night, whilst its ‘CommunityFueler’ is a fully modular design that starts with anability to produce hydrogen for five cars but can bescaled up to any requirement (Stuart Energy, 2002a, b).Vandenborre’s H2 IGEN, which runs on DC current,again is a modular design which can be scaled up fromvery small-scale requirements (Vandenborre, 2002).Both these companies’ electrolysers produce hydrogengas at various levels of pressure, depending on therequirements of the consumer. A problem with small-scale infrastructure is economics. Though Stuart havestated that the Personal Fuel Appliance will be‘affordable’ (Stuart Energy, 2002a, b), there is currently

no information available on what the cost of the systemwould be. Currently the economics of the situation, ashighlighted below, are such that the larger units aremore cost effective. What is known is that, as with othertechnologies, economies of scale play a large role, but weseem to face a technology that is exhibiting signs offorming a technological trajectory with associateddownward curve in costs. Dutton et al. (2000) highlightsmanufacturers’ beliefs that the price of a 100 kWe unitcould drop from 5050 to 4100Euro/kWe, whilst a1MWe unit price is thought to drop from 2250 to1900Euro/kWe in the future. Plans for an industrial-scale 20MWe electrolyser are expected to cost around680Euro/kWe.The economics of producing hydrogen from green

electricity and electrolysers under current technologicaland accounting systems appear bleak. As with NaturalGas the cost of hydrogen production relies heavily onthe cost of the feedstock. When using the so called‘green’ electricity this reliance is the highest of the threepathways discussed here. A recent survey by Basye andSwaminathan (1997) of hydrogen costs from varioussources suggests that the cost of electricity was 80% ofthe overall production cost of hydrogen, rising to 85% ifthe electricity produced is from Solar PVs.

2.3. Biomass

Biomass may be converted to hydrogen through theelectrolysis path by using electricity from biomasspower plants. But, besides wind, wave and solar,hydrogen may also be produced directly in a gasificationprocess.Two important factors in assessing the future

potential of biomass for hydrogen production are theyield per hectare and the energy content of the cropunder consideration. These vary widely from Cornwhich has an energy content of 18.5MJ/kg and yieldper hectare of 7.1 t/ha, from Sorghum, which though hasa similar energy content of 18.2MJ/kg, has a per hectareyield of 80 t/ha, some factor of 11 greater (Dreier, 2000).An average of 19 European crops, gives an yield perhectare of 8 t/ha with an energy yield of 18MJ/kg.Before the gasification process the biomass needs to beprocessed, which mainly involves drying. The averagemoisture content of biomass is 45%, and typicallyprocessing and drying leads to a loss of 10% of theenergy content (Katofsky, 1993). The average realisedefficiency of the biomass to hydrogen gasifier is 63%(DeLuchi et al., 1991).Economically, among the three systems discussed here

it is biomass that has the lowest dependence, for overallproduction costs, on the cost of the feedstock: between25% and 30% (Katofsky, 1993), with the remainderattributed to costs of plant and operation and main-tenance costs.

ARTICLE IN PRESSK.-A. Adamson / Energy Policy 32 (2004) 1231–1242 1233

Currently, there exists in Europe no commercialproduction of hydrogen from renewable resources. Overthe past 15 years, there have been numerous projects setup to assess the feasibility of producing hydrogen fromrenewable sources. These studies include:

1. The ‘Euro-Qubec Hydro-Hydrogen Pilot Project’ toanalyse the feasibility of large-scale production ofhydrogen with long-distance transportation (Wur-ster and Malo, 1990).

2. The ‘Stand Alone Photovoltaic-Hydrogen PowerSystem’ project which utilised solar PV to producehydrogen, for use in fuel cells in distributedgenerating capacities (Galli and Stefanoni, 1997).

3. The already mentioned wind to hydrogen project toascertain the problems caused by intermittentsupply on the electrolyser efficiency (Dutton et al.,2000).

4. The ‘Photovoltaic Electrolyser Fuel Cell andTechnical Systems’ at Forschungszentrum J .ulichwhich used a built-in hybrid wind and solar systemfor hydrogen production and use in a fuel cell.(Meurer et al., 1999).

What these, and numerous other projects, have incommon is that they show that there does exist thetechnical feasibility to produce hydrogen, reliably and inthe quantities needed, from a wind or solar pathway.2

3. Energy trends and current fuel infrastructure

Historic and projected energy trends across Europeshow a steady, slow, increase in energy demand acrossEurope. Fig. 1 shows the EU’s own energy demandprojections, for the EU15, from the Shared AnalysisProject. (EC, 1999a, b). Figs. 2 and 3 highlight thesubstantial difference between EU countries, here theexamples are the UK and Greece. Note, here thecategories ‘other’ includes coal and renewables.

3.1. Energy trends

What these graphs highlight is the projected medium-term sustained reliance on oil, some 44% of final energydemand over the EU15 in 2020. The EU15 areprojecting by 2020 an extra demand of over 100 MillionTonnes of Oil Equivalent (Mtoe), over 1990 levels. TheUK’s ‘dash to gas’ is predicted to level off, whereas inGreece by 2020, approximately 60% of the total energydemand is expected to be met by oil and another 24% byelectricity. What is unclear from these projections is thelevel of renewables in the system, as these are covered in

‘electricity’, alongside nuclear and thermal. The EU’s1997 White Paper ‘Energy for the Future: RenewableSources of Energy’ (Com(97)599) sets out the policy for12% of all energy demand to come from renewables by2010 (EC, 1997). If this target is to be met then using the2020 projections, renewables will need to produce by2020 holding at 12%, 222Mtoe, some 2650TWh ofpower.To put this information in context, Figs. 4–9 show the

historic and projected energy requirement of differentindustries. The data are repeated for the EU15, UK andGreece.The main point to take away from these is the

projected increase in demand, in absolute terms, from

ARTICLE IN PRESS

0

100

200

300

400

500

600

1990 1995 2000 2005 2010 2015 2020

Mto

e

Gas Oil Electricity Other

Fig. 1. EU15 historic and projected final energy demand by fuel type.

0

20

40

60

80

1990 1995 2000 2005 2010 2015 2020

Mto

e

Gas Oil Electricity Other

Fig. 2. UK historic and projected final energy demand by fuel type.

0

5

10

15

20

1990 1995 2000 2005 2010 2015 2020

Mto

e

Gas Oil Electricity Other

Fig. 3. Greece historic and projected final energy demand by fuel type.

2The projects above are in no means an exclusive list. Information

and details of a range of other examples can be found at:

www.eren.doe.gov/hydrogen/iea/iea publications.htm.

K.-A. Adamson / Energy Policy 32 (2004) 1231–12421234

the transportation sector, whereas the demand fromindustry3 is decreasing. The implications of theseprojections will be returned to later in the paper. 3.1.1. Import and export dependency

Although the EU15 has 2.2% of the World’s ProvenReserves of natural gas, it already imports 145BCF(billion cubic feet) per year, mainly from The Russian

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EU Energy Demand by Sector (1990)

30%

27%13%

30%

Industry Residential Tertiary Transport

Fig. 4. EU energy demand by sector, 1990.

EU Energy Demand by Sector (2020)

26%

25%16%

33%

Industry Residential Tertiary Transport

Fig. 5. EU energy demand by sector, 2020.

UK Energy Demand by Sector(1990)

25%

31%11%

33%

Industry Residential Tertiary Transport

Fig. 6. UK energy demand by sector, 1990.

UK Energy Demand by Sector(1990)

25%

31%11%

33%

Industry Residential Tertiary Transport

Fig. 7. UK energy demand by sector, 2020.

Greece Energy Demand by Sector(1990)

31%

10%

13%

46%

Industry Residential Tertiary Transport

Fig. 8. Greece energy demand by sector, 1990.

Greece Energy Demand by Sector(2020)

22%

6%

23%

49%

Industry Residential Tertiary Transport

Fig. 9. Greece energy demand by sector, 2020.

3Here industry covers metals, chemicals ‘other energy intensive

industries’ and ‘other industrial sectors’.

K.-A. Adamson / Energy Policy 32 (2004) 1231–1242 1235

Federation. Currently, the import dependency fornatural gas alone is 40% and this is expected to increaseby 2020 from the current EU15 lead to over 67%. Twoof the largest energy providers within the current EU,Denmark and the UK, are both expected to becomeenergy importers by 2020, Denmark heavily so, over60% in the EU energy scenario. The EU have modelledthe effect of enlargement to the EU30 on the energyportfolio (European Union, 1999). For natural gas, thestudy expects the overall energy import dependency by2020 to be similar to that of the EU15 at over 60%. Themajority of proven natural gas reserves lies in twodiverse locations, The Russian Federation and Iran.They have 30.7% and 14.8% of world reserves,respectively (BP, 2002a, b) and as Table 1 indicates theRussian Federation already exports 126.86 BCF an-nually. Netherlands, Europe’s largest exporter, exports36.4 BCF annually but it has been mentioned that thisenergy independence is predicted to change drastically.

3.2. The current energy infrastructure

The current fuel infrastructure, within Europe, reliesheavily on large centralised systems. For example, theUK has just 11 oil refineries, which have a combinedcapacity throughput of 1769 thousand barrels daily, tocope with demand, (BP, 2002a, b), and over 55% of theUK’s electricity is supplied by only 17 nuclear powerplants and 28CCGT (combined cycle gas turbines)plants. The working life of these large-scale plants,nuclear 30–40 years, coal 40 years and CCGT 30 years(ExternE, 1997a, b, c, d), (Vols. 3–5), combined withtheir construction dates, provide some indication of howlocked in we are to the current paradigm of energyinfrastructure.We know, for example, that in Germany due to the

legislation to close down all nuclear power plants at theend of their working life and not to commission any newones, known as the ‘Atomausstieg’, within the next 20

years, 50% of the current electricity demand will have tobe replaced by other sources.Across the EU15, many of the current nuclear plants

were commissioned in the 60s and 70s, indicating agingplants. When this is coupled with the current feelingagainst nuclear and the desire to move away from such aheavy reliance on fossil energy, we may be facing awindow of opportunity to move away from the currentparadigm of large-scale centralised systems of energyproduction to more modular, flexible energy pathways.

4. Switching to a hydrogen economy

4.1. Infrastructure for the market introduction of fuel

cells

If the market accepts fuel cell technology, it willrequire hydrogen production and, potentially, transpor-tation. As already shown we have, technically, a numberof options to produce the hydrogen and options fortransportation are no different from current energysources, such as shipping, pipelines and tankering.What is commonly referred to as the Chicken and Egg

problem, of what do we put in first, a fuel infrastructurefor a product that does not yet exist in the market place,or wait to see if the consumer will accept a product withvery low levels of refuelling infrastructure is seen as oneof the three4 main stumbling blocks to any future fuelcell market. There is an argument, though, that we arelooking at the problem from the viewpoint of thecurrent paradigm, large-scale centralisation of powergeneration and distribution. A study in the US wasundertaken to determine what the current hydrogenproduction capacity was and what level, if any, surpluscapacity existed which could, in theory, be used in the

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Table 1

Natural gas statistics from the five producers in the eu15 and the Russian federation

Reserves (tcf) Share of world

total (%)

Production

(mtoe)

Consumption

(mtoe)

Imports (BCF) 2000 overall

import

dependency (%)

2020 overall

import

dependency (%)

Germany 0.34 0.2 15.3 74.6 78.75 61.2 72.6

UK 0.73 0.5 95.2 85.9 2.70 �19.3 26

Netherlands 1.77 1.1 55.2 35.3 13.13 21.1 53

Italy 0.23 0.1 13.9 58 49.55 85.1 92.2

Denmark 0.08 o0.05 7.5 4.6 — �12 61.2

EU15 3.21 2.1 191.6 343.3 211.06 47.6 63.4

Russian Fed. 47.57 30.7 488.2 335.4 126.86 (export)

1-year 2001.

NB 1 trillion cubic feet of natural gas=26 Million Tonnes of oil equivalent.

Source: BP (2002a, b).

4The other two barriers are economics—fuel cell technology, for

light duty vehicles, is still prohibitively expensive, and hydrogen

storage, again, for vehicle applications.

K.-A. Adamson / Energy Policy 32 (2004) 1231–12421236

fledging hydrogen economy. The results indicated thatthere already exists the capacity, in the US, to produceenough hydrogen to sustain any new market for anumber of years to come (Padro, 2002).The issue exists, though, that outside of the test fleets

in cities such as Berlin, London and Copenhagen theadoption of fuel cells and their inherent requirement forfuel will not necessarily be geographically concentrated.Rogers’ (1995) work in adoption categories and adoptertypes of new technology shows that the group ‘In-novators’, which normally represent the first 2.5% ofadopters, are not necessarily geographically close. Forstationary applications, the initial fuel cell market willmost likely occur in areas or regions with lack of accessto grid electricity. In these situations, the premium forelectricity, heat and water generated by the firstgeneration of commercially available fuel cells may belower than the cost of extending the grid network. Ruraland island communities and isolated homes and farmscould be the niche market, and provide the ‘innovators’of adoption. We therefore face the strong potential for avery distributed early market for fuel cells and, byimplication, hydrogen. This could be seen to furtherexacerbate the problem of fuel infrastructure, or, it canbe seen as an argument for small-scale modulardevelopment of infrastructure.Using technical data available from the developers of

products, remembering the adage that consumers buyproducts not technology, some first-order approxima-tions can be produced on the level of requirement ofhydrogen per product adoption per year. The twoproducts that were modelled were FCVs, using specifi-cally the technical data from the 2001 General Motorsfuel cell ‘Zafira’ (GM, 2001) and two stationary systemsdesigned for residential use. The systems modelled arethe Plug Power 7 kW System and the American FuelCell Corporation 10 kW system.For the Zafira, equipped with a 80 kW PEM fuel cell

and the assumption of a yearly driving distance of16,100 km, it was calculated that 29GJ of Hydrogen willbe required per vehicle per year. Note that this is basedon the implicit, and incorrect, assumption that thistechnology will stand still. Though the learning curvefor fuel cell technology is still high, working with thisconstant figure of 29GJ provides a useful upper bound.For the stationary applications assuming that the

system is run 6200 h/pa, approximately 17 h/day, withan efficiency of 35%, which is middle of the currentrange, indicates that an average unit will need 151 and201GJ/pa, of hydrogen for the 7 and 10 kW, respec-tively.What can be seen from this is that the stationary

applications require substantially more amount ofhydrogen than the mobile applications and what alsoneeds to be kept in mind is that stationary applicationscould require a different distribution system.

Based on this requirement of 29GJ/pa for FCVs and201GJ/pa for a 10 kW, we can now assess the energyrequirements, both from renewable, here wind and solarand natural gas, that these systems would require.Starting with the renewable to hydrogen pathway, we

need to analyse the electricity requirement by theelectrolyser to produce the hydrogen. Using the averageelectrolyser efficiency of 65%, even though this could beseen as conservative as market ready models haveefficiencies upto 90% (Vandenborre, 2002), this trans-lates into a required renewable electricity generation of12MWh/pa for each vehicle and approximately86MWh/pa per stationary unit. These figures, of course,need to be put into some technological and availabilitycontext.Offshore wind development has encouraged the

development of superturbines. These megawatt turbineswhen placed off-shore have a number of advantages totheir on-shore equivalents, such as the decrease in visualintrusion and noise pollution off-shore. Wind farms canproduce wind energy in the range of 45–100MW(Border Wind, 1998). Working with a high loadingfactor of 0.75, i.e. representing the possibility of therebeing enough wind off-shore to generate power 75% ofthe time, a single 1.5MW turbine could produce, iflinked to this hypothetical electrolyser system, enoughhydrogen for 262 FCVs per annum or 38 fuel cell homes(FCHs) per annum. If this loading factor was droppedto 40% then the amount of energy produced would beenough to produce hydrogen to power 140 vehicles or 20houses. This and the other modelled technologies aretabulated below to allow at a glance to see in context thesize of the systems that could generate hydrogen for anypotential future fuel cell market.For discussion purposes, the data were run with the

drop in transmission losses for off-shore wind to 8.7%.For the 1.5MW system, the number of FCVs that couldbe powered would increase from 140 to 233 and thenumber of FCHs from 20 to 34.Using the same technical information, we can produce

discussion figures on the levels of requirements fornatural gas to provide enough hydrogen, throughgasification, to power our FCV and FCH. As can bederived from Table 2, one FCV per annum, wouldrequire 1005m3 of Natural Gas and 1� 10 kW FCHwould require approximately 11,000m3 of Natural Gasper annum.Again all figures need to be put into some form of

context of resource availability. If we assume that ourFCH also has an FCV, then per annum they would needa combined 230GJ of hydrogen or 98MWh/pa ofelectricity. Is this realistic from today’s solar PV?Assuming we can purchase an off-the-shelf solar modulesuch as that produced by BP (2002b) comprising PVcells each of 170W range, in countries such as Spain andGreece where the solar irradiance is high, we can

ARTICLE IN PRESSK.-A. Adamson / Energy Policy 32 (2004) 1231–1242 1237

produce enough electricity from 383 single PV modules,using an average daily irradiance of 4.57. The surfacearea needed can be calculated from the dimensions of asingle module—1593mm high and 790mm wide. Whatcan be seen from this is that although technicallyfeasible today, as the average roof can have a surfacearea of around 100m2, the land use, and or constructionproblems, may be an issue.The main reason that so far in this paper off-shore

wind developments have been primarily considered isthat often on-shore developments come across someresistance through the planning process. If this can beovercome, there are currently on the market a numberof ‘microturbines’, single unit turbines with low-to-medium output (Sagrillo, 1998) that could very usefullybe adopted into a hybrid system with the PV, or inplaces where Solar PV is not energetically attractive,they could be used to provide primary power to theelectrolyser.All the new technologies undergo periods of improve-

ments in efficiencies especially early on in their devel-opment. Solar PV, Wind and Fuel Cells are three suchtechnologies which are still on a learning curve. Table 3shows the efficiencies that have been used in the paperand the published possible or theoretical maximumefficiencies of solar PV, wind turbines, electrolysers, fuelcells and grid connections for off-shore wind.What this shows is that in some cases for some of the

technologies, the figures produced here are on theconservative side, but what is important is that all thepieces of this puzzle are, or will be in short-term future,available off the shelf.

4.2. Economics

As discussed in Section 2 on Hydrogen ProductionTechniques, the cost of producing hydrogen fromnatural gas or renewable energy is very heavilydependent on the cost of the feedstock. This can rangefrom 52% to 68% for natural gas, to 85% for solar PVand Braun (2003) states that hydrogen from large-scalewind energy can be up to 10 times cheaper thanhydrogen from solar PV, even though this appears tobe from on-shore wind turbines. What these overallfigures mask is the relative price changes from theprimary energy sources. In black and white terms theprice of natural gas is going up, especially in the US

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Table 2

Size of fuel cell market potentially covered by renewable systems

Technology Capacity (MW) Power output (GWh/a) No. of FCVs powered per

annumaNo. of FCHs powered per

annuma

Solar PVb 1 0.4 33 5

3.3 1.3 108 16

5 2 163 24

Offshore windc 1.5 1.8 140 20

15 17 1400 202

45 52 4199 606

Microturbinesd 0.02 0.039 3 0

0.04 0.077 6 1

0.06 0.116 9 1

For comparison: natural

gas

250 2081 221,901 30,549

500 4161 443,903 61,099

750 6242 665,704 91,648

aUsing an electrolyser with 65% efficiency.bHere the assumed efficiency of the PV cells are 14% and uses a loading of 0.33, representing useful sunshine 8 h/day.cFor wind, the combined efficiency of turbine to shore is used as 33%, which assumes transmission losses of 45%, note that these losses are

expected to drop by 2010 to 8.7% (Martander (2002)). The loading is 0.4.dThis represents a microturbine with a rated output of 20 kilo, loading of 0.4 and efficiency of 0.55.

Table 3

Used and possible/maximum theoretical efficiencies for energy

technologies

Technology Used in

paper

Possible/

maximum

Notes

Solar PV 14 33a Theoretical maximum

Wind 59.3 59.3b Theoretical maximum

Fuel cells 35 68c Theoretical maximum

(for PEM)

Electrolysers 63 90d Close to market ready

with 90%

Grid

connectors

45.8 8.7b Predicted

aPV Power (2001).bMartander (2002).cKreith and Hoogers (2002).dVandenborre (2002).

K.-A. Adamson / Energy Policy 32 (2004) 1231–12421238

where concerns are growing over another natural gascrisis (Foresight Weather, 2003), and the price ofelectricity from renewables is going down.Natural gas prices have historically been more stable

than the oil prices, as shown in Fig. 10, even though the2001/2002 winter in the US saw natural gas price rise of400% (Pittsburgh Business Times, 2001).Between 1985 and 1997, the price of natural gas in

the EU varied between 2.28 euros million Btu, in 1989,up to a peak of 4.12 euros million Btu in 1985, and 1.65euros per million Btu in 1997 (BP, 1999). This compareswith an oil price during this period of between 2.83 and5.22 euros per million Btu (BP, 1999). As has beendiscussed, this period saw a rapid expansion in Europeof the use of natural gas in Gas Fired Power Plants, Co-Generation and direct use in the home for heating andcooking. Future forecasts of the price of natural gasvary widely. For example, the American Energy Agencyactually predicts a decrease by 2010 in euros million Btufrom today’s US price of 5.27 euros million Btu to 3.31euros million Btu (Canadian Energy Research Institute,1999). The other extreme is the DRI who predicts anincrease over the base case of 2.44 euros million Btu in1995 by between 16% and 169% (Canadian EnergyResearch Institute, 1999). Due to the reliance of theoverall cost of hydrogen, from any feedstock, priceincreases can have a significant impact. For natural gasto hydrogen, a 1% increase in the cost of the feedstocktranslates into an overall cost increase of 0.6%. If theprice increases stay small and incremental, say forexample, a 1.9% increase per annum, than theCalifornia Energy Commission (1998) forecasts, thenthe increase in the price of hydrogen may stay in linewith inflation but if there are price hikes similar tothose experienced in the US during the Winter of 2000/2001 or similar to those of the 1970s oil crises, then thiscould easily cause a significant problem for the energymarket.

On the other side of the coin, renewable energies arestill experiencing high rates of learning with associatedinclinations in experience curves, and cost reductions.Experience curves are usually measured in cost

reductions as a function of installed capacity, so initself is not a measure of the improvement of thetechnology. In general, new technologies experiencehigher effects from the experience curves than olderones. Because the rate of cost reduction is based on thevariable of cumulative installed capacity, the higher theinstalled capacity the shorter the time for ‘breakeven’. Inthis case breakeven for renewables for electricitygeneration for grid applications would be when the costbecomes equal to the cost of the modern fossil firedelectricity plants, which, according to the IEA (2000), isat a level of 0.43’s/kWh. In the case of breakeven forhydrogen production the cost of the electrolyser plus theenergy pathway will reach breakeven when this costequals the cost of petroleum. Based on a number ofassumptions of variables such as market penetrationrates and level of conversion efficiencies, a number ofcalculations can be performed to give an idea of theeffect of renewably produced hydrogen on the experi-ence curve of renewable technologies.The EU’s scenario that is foreseen, to reach the 12%

renewable energy by 2010, is an increase in use ofBiomass for electricity generation to 134.8Mtoe by2010, up from the 1997 level of 44.8Mtoe, large-scaleHydropower to only increase by 8500MW, due to thealready installed use of most available locations, Windto take off substantially and increase to 40GW andSolar PV to 3GW. This combined with other renewablessuch as small-scale hydro and geothermal are hoped tomeet the 2010, 12% target.To obtain an idea of how much effect a hydrogen

market from renewables would affect the price in 2010, amodel was produced using the EU energy data and theabove scenario, combined with the IEA (2000) quoted

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-60

-40

-20

0

20

40

60

80

1984 1986 1988 1990 1992 1994 1996 1998 2000

% price change over 1984 % energy demand change over 1988 % price change over 1984

Natural Gas

Oil

%

4.12 's mBTu

1.65 's mBTu

Fig. 10. Natural gas price change in Europe from 1984 to present day (BP, 2002a, b). Note the prices shown here are c.i.f (cost+insurance+freight).

K.-A. Adamson / Energy Policy 32 (2004) 1231–1242 1239

learning curves for wind and solar PV. This provided thebase case. Then an additional need for wind and PV wasmodelled based on requirements for 500 hydrogen FCVsand 1000 Fuel Cell powered homes, a hypothetical FuelCell village. The current price of wind energy was takenfrom the NFFO (nonfossil fuel obligation) five in theUK. NFFO requires electricity to be purchased by thegrid at a set price from a range of agreed uponrenewable plants. The bid price used here, which is theprice at which the electricity will be available to the grid,for large-scale Wind is 0.043 euro/kWh (ENDS Report,1998). The online version of the ENDS Report (ENDSReport, 1998) notes that this is already close to theelectricity pool price of 0.04 euro/kWh. Due to NFFO inthe UK having no Solar PV projects, there exists no bidprice for PV electricity. The price that was used,1.185 euro/kWh, comes from the published literature(Oliver and Jackson, 2000). The learning curves, whichrepresent the price reduction for each doubling ofinstalled capacity are, currently, 18% for Wind energy(IEA, 2000) and for Solar 18%, which is the industryaverage (Oliver and Jackson, 2000), even though the EUaverage is 35% (IEA, 2000), where modelled. Based onthe penetration rates outlined in the EU scenario by2010, the cost of Wind energy, if it carries on at the samelearning curve level, is predicted to fall to 0.03 euro/kWh, and solar, with an 18% learning curve, 0.5 euro/kWh. The effect of the hypothetical extra requirementsfor hydrogen production leads to an insignificant dropin price for wind but, for solar the price drops to0.498 euro/kWh. What these figures indicate is thatalthough the impact per ‘village’ is low there is animpact on the price and that if any substantial marketbuilds up this will create a positive impact on the priceof renewable electricity. It should be noted that the onefuel cell village scenario that was modelled could beclaimed to be on the conservative side, as for example,Newcastle-upon-Tyne in the North of England, a citywith some 11,900 households and over 69,000 vehicleshas stated its intent to become carbon neutral. To dothis it plans to adopt, amongst other technologies,fuel cells.5

It must be noted here that there are a number ofpublished studies (Ogden et al., 1996; Directed Tech-nologies Inc, 1997; Basye and Swaminathan, 1997) thatsuggest that under certain assumptions, for example,mainly low natural gas prices and sizeable concentratedhydrogen demand, there is an economic argument forinstalling and using small-scale natural gas steammethane reformers. Where it is not the case, that this

current work argues against these studies, it is the casethat has been laid out that any initial consumer-drivenmarket, i.e. not test fleets, will be geographicallydistributed and with its implications on lack ofinfrastructure and lack of an economic argument toput in the medium- to large-scale infrastructure that issuited to the natural gas to hydrogen pathway.

5. Discussion and conclusions—the need for long-term

concrete targets

Hydrogen is currently experiencing a surge of high-profile interest in policy making circles both withinEurope and the United States. President Bush in his2003 State of the Union Address announced a new fuelinitiative to develop technology competence in vehiclesfor hydrogen. Even though this sounds like a step in theright direction, some analysts have published theirconcern that this means continued reliance on fossilfuel to produce the hydrogen, and therefore will not helpto contribute towards any decrease in energy depen-dence in the United States (Gallon, 2003).The UK government has also recently realised a

policy document ‘Powering Future Vehicles: Govern-ment Strategy’ in which hydrogen and fuel cells areexpected to make a significant contribution after 2010(Department of Transport, 2002). The EU meanwhilehas earmarked some 7 million Euros for hydrogen-basedresearch within its 6th Framework Programme, and afurther 7 million for fuel cell research (Fuel Cell Today,2003).What these represent, though, is policy, not legislation

or regulation. Policy can be, and has been in manyareas, altered by newly incoming governments orchanges in regulatory power. The financial communitiesare well aware of the level of risk policy, represents anda prominent European fuel cell investment bankerhighlighted that what they, the financial bankers ofnew technology, need is some form of regulation, whichcannot be altered as easily (Doran, 2002). Regulation orlegislation, as opposed to policy, provides concretesignals of intent and reduces for investors perceived riskwhen investing in a new technology.The EU has over the past 5 years produced a number

of important White papers and action plans which couldhave direct impact on the policy direction of the next 50years, and has, therefore, implications on any future H-FCV market that develops.In terms of direct importance, the papers and

legislation:

1. White Paper—Energy Supply and Diversification2. White Paper—Renewable Energy3. White Paper—Transport Policy for 20104. CAP Agenda 2000

ARTICLE IN PRESS

5As an aside the number of off-shore wind turbines was calculated,

that could supply the total energy needs of Newcastle, assuming all

homes and vehicles were converted to use with fuel cells. Using a

loading of 0.6 and with transmission losses minimised to 7.7%, it was

calculated that it would require 1384.2MW turbines to produce

enough hydrogen per annum.

K.-A. Adamson / Energy Policy 32 (2004) 1231–12421240

5. 6th Environmental Action Plan6. Kyoto and Climate Change Agreement

are of relevance to this debate. Each deals with theneed for a transition of the EU to a more sustainablepath, whilst ensuring the continuing economic andcultural stability of its current and new members.Dependence on, and the unsustainability of, oil use isrecognised and discussed in each document and in most,natural gas is seen as its replacement.The EU has critical reserves of natural gas to facilitate

a change in direction, without leaving them open totallyto the vagaries of the geopolitical situation in Russia aswell as continuing the relationship with the Middle East,but the question is in which direction? Transport, thelargest user of petroleum-based energy, currently faces awindow of opportunity to sow the seeds for a funda-mental transition to a cleaner, more efficient andsustainable path. But this will not happen easily. Theautomotive manufacturers, in conjunction with otherplayers, have the ability, theoretically, to provide atechnology revolution which will enable the first stepsalong this path to be taken. The stationary fuel cellmanufacturers could be providing a means for decen-tralised energy production. Control of energy produc-tion and demand at a local scale, potentially bypassinglarge centralised projects. But both of these possibilitiesneed commitment, targets and management from theEU, as well as development of a market pull. Themarket pull for fuel cells should not be assumed to occurwithout further and extensive work on the sides of boththe industry and government, but this can be achieved.What is critically needed, and is currently missing, is along-term commitment to ensuring that the technologi-cal opportunity that a hydrogen economy, utilisingtechnologies such as fuel cells, presents to the EU, andto the world, is not wasted or worse allows a secondperiod of energy insecurity to be created.Hydrogen and its use in transport is seen in the new

transport white paper as a long-term option behind theuse of natural gas. It makes no distinction betweennatural gas as feedstock for the hydrogen FCVs in themedium term, and hydrogen from renewable resourcesin the long term. This shows either a lack of under-standing of any future hydrogen market or a reluctanceto set down on paper what is needed. However, this isexactly what must be laid down in any paper on energysecurity, energy diversification, transport, environmentand sustainability; that hydrogen from natural gas is animportant bridge, but that hydrogen from renewables isthe goal, for which foundations must be laid at the sametime as the natural gas to hydrogen market. The marketover the next 20 years will be small and highly diversewhich is the benefit of renewable energy. The costs ofhydrogen from renewable resources can only go oneway—down. This may have important physiological

effects on the perceived risk of investing in newtechnology. By ensuring that there exists a renewableenergy to hydrogen pathway from the inception of themarket, there is a prevention of lock-in of a natural gasinfrastructure and manufacturing, and if a futureequivalent energy crisis occurrs, when the price ofnatural gas soars, there would exist in place at least aminimum level of alternative technology with theknowledge base to ensure that it could be scaled up.By artificially ensuring that there exist a market forrenewable hydrogen, make no mistake it will have to beartificially created through tax breaks, subsidies or otherforms of government interventions, then the renewableto hydrogen market could be working on the manu-facturing and building knowledge and techniques thatwould ensure an ability to switch at a given date to amajority renewable base.There is in Germany a saying ‘Jahrhundertaufgabe‘ or

‘A Hundred Year Commitment’, something that needsvision, long-term planning and long-term commitment.If we can secure long-term commitment, with a clearvision, for transition to a sustainable hydrogen econo-my, then we can begin on the long-term planning. Butonly if we can receive these clear signals of intent fromthe European Union we can ensure that a window ofopportunity is not lost.

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