Generation, of the energy carrier HYDROGEN In context ... - needs

NyOrka Page 1 12/18/2008SIXTH FRAMEWORK PROGRAMMEProject no: 502687NEEDSNew Energy Externalities Developments for SustainabilityINTEGRATED PROJECTPriority 6.1: Sustainable Energy Systems and, more specifically,Sub-priority 6.1.3.2.5: Socio-economic tools and concepts for energy strategy.Deliverable n° 8-5 RS1aLife cycle approaches to assess emerging energy technologiesTechnology specification:Generation, of the energy carrierHYDROGENIn context with electricity buffering generationthrough fuel cellsCorresponding author: maria.maack@newenergy.isDue date of deliverable: June 2008Start date of project: 1 September 2004Duration: 48 monthsOrganisation name for this deliverable: Icelandic New EnergyProject co-funded by the European Commission within the Sixth FrameworkProgramme (2002-2006)Dissemination LevelPU Public XPPRestricted to other programme participants (including theCommission Services)RERestricted to a group specified by the consortium(including the Commission Services)

NyOrka Page 2 12/18/2008Specific acronyms ............................................................................................................... 41 Structure ...................................................................................................................... 51.1 The data sources ................................................................................................... 52 Hydrogen..................................................................................................................... 52.1 Methods and pathways for production ................................................................. 62.2 Electrolysis ........................................................................................................... 82.3 Process description of electrolysis ....................................................................... 92.4 Life Cycle Evaluation of the Electrolysis .......................................................... 122.4.1 Material flow data and sources ................................................................... 143 Results ....................................................................................................................... 153.1.1 Key emissions and land use ........................................................................ 153.1.2 Contribution analysis for the main life cycle phases .................................. 163.2 Additional information ....................................................................................... 173.2.1 Spatial disaggregation ................................................................................. 184 Electrolysis technology development pathways ....................................................... 194.1 Hydrogen roadmaps and policy .......................................................................... 214.2 Criteria for hydrogen applications ...................................................................... 234.2.1 Efficency of production .............................................................................. 234.2.2 Quality criteria ............................................................................................ 234.2.3 On site production of hydrogen; grid criteria ............................................. 244.2.4 Quantitative criteria .................................................................................... 264.2.5 Where would the hydrogen come from? ..................................................... 264.2.6 Niche markets ............................................................................................. 274.3 Cost of hydrogen production from two sources ................................................. 294.4 Future scenarios – cost comparison ................................................................... 334.5 Price trends in future .......................................................................................... 354.5.1 The potential role of hydrogen in a future energy supply system ............... 374.5.2 Integrated systems ....................................................................................... 395 Technology development perspectives ..................................................................... 396 Specification of future technology configurations .................................................... 417 Conclusions ............................................................................................................... 428 References ................................................................................................................. 439 Annex ........................................................................................................................ 46

NyOrka Page 3 12/18/2008Figure 1 Overview of energy streams, from source to user phase. Any source of energycan become a source of hydrogen and therefore it may give all regions an opportunity forlocal production and specific local use. .............................................................................. 7Figure 2 A schematic overview of the process flow within the three main types ofelectrolysis .......................................................................................................................... 9Figure 3 An overview of the connected components of an electrolytic fuel station anno2003................................................................................................................................... 11Figure 4 The main life cycle phases of a hydrogen filling station. ................................... 12Figure 5 Main components of an electrolytic hydrogen filling station. ............................ 13Figure 6 Contribution analysis for electrolytic hydrogen production, when using UCTEgrid mix. Refer to figure 7 for comparison with grid mix based on renewable sources. .. 16Figure 7 Comparison of key emissions using UCTE electricity grid and the Icelandicelectricity grid. .................................................................................................................. 17Figure 8 Energy road-maps for the new century predict that fuel types for transport, willcontain gradually less carbon.. .......................................................................................... 19Figure 9 Presentation of the context between hydrogen supply and demand. ................. 20Figure 10 An overview of expected proportion number of hydrogen vehicle penetrationon the world market according to various sources............................................................ 22Figure 11 Hydrogen or electricity by cable? Pathways for hydrogen import to Europehave been mapped by the ‘Encouraged’ project. .............................................................. 27Figure 12 The system setup in Ramea ............................................................................. 28Figure 13 Measured cost of Equipment, site preparation, investment and operation cost(2005) for electrolyser per kg hydrogen; electricity cost = 10 ct/ kWh; Nitrogen cost = 0,5€/ Nm 3 ............................................................................................................................... 31Figure 14 Measured cost of equipment, site preparation, investment and operation cost(2005) for a steam reformer per kg hydrogen – electricity cost = 10 ct/ kWh; natural gascost = 5 ct/ kWh; nitrogen cost = 0,5 €/ Nm 3 . .................................................................. 32Figure 15 Cost burden from hydrogen purfication criteria ............................................... 32Figure 16 Future scenario: Reformer – Electrolyser; cost for electricity set at 0,10 € perkWh ................................................................................................................................... 35Figure 17 Composition of cost factors using projected learning effect but based oncurrent yet upscaled technology. Electrolyser scenario 600 Nm3/h and 170 plants; costper kg hydrogen - electricity cost = 10 ct/ kWh; nitrogen cost = 0,5 €/ Nm3 .................. 36Figure 18 Steam Reformer scenario 600 Nm3/h and 170 plants; cost per kg hydrogen.Electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; N2 cost = 0,5 €/ Nm3, allusing fore .......................................................................................................................... 37Figure 19 A hydrogen test system that is intended to monitor and raise total energyefficiency. .......................................................................................................................... 39

NyOrka Page 4 12/18/2008Table 1 The characteristics of electrolysis units available worldwide ............................. 10Table 2 List of selected electrolytic technology and general configurations .................... 12Table 3 Description of LCA phases .................................................................................. 13Table 4 Parameters for the studied hydrogen production facilities in current situation. .. 13Table 5 Material and energy flows allocated to the production of current electrolytichydrogen production plants. .............................................................................................. 14Table 6 Key emissions and land use of the reference plants. ........................................... 16Table 7 Temporal disaggregation for hydrogen production ............................................. 18Table 8 Spatial disaggregation for hydrogen production facilities. .................................. 18Table 9 Influential factors for the integration of hydrogen in the energy system ............. 22Table 10 Information on size and amount of energy needed to run four different sizes ofhydrogen stations. ............................................................................................................. 25Table 11 Needed number and size of new transformers within Reykjavik’s grid system ifhydrogen is produced on site near main transport routes. ................................................ 25Table 12 Cost composition of three sizes of electrolytic hydrogen stations based on costsof new equipment and operation costs as experienced during 5 years of operation inReykjavik. The price is in Isk where 100Isk=1€ ............................................................. 30Table 13 Boundary conditions for electrolyser and steam reformer set for comparison ofproduction cost of hydrogen. ............................................................................................ 34Table 14 Parameters that are used to scale up future cost reduction potentials ................ 34Table 15 Total share of hydrogen vehicles according to the Hy-Ways scenarios;Pessimistic – very optimistic scenario. A Realistically optimistic would set hydrogenpenetration at 2% of the vehicle fleet by 2020 and up to 50% in 2050. ........................... 38Table 16 Market share scenarios of stationary applications presented in the Europeanhydrogen road map ........................................................................................................... 38Table 17 Hydrogen production technology datasheet: Electrolysis ................................. 41Specific acronymsFC: fuel cellGCV: Gross Calorific ValueH 2 : chemical formula of hydrogen,HHV: higher heating valueLCA: Life Cycle AnalysisLCE Life Cycle EngineeringLHV: Lower heating valueNm 3 : Normal cubic meters; metric unit for quantifying hydrogen volume at 0°C and1atm pressure

NyOrka Page 5 12/18/20081 StructureThe goal of this chapter is to shed light on the technology that is currently and foreseen tobe used to produce hydrogen which can become an important energy carrier anddescribes policies and road maps concerning its market penetration. Only an optimisticscenario suggesting maximum expected penetration of hydrogen as an electric buffer andfuel for transport is presented. An LCA description and cost estimates follow for acontemporary hydrogen production system as are trends for the future settings.Reflections are given about the expected development of the components and materialswithin the selected pathway, electrolysis in combination with renewable energy systems,space and energy requirements and cost perspectives including the external costs.1.1 The data sourcesAs of yet, no major investment has been made in a real scale system that is to survivethroughout the timeframe of the NEEDS project: 2005 – 2050. No single technologicalwinner has been selected neither for a final strategy to produce nor to use hydrogen as anenergy carrier in stationary applications. Therefore it is currently impossible to give adetailed Life Cycle Analysis of any future hydrogen equipment. Reports, policy papers,technological previews have been emerging since 2005 and prove to be controversial.Information for the following paper has been collected from European, Asian – Pacific,Canadian and Japanese sources as well as reports that have emerged from theInternational Energy Agency, and the Hydrogen Implementation Agreement. (IEA/HIA)Interviews have been conducted and singular questions sent to developmental managersin strategic positions in industries in Norway, Canada and Germany and weighed againstexperience of running hydrogen systems for transport in Iceland and Germany during theperiod 2003 – 2008. It is hereby acknowledged that the staff at ,,Hydro Electrolysers” andthe project partners in HyFLEET:CUTE have by far, added most value to the presetselection for this report.2 HydrogenHydrogen, H 2, is an energy carrier, not to be found in natural conditions but can beextracted from numerous materials and energy sources; energy will be lost in theproduction phase. Hydrogen is the lightest element on Earth 1 , usually composed of oneproton and one electron and forms a diatomic volatile gas, H 2 , with boiling point at20.4°K. Hydrogen can be liquefied under high pressure and extreme cooling whichdemands energy expenditure. Explosions may occur at a mixture of hydrogen and airbetween 4 and 75% by volume. The same amount of energy bound in 1liter of gasoline isapprox 3Nm 3 under atmospheric pressure 2 but that amount would weigh only 270 grams.The energy contents are 3.00KWh/Nm 3 or 12.75 MJ/Nm 3 or 144MJ/kg. While a gasolinetank on a vehicle may take 50 litres of fuel, a hydrogen tank on a similar vehicles made in2003 would hold less than 2 kg of hydrogen and give roughly a driving range of 150 km.1 www.britannica.com gives a good insight into chemical and physical properties of hydrogen2 Nm3 stands for normal cubic meters because it is measured at 0°C and 1,013bar pressure.

NyOrka Page 6 12/18/2008The weight of the full hydrogen tank is still higher than that of the gasoline fuel tankbecause of the material and safety requirements of the container; Materials mustwithstands corrosive attack from hydrogen and oxygen and can hold extreme pressure aswell as prevent diffusion through walls and system connection. Whereas hydrogen ishighly volatile, disperses extremely fast, burns with an invisible flame and must beextremely pure to make fuel cells work properly, then hydrogen production, storage anddistribution must be optimised along every step within the energy conversion path.Further conversion factors have been issued in tables and explained in variouslanguages 3 .2.1 Methods and pathways for productionThree main methods exist for the mass production of hydrogen; Steam reforming, partialoxidation, and electrolysis. Emerging technologies are thermolysis and thermo-chemicalcycles, which have not been built yet and operate at temperatures above 1000°C. Theclassic methods are described in text books such as CJ Winter’s: Hydrogen as an energycarrier 4 .Approximately 95 percent of hydrogen is currently produced via steam reforming.Steam reforming is a thermal process that involves reacting natural gas or other lighthydrocarbons with steam. This is a three-step process that results in a mixture ofhydrogen and carbon dioxide, which is then separated by pressure swing adsorption, toproduce pure hydrogen. Steam reforming is considered the most energy efficientcommercialized technology currently available (η = 75-82%), and is most cost-effectivewhen applied to large, constant loads. In this case the hydrogen must be transported to themarket and purified to fit the use within PEM fuel cells. Research is being conducted onimproving catalyst life and heat integration, which would lower the temperature neededfor the reformer and make the process even more efficient and economical. Recentdemonstrations where hydrogen vehicles, especially buses have been tested in realtransport service, difficulties have arisen with small scale gas-reformers of the size thatwould fit hydrogen refuelling stations 5 These problems have not been defined properlywithin the industry but refer to both operational and purity problems. Due to thesediscoveries the reforming technology that has been referred to as straight forwardexercise of down-scaling an established technology before broad on site applications thereforming procedures will not be addressed within this chapter of future technologypathways.Partial oxidation (auto-thermal production) of fossil fuels is another method of thermalproduction. It involves the reaction of fuel with a limited supply of oxygen to produce ahydrogen mixture, which is then purified. Partial oxidation can be applied to a wide rangeof hydrocarbon feedstock, including light hydrocarbons as well as heavy oils andhydrocarbon solids. However, it has a higher capital cost because it requires pure oxygen3 An Icelandic/english version is to be found on www.newenergy.is/publications.4 Winter, Carl-Jochen & Joachim Nitsch eds 1988; Hydrogen as an energy carrier, technologies, systems, economy(translation from: Wasserstoff als Energieträger) Springer Verlag, Berlin, New York.5 HyFleetCute; the hydrogen bus demonstrations in Berlin, Nov 2008, presentation by Total;

NyOrka Page 7 12/18/2008to minimize the amount of gas that must later be treated. In order to make partialoxidation cost effective for the specialty chemicals market, lower cost fossil fuels must beused. Current research is aimed to improve membranes for better separation andconversion processes in order to increase efficiency, and thus decrease the consumptionof fossil fuels.The direct use of natural gas in the energy mix is growing rapidly, not the least as fuel fortransport and is therefore in direct competition with hydrogen on the market. Centralproduction of hydrogen from natural gas demands a different approach to distribution andinfrastructure as compared with hydrogen that is made in a distributed manner; mainlywith electrolysis from water or directly from solar power plants.Figure 1 Overview of energy streams, from source to user phase. Any source of energy can become asource of hydrogen and therefore it may give all regions an opportunity for local production andspecific local use.

NyOrka Page 8 12/18/2008Electrolysis, the splitting of pure water with electricity will be described later in moredetail as this is the selected technological pathway in this work package of NEEDS.Electrolysis has been in use for decades, and it is currently subjected to furthertechnological evolution for higher efficiency, minimal environmental effects and use withfluctuating electric input. The modularity of the equipment and the possibility to installonsite production facilities near the market gives higher flexibility for location choicesand evades the need for heavy investment for hydrogen distribution.The wide range of methods for production, storage and use phase of hydrogen is shownin figure 4. The oval at the lower half of the figure indicates which technicalspecifications will be addressed in the report. While making hydrogen with electrolysisfrom water and energy all renewable energy forms that give rise to electricity and or highheat can be considered for the process.According to the International Energy Agency, the year 2000 48% of hydrogen wasderived from Natural gas, 18% from Coal and 30% from oil through gasification and 4%from electrolysis. The total quantity was about 500 billion Normal m3 annuallyThe application methods are as varied as are the options for transportation from thehydrogen source to the users. Figure 1gives an overview of some of the hydrogenproduction and application options that are currently in use. The following criteria willform a frame will be set as boarders for the study: Minimisation of environmental effects,boosting efficiency and minimisation of the cost of handling and distribution as well asbuilt in safety requirements. The scope here is though set around the methods that usewater as the source of hydrogen and renewable energy to run the process. 48% ofhydrogen was derived from Natural gas, 18% from Coal and 30% from oil throughgasification and 4% from electrolysis. The total quantity was about 500 billion Normalm3 annually2.2 ElectrolysisAs mentioned the third family of production methods is electrolysis or splitting of waterwith an electric current. Electricity is lead through water and the water molecules splitinto oxygen at the anode and hydrogen at the cathode. The oxygen can be collected andused for specific purposes such as industry or aquaculture. One example of electrolysisfrom a chemical process but is not included further whereas the hydrogen is not as pureand the amounts are limited hydrogen production: the Lurgi process that produceshydrogen as a side-product from the production of Chlorine and sodium compounds. Thepurity if hydrogen made from water is higher and this is essential for PEM Surelyhydrogen can be collected from chemical industry, yet it may not be enough in the longrun and industries that only produce hydrogen for the energy market will be put near tothe markets while chemical plants are usually kept away from human settlements.Therefore options that can make hydrogen on a large scale must be defined.Three types of industrial electrolysis units are used today. Two involve an aqueoussolution of potassium hydroxide (KOH), which is used because of its high

NyOrka Page 9 12/18/2008conductivity, and are referred to as alkaline electrolyzers. These units can be eitherunipolar or bipolar. The unipolar electrolyser resembles a tank and has electrodesconnected in parallel. A membrane is placed between the cathode and anode, whichseparate the hydrogen and oxygen as the gasses are produced, but allows the transferof ions. The bipolar design resembles a filter press. Electrolysis cells are connected inseries, and hydrogen is produced on one side of the cell, oxygen on the other. Again, amembrane separates the electrodes.The third type of electrolysis unit is a Solid Polymer Electrolyte (SPE) electrolyser.These systems are also referred to as PEM or Proton Exchange Membraneelectrolysers. In this unit the electrolyte is a solid ion conducting membrane asopposed to the aqueous solution in the alkaline electrolyser. The membrane allows theH+ ion to transfer from the anode side of the membrane to the cathode side, where itforms hydrogen. The SPE membrane also serves to separate the hydrogen and oxygengasses, as oxygen is produced at the anode on one side of the membrane and hydrogenis produced on the opposite side of the membrane.Electrolytic units are currently capable of producing the largest amounts of hydrogen, andtoday are in use worldwide mostly the lye based technology, the selected case for theNEEDS . The LCA analysis is based on The PEM electrolysis unit is the newest of thetechnologies and is the cleanest candidate for future hydrogen production. Because thesimilarities with PEM fuel cells and PEM electrolyser it is foreseen that this unit willdevelop into the same unit: A reversible fuel cell! It is used for electrolysis to producehydrogen AND for the electric production from hydrogen. Prototypes of these are2.3 Process description of electrolysisRegardless of the technology, the overall electrolysis reaction is the same:H 2O → ½ O 2+ H 2Figure 2 A schematic overview of the process flow within the three main types of electrolysis

NyOrka Page 10 12/18/2008Different processes will use different pieces of equipment. For example, PEM units willnot require the KOH mixing tank, as no electrolytic solution is needed for that type.Another example involves water purification equipment. Water quality requirementsdiffer across electrolysers but water purifiers can also be essential according to thequality of the available water. Some units include water purification inside their hydrogengeneration unit, while others require an external deionizer or reverse osmosis unit beforewater is fed to the cell stacks. A water storage tank may be included to ensure that theprocess has adequate water in storage in case the water delivery is interrupted 6 .Table 1 The characteristics of electrolysis units available worldwideFor systems that do not include a water purifier, one is added in the process flow. Eachsystem has a hydrogen generation unit that integrates the electrolysis stack, gaspurification and dryer, and heat removal. Electrolyte circulation is also included in thehydrogen generation unit in alkaline systems (up to 30% mixture). The integrated systemis usually enclosed in a container or is installed as a complete package. Oxygen andpurified hydrogen are thereafter lead to respective compressors or liquefaction processesdepending on the selected transportation pathways.In addition to the listed manufacturers, there are several less known electrolysermanufacturers in US, Europe, India, Japan and China. Several of these manufacture forindigenous supply only.The energy required to produce hydrogen with water electrolysis varies slightly for thedifferent electrolysers, according to Table 1. Despite the amount of energy required for theelectrolysis process, the conversion efficiency is high, in the range of 80 to 85 % withreference to the gross calorific value (GCV).The size of an electrolyser can be varied. The economies of scale only apply partially tothis type of hydrogen production (see Table 12). An optimization between the sizes ofproduction units, storage capacity and distribution systems (as well as land costs) must befound according to the size of the user group. The first version of the European HydrogenHandbook 7 suggest a safety zone around hydrogen fuel stations in the range of 7 – 136 Iain Alexander Russel, Hydro Elecrtolysers personal communication, email 10 th of Dec 2006 and7 Hy-Approval handbook of hydrogen stations is still a living document, whereas the content has not been approved inall European states. See: http://www.hyapproval.org/publications.html

NyOrka Page 11 12/18/2008meters. In references from the USA, land cost has been reported to be little less than thecapital cost for the station 8 .Figure 3 An overview of the connected components of an electrolytic fuel station anno 2003.For the purpose of simulation the configuration, size and load can be varied theoretically between thecomponents to find the optimal running conditions according to demand or other criteria 9 10Electric-current density is low when applied for today’s technology, typically 1 – 2kA/m 2 . In addition to significantly improving the energy consumption, it also dictates thenumber of cells and hence the area or footprint required. An increase in current density inthe magnitude of 5 – 10 times, without a significant increase in power consumption, as isexpected in future electrolysers. Table 2 gives an overview of the main manufacturersand the configuration for the technology.8 Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery mode article pending to be publisedin the international journal of hydrogen energy.9 Ulleman Oystein, for IEA, hydrogen implementation agreement, annex 18, integrated hydrogen systems subtask B,simulations of hydrogen systems.10 Ulleberg, Oystein, Susan Schoenung,Maria Maack, Bengt Ridell et al, World Hydrogen Energy Conference, WHEC,Conference paper 2007

NyOrka Page 12 12/18/2008Table 2 List of selected electrolytic technology and general configurations 11Technology;type ofelectrolyserConventional Advanced alkaline InorganicmembranePEMDevelopmentstageCommerciallarge scale unitsPrototypes andcommercialCommercialunitsPrototypes andcommercial unitsSOFC Hightemp. steamLab-stageand commercialunitsCell voltage (V) 1.8-2.2 1.5-2.5 1.6-1.9 1.4-2.0 0.95-1.3Current density 0.13-0.25 0.2-2.0 0.2-1.0 1.0-4.0 0.3-1.0(A/cm 2 )Temperature (°C) 70-90 80-145 90-120 80-150 900-1000Pressure (bar) 1-2

NyOrka Page 13 12/18/2008Table 3 Description of LCA phasesLCA phase DescriptionFuel supply The station uses grid electricity and tap water to produce compressedgaseous hydrogen ready for use in fuel cells or internal combustion engines.ProductionOperationDisposalManufacturing of electrolyzer, compressor and storage modules, dispenser,buffer tank, nitrogen bottles and walls and foundations. On-site assembly.Replacement of electrolyzer cell package, diaphragms and hydraulic oil forthe compressor. Maintenance and overhaul materials for e.g. pipes andfittings, the nitrogen bottles are neglected as supplies due to low dataavailability. Lye (KOH) to facilitate the splitting of H 2 O, Nitrogen to flushthe cell stack when the process is stopped or in time for maintenance orreparation, this function becomes less needed if the whole module is keptunder pressure during iAll metals are recycled and are not included as the cut-off approach is used.It is assumed that all other materials are transported to landfill or recyclingplant.The hydrogen production facility is made from several modules which are manufacturedseparately and then assembled on-site. The most important of those can be seen in Figure 5which shows the main division of the station into its main components.Figure 5 Main components of an electrolytic hydrogen filling station.The most important figures and statistics related to the hydrogen station modelled can beseen in Table 4.Table 4 Parameters for the studied hydrogen production facilities in current situation.Parameter Unit Current(as of 2003)ElectrolysisElectricity required kWh / kg GH 2 62- for electrolyser kWh / kg GH 2 53- for compressor kWh / kg GH 2 8Water required litres / kg GH 2 10

NyOrka Page 14 12/18/2008Storage pressure Bar 440Production capacity kg GH 2 / year 47250Lifetime years 15Area occupied m 2 3002.4.1 Material flow data and sourcesThe model used here is based on an inventory compiled by Mailänder in 2003 12 whichconsidered a hydrogen fuelling station from Norsk Hydro (now HydroStatoil 13 )assembled in Reykjavík and still in operation by 2008. The data came from themanufacturers of each module. The maximum output of the hydrogen fuelling station is60 Nm3 H 2 /h at 15 bar or 5,394 kg/h which amounts to 180kW/h output in energycontent. The simulation was altered as to make the results more relevant to currentsituation in Europe; therefore the hydrogen station was placed in central Europe andfurnished by UCTE grid electricity.Table 5 Material and energy flows allocated to the production of current electrolytic hydrogenproduction plants.Component Material or service unit Per kg GH2Electrolyser chromium steel 18/8, at plant kg 5,99E-03nickel, 99.5%, at plant kg 7,05E-04synthetic rubber, at plant kg 3,53E-05reinforcing steel, at plant kg 1,87E-03copper, at regional storage kg 5,40E-04tube insulation, elastomere, at plant kg 2,40E-04aluminum, production mix, at plant kg 1,55E-04acrylonitrile-butadiene-styrene copolymer, ABS, at plant kg 5,64E-05polyethylene, LDPE, granulate, at plant kg 1,41E-04glassfiber, at plant kg 1,41E-04cast iron, at plant kg 4,80E-05nylon 66, glass-filled, at plant kg 1,76E-05transport, lorry 32t tkm 9,91E-04Diaphragmreinforcing steel, at plant kg 1,75E-03Compressorchromium steel 18/8, at plant kg 1,34E-03cast iron, at plant kg 4,23E-04ethylene glycol, at plant kg 4,94E-06lubricating oil, at plant kg 1,27E-05aluminum, production mix, at plant kg 4,23E-05tube insulation, elastomere, at plant kg 1,06E-05copper, at regional storage kg 3,17E-05electricity, production mix UCTE kWh 7,05E-04heat, natural gas, at industrial furnace >100kW MJ 2,54E-03transport, lorry 32t tkm 3,62E-0412 Mailänder, E. (2003). Life cycle analysis of hydrogen infrastructure for fuel cell driven buses in thepublic transport of Reykjavik, Diploma thesis, University of Stuttgart.13 See description on www.electrolysers.com

NyOrka Page 15 12/18/2008Storage Module chromium steel 18/8, at plant kg 5,93E-02electricity, production mix UCTE kWh 6,77E-04diesel, burned in building machine MJ 6,04E-04transport, lorry 32t tkm 5,93E-03Walls and Foundation reinforcing steel, at plant kg 6,35E-03flat glass, coated, at plant kg 2,29E-03gypsum fiber board, at plant kg 7,05E-05silica sand, at plant kg 4,06E-02concrete, normal, at plant m3 7,05E-06concrete, exacting, at plant m3 9,17E-05gravel, unspecified, at mine kg 1,27E+00lubricating oil, at plant kg 1,41E-05electricity, production mix UCTE kWh 3,53E-04diesel, burned in building machine MJ 3,02E-02transport, lorry 32t tkm 1,56E-01Occupation, industrial area m2a 6,44E-03Other Components reinforcing steel, at plant kg 1,16E-03nitrogen, liquid, at plant kg 1,01E-04chromium steel 18/8, at plant kg 2,85E-04polypropylene, granulate, at plant kg 7,05E-06transport, lorry 32t tkm 6,90E-02Operation chromium steel 18/8, at plant kg 3,69E-02nickel, 99.5%, at plant kg 2,82E-03synthetic rubber, at plant kg 1,41E-04reinforcing steel, at plant kg 5,50E-02cast iron, at plant kg 2,54E-02ethylene glycol, at plant kg 2,96E-04lubricating oil, at plant kg 7,62E-04electricity, production mix UCTE kWh 4,23E-02heat, natural gas, at industrial furnace >100kW MJ 1,52E-01transport, lorry 32t tkm 2,20E-013 Results3.1.1 Key emissions and land useAs a result of WP 1, a “minimum air pollutant list” to be used for the external costassessment was defined between RS1a and RS1b. The emissions related to hydrogenproduction facilities are shown in the annex. The emissions shown in table 2.1 are anexcerpt of this minimum list and were analysed to be most relevant for hydrogenproduction. They refer to one kilogram compressed gaseous hydrogen.The main emission into air is carbon dioxide. Regarding all the emissions the vastmajority comes from the fuel supply phase, i.e. the actual production of hydrogen byelectrolysis (see Figure 6 below). The emissions from the manufacturing phase of thefuelling station are dominated by the amount of steel and concrete used.

NyOrka Page 16 12/18/2008Table 6 Key emissions and land use of the reference plants.Parameter Path Unit Current(as of 2003)ElectrolysisKg GH2Carbon dioxide, fossil Air kg 2.84E+01Carbon monoxide, fossil Air kg 1.36E-02Methane, fossil Air kg 4.53E-02Nitrogen oxides Air kg 5.19E-02NMVOC Air kg 4.82E-03Sulfur dioxide Air kg 1.17E-013.1.2 Contribution analysis for the main life cycle phasesIn a contribution analysis the key emissions are split into the four main life cycle phases.Figure 6shows their shares.InterpretationIt can be assumed that using an electricity mix which relies mostly on renewable energywould result in greatly reduced emissions and therefore a greater proportional share forthe manufacturing and operation phases. It is evident from figure 2.1 that the vastmajority of emissions comes from the fuel supply phase, i.e. the actual production ofhydrogen by electrolysis. This is due to the fact that a great amount of electricity isrequired for electrolysis, and so the source of electricity is very important. The UCTEproduction mix contains electricity produced from coal, oil, etc., so emissions from thefuel supply phase are considerable.Contribution analysis for current electrolytic hydrogen productionConstruction Operation Fuel DisposalCarbon dioxide, fossilCarbon monoxide, fossilMethane, fossilNitrogen oxidesNMVOCSulfur dioxide0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Figure 6 Contribution analysis for electrolytic hydrogen production, when using UCTE grid mix.Refer to figure 7 for comparison with grid mix based on renewable sources.

NyOrka Page 17 12/18/2008The emissions from the manufacturing phase is dominated by the amount of steel that isused in the storage module and the filling station itself, as well as the volume of concretethat is necessary for the foundation. The NOx and CO emissions are also a typicalemission related to the combustion of fossil fuels, e. g. in diesel engines related totransportation of the manufactured modules to assembly site. The NMVOC emissionsalso come from the nickel from the electrolysers electrodes.Using hydrogen to buffer renewable energy systems, such as a network of windfarms orsolar plants, the electricity to run the operation would come from renewable sources asthey actually do in the case plant (at Grjóthals, Reykjavik Iceland it is fed electricity fromgeothermal- and hydropower). The largest impacts may shift to the manufacturing phaseof the module where the electricity comes from renewable sources.To illustrate the importance of the source of the electricity used for hydrogen production,Figure 7compares the key emissions using the UCTE grid and the Icelandic electricity gridwhich is composed of 82% hydropower and 18% geothermal power).The absolute values are too different between categories to show in a single graph, so apercentage graph is used instead. Should the electricity be derived from wind turbines theenvironmental impact would be even become less than for the Icelandic grid mix.Grid mix comparisonUCTE MixIS Mix100%90%80%70%60%50%40%30%20%10%0%CarbondioxideCarbonmonoxideNitrogenoxidesSulphurdioxideGroupNMVOC toairMethaneFigure 7 Comparison of key emissions using UCTE electricity grid and the Icelandic electricity grid.3.2 Additional informationTemporal disaggregationThe temporal disaggregation means the duration of and time between the phases withreference to start of commercial operation. Table 7 shows the values for the referencehydrogen production facilities with year number 1 as start year of commercial operation

NyOrka Page 18 12/18/2008Lifetime of the station is assumed to be 15 years, although some individual modules mayhave a longer lifetime (up to 30 years). The fuel supply and operation emissions areevenly spread out over those 15 years.Table 7 Temporal disaggregation for hydrogen productionPhase Unit PresentElectrolytic H 2ProductionCONSTRUCTIONStart year 0End year 0FUEL SUPPLYStart year 1End year 15OPERATIONStart year 1End year 15DISPOSALStart year 16End year 163.2.1 Spatial disaggregationTable 2.3 provides information on where the main life cycle phases are located. They areallocated to five regions within Europe or to continents if they are outside of Europe.Because the fuel supply phase is so dominating with regards to the emissions, the spatialdisaggregation obviously depends heavily on the location of the facility. In this report thestation is assumed to be located in central Europe (region 1), so all of the emissions fromoperation, fuel supply, and disposal occur there. The only part of the life cycle whichhappens outside of central Europe is the manufacturing of the electrolyser module, whichtakes place in Norway (region 4). Exact definition of the affected regions is found below.Region 1: Belgium, Switzerland, Germany, France, Luxembourg, NetherlandsRegion 4: Denmark, Estionia, Finland, Greenland, Ireland, Iceland, Lithuania, Latvia, Norway,Sweden.Table 8 Spatial disaggregation for hydrogen production facilities.Electrolytic hydrogenRegion Fuel Prod Op Disp% R1 100 70 100 100% R2% R3% R4 30% R5% C1% C2% C3% C4% C5

NyOrka Page 19 12/18/20084 Electrolysis technology development pathwaysThe drivers for using hydrogen as energy carrier or buffer for grids are:• Distributed production i.e. near the customer• Diversification of energy sources and availability of water supply• Clean operation, - important in cities to lower sooth• Good integration possibilities with established electric systems and modules• Buffering opportunities to meet fluctuations between production and demand withrenewable energy systems• Stand alone applications in remote areas possible• Benign environmental effects during use phase• High energy quality characteristics• Combined heat and power production with use of certain Fuel Cells• Easy integration with upcoming transport schemesDuring the first stages of introduction, hydrogen from industry and central gas reformingis seen as the main source. Hydrogen will be foremost used as fuel for transport withelectric vehicles, and in figure 8 Hydrogen is placed as fuel at the future end fordecarbonised fuel types, but hydrogen technology has been used in viable energy systemsfor decades Two main pathways are predicted for electrolysis when demand rises in thesecond and third decade of the 21 st century; Electrolysis using PEM electrolysers on onehand and high heat, high pressure lye electrolysis on the other. The PEM technology isforeseen as a small module for specific applications while bulk production may requirelye electrolysis, which is proven technology. High heat and pressure electrolysis shouldoccur at temperatures near500°C (supercritical heat) ormore and is foreseen in contextwith solar thermal towertechnologies, high geothermalheat and nuclear power coolingfacilities.Figure 8 Energy road-maps for thenew century predict that fuel typesfor transport, will containgradually less carbon. 14 .Due to purity demands, theselected hydrogen deploymenttechnology will influencewhich production pathway isused. The PEM fuel celldemands high purity while other types of fuel cells can use hydrogen mixed with othergaseous fuel. The PEM is promoted in context with transport drive trains as they arecompact and operate at temperatures below 100°C. Recent developments have shown14 Minns David (editor) 2005, APEC 2030 Integrated Fuel technology roadmap

NyOrka Page 20 12/18/2008small reversible PEM units (

NyOrka Page 21 12/18/20084.1 Hydrogen roadmaps and policyThe 2003energy policy paper: European Energy Outlook and Transport – Trends to 2030states that fossil-fuel prices are foreseen to be static and therefore conventional fuel fortransport i.e. oil products are considered to keep their market share. Hydrogen is neithermentioned for use in stationary application, CHP nor as fuel for transport 17 . Some of theTrend paper’s assumptions, such as price for oil, became highly inaccurate only 3 yearsafter its publication.In 2002 the European Commission launched a policy outline regarding hydrogenspecifically for Europe 18 . Hydrogen is linked to hopes for a more energy-self reliantEurope and its policies to decrease carbon emissions and leverage the risk of climatechange by increasing the use of renewable local energy. Referring to Error! Referencesource not found. it becomes evident that the outlined idea is to derive hydrogen fromvarious sources, either energy carriers with carbon contents or from water throughelectrolysis. Carbon sequestration is discussed in the same context, if H 2 is madecentrally from fossil fuels such as gas.The EC supported HyWays 19 project (2005– 2007) suggest that the maximum penetrationtarget for hydrogen and fuel cell passenger cars in 2020 should be 3% of the totalpassenger car fleet. Car- manufacturers (for example GM in USA, Toyota in Japan,Daimler in Europe) state that the technological maturity for marketable FC vehicles willhave arrived by 2010 but others 20 aim to offer a different type of hydrogen drive trainusing high heat fuel cells by 2020. Still others manufacture vehicles for public transportthat burn hydrogen in internal combustion engines. These vehicles will have integratedbattery and hydrogen drive trains to raise efficiency, as will other types of vehicles usingdifferent energy carriers derived from renewable sources.In 2006 the European Commission issued a green paper listing a number of options forachieving sustainable competitive and secure energy supplies in the EU 21 assuming thathydrogen will be available on the market both as fuel for vehicles and as a buffer inelectric systems that are (partially) powered by renewable energy such as connectedwindfarms. By December 2006 scientists urged the European commission as well asgovernments and the UN to consider supportive measures to aid the introduction ofhydrogen worldwide and a developmental centre whose goal is to facilitate theintroduction of hydrogen in developing countries is in Turkey, a country that aims tobecome part of EU.The use of hydrogen in the transport sector will influence the speed of integration intostationary applications and technological spill-over will influence stationary applications.Current transportation of hydrogen in pipes as is already known from central Europe will17 European Commission Directorate-General for Energy and Transport, 2003: European energy and transport trends to2030. Prepared by National Technical University of Athens, E3Mlab18 EC 2003, High level group to the commission: Hydrogen and fuel cells a vision of our future19 A brief description of the project, its goals and tools is given at: www.hyways.de/project/description.html20 Volkswagen, nov 200621 EurActiv EU news, policy positions and EU Actors online; 9th of March www.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=News

NyOrka Page 22 12/18/2008continue to be operated, but the speed of integration depends to a high degree on theproportional cost as weight against other types of transport fuel; the higher the price of oilproducts, the higher the price of fuels made with agricultural products and at the sametime the more likelier will become extended use of hydrogen which is made in situ, eitherfrom gas or water.HyWays High EU Fleet Penetration HyWays Low EU Fleet Penetration IEA World Fleet PenetrationIEA EU Fleet Penetration HFP SRA WETO-H2: H2 case (World)IEA World Fleet Penetration MAP Scenario80%70%Share of hydrogen vehicles (%)60%50%40%30%20%10 %0%2010 2020 2030 2040 2050Figure 10 Overview of expected proportion number of hydrogen vehicle penetration on the worldmarket according to various sources 22 .The matrix of factors that are influential for the speed of hydrogen integration is shown inTable 9.Table 9 Influential factors for the integration of hydrogen in the energy systemLevelsFinancialAdministrationalEnvironmentalInfrastructureActs to speed up hydrogen systemdevelopmentDeregulation and growingflexibility; growing use of fuel cellsin transport; taxed carbonemissions.Comparable prices with othertransport fuels; Extended use offuel cellsExternalities charged for all fuels.Available electricity grids. Highintegration of renewable energypower;Good access to electric gridActs to slow down the speed of hydrogensystem developmentLack of harmonised hydrogen codes andstandards; set restrictions for safety reasons,ignoring technology- and materialdevelopments 23 ,Lack of standards for purity criteria, theseeffect which type and life-time of fuel cells;efficient and eco-effective fuel chains fromother sources;as well as minimal and recyclable use ofscarce minerals (such as Pt).complex optimization between production,storage and distribution modules22 Gudmundsdottir L. (2008)23 Final report of HyApproval; harmonised European handbook for Hydrogen stations.

NyOrka Page 23 12/18/20084.2 Criteria for hydrogen applicationsThe production pathway selected for further analysis emphasises the electrolytichydrogen production in as competitive and secure operation as possible and thenadjusting these to optimal efficiency. The current bulk production method; steamreformation from gas will also be used as reference.4.2.1 Efficency of productionCurrent electrolysers show an efficiency of about 65 - 75% but the goal is to raise it up to87% by 2020. In future models the technology may allow for electrolysis to be carriedout under high pressure and partial substitution (up to 20%) of the electric energy withhigh heat. As a rule the efficiency of low pressure electrolysers is given with thefollowing function:ηsystem=m * H 2HH 2EElectrwhere m H2 : Mass of produced hydrogenH H2 : Heat value of hydrogenE Electr : Amount of electricity 24If the pressure in the electrolyser is raised this is done only to reduce the volume ofhydrogen and therefore the space of hydrogen stations. When high heat is added to theprocess the voltage can be lowered from 1,48Volt to 1,23Volt.4.2.2 Quality criteriaModern PEM fuel cells are sensitive to impurities carried in hydrogen. The purity issometimes simplified to four, five or six nines (99,99%; 99,999% and 99,9999%), but thetolerance is not equal for all impurities. Within the HyFLEET:CUTE project, the brakedown of cost components of hydrogen revealed that monitoring and analysing the qualityas well as purification of hydrogen has significant impact on its price. The PEM fuel cellsare mostly applied in vehicles but for stationary applications other types are more costeffective and they can use a range of fuel types. The proportional in-stallation of fuel celltypes is presented in the fuel cell chapter.From electrolytic hydrogen the impurities consist mainly of O 2 that damages the coatingsof PEM fuel cells. Impurities from gas-reformation can be H 2 O, CO, CO 2 or N-compounds and those can harm PEM fuel cells but types of stationary FCs can withstandmore impurity (see section on fuel cells). International standards for purity have not beenset but are rather negotiated along the delivery chain. Drying and purification can raiseprices and can become energy intensive within the reformation or gasification methods(see section on hydrogen costs). Whereas the NEEDS project is dedicated to hydrogen in24 Faltenbacher Michael, PE International 2006, report on LCA of hydrogen production within CUTE cities

NyOrka Page 24 12/18/2008stationary applications, but emphasis on renewable sources hydrogen costs fromelectrolysis will be compared to that made from gas.4.2.3 On site production of hydrogen; grid criteriaIn later decades the ideal distribution is in high pressure pipelines, but this has as of 2008not been implemented even as a pilot test 25 . If hydrogen is made with electrolysis themeans of transport is in the form of electricity along established grids.Large electrolytic hydrogen production units demand large power intake. For a stationthat produces more than 500Nm3/h the power must be at least 2,25MW. Also, as powerlines have limited capacity an optimal selection must be made between the reinforcementof the grid for electricity distribution and the delivery of hydrogen in the elementary form(via pipes and trucked in). If the grid is not capable of accepting all power that isproduced during peak hours, for example from a network of wind farms, then the surpluscould be changed to hydrogen on site and stored for times with higher customer demand.This is called hydrogen production from dump load and has been installed for example inRamea, Newfoundland (see fig 12)Otherwise reinforcement of the grid capacity is an option.In 2008 a study on the optimal pattern for establishing hydrogen fuel stations inReykjavik, Iceland was carried out. It can give an insight into how they affect theestablished grid if the demand for hydrogen rises. Results that are shown in Table 10 areaccording to three main criteria and a following assumption;1) That electrolytic stations are erected close to step-down transformation pointsalready established within the Reykjavik’s electricity distribution system2) That their capacity has not been put to the full use3) That these points lie close to large traffic routes.4) Assumptions concerning vehicles are that they use 1,3kgH2/100km and will drivearound 12000km annually.The distribution system in the city is made of primary substations and 11kV cables thatconnect a number of distribution substations and terminate in circuit breakers, usuallylocated between two possible input points from primary substations. In each substationthe voltage is stepped down from 11kV to 400V and goes out in a few 400V cables whichcarry current to a number of small distribution cabinets scattered in the city.25 Rouvroy, Steven Shell Hydrogen, HyFLEET:CUTE meeting, May 2008

NyOrka Page 25 12/18/2008Table 10 Information on size and amount of energy needed to run four different sizes of hydrogenstations.Size of stations60 Nm3 130 Nm3 485 Nm3 970 Nm3*INPUTProduction capacity 60 130 485 970 Nm3/hB, Energy costSpecific energy constant 5 5 5 5 kWh/Nm3Annual operational hoursof grid 8.136 8.136 8.136 8.136 hours/yearInstalled power 0,3 0,65 2,425 4,85 MWEnergy consumption 2.441 5.288 19.730 39.460 MWhAmount of hydrogenproduced per year 43.886 95.085 354.742 709.484 KgAnnual max number ofpassenger cars serviced 281 610 2.274 4.548To construct hydrogen stations in the optimal order, the overall electric distributionsystem has to be investigated; what is the current use, the overall system capacity and canthe high Voltage cables provide enough electricity to the ideal locations. Is the fullcapacity already in use or is there room for additional power transmission? The studyonly maps whether the areas’ electric grid networks can handle the required extradistribution or how it may be changed to fit the needed carrying capacity. The resultsfrom Reykjavik are presented in tables 5 and 6. In this case the grid has been built todeliver on peak demand (the 24 th of Dec in the afternoon!) and is therefore ready totransport electricity to planned hydrogen stations in times of low demand, but the gridneeds to be reinforced if the demand increases considerably. The maximum demand ismeasured at 77 A, but the grid is built to deliver 320 A. The unused capacity surplus is178 A using 80% load.Table 11 Needed number and size of new transformers within Reykjavik’s grid system if hydrogen isproduced on site near main transport routes.Production capacity 60 130 485 970 Nm^3/hCurrent 433,0 938,2 3.500,2 7.000,4 ATransformers size 1 315 800 1250 1600 kVA2 1250 1600 kVA3 1250 kVA4 500 kVAMax current obtained 455 1155 3608 7144 AEstablishing a hydrogen station in one location evidently draws energy from the wholesystem, and therefore shuts out the opportunity of building a second one in close vicinityof the first one. In all cases, medium to large electrolytic hydrogen stations proved to be

NyOrka Page 26 12/18/2008the optimal choice, given that the number of hydrogen vehicles would grow 2015 fromand replace 50% of gasoline vehicles by 2050.4.2.4 Quantitative criteriaIn 2000 the annual world hydrogen production amounted to about 500 billion Nm3. Mostof the hydrogen is made in centralized plants that typically produce 100.000 Nm3/h withsteam reforming. The proportion is about 48% from natural gas, 30% from petroleum and18% from coal. Hydrogen is used in industry and for that purpose distributed in selectedregions in low pressure pipes from the place of formation to the users. More could berecuperated from industrial plants that currently burn off hydrogen that forms as a byproductin the process stream, but this type of hydrogen must meet relevant puritydemands. Refer toIn transport demonstrations 2001-2008 (ECTOS, CUTE, STEP, HyFLEET:CUTE 26 )decentralized stations produced hydrogen of the magnitude 50 – 100 Nm3/h and mostupcoming electrolyses will be in the range of 100 – 1000 Nm3/h 27 .Hydrogen losses have been observed in production facilites. For hydrogen produced at onsite stations from reformed gas the loss is detected in the pressure swing adsorption(PSA) unit, which is part of the steam-reformer system and in the electrolyser it is thedeoxo-dryer unit. In the case of the PSA, the losses vary between 12,5 % and 22,5 %,depending on the hydrogen specification that is used, while the losses at the deoxo-dryervary between 4 % and 6 %. Both losses and purity demands raise the unit price ofhydrogen, but table 7 shows the recent composition of the cost of modules for electroliticstations in three different sizes.Both criteria pose added cost on the hydrogen except if it can be used in fuel cells thatcan handle impurities and used to derive electricity close to its origins. Most relevantdistribution of hydrogen made with renewable energy from water would be within anelectric grid. Therefore the reinforcement of the grid may be inevitable but trucked inhydrogen may pose severe social opposition.4.2.5 Where would the hydrogen come from?The cheapest method is to use excess hydrogen from large industrial gas plants andnatural gas as a source for making hydrogen. This method can therefore be used for costcomparison and cost- optimisation. Secured supply is one of the important criteria inenergy services that need to be addressed. Mature gas technology and direct applicationsas well as the small environmental gain from reforming gas to hydrogen discourages thatpathway for long term hydrogen production but can give rise to further studies on costdevelopment. Where would the hydrogen come from if Natural gas becomes less ideal?Ludwig Bölkow System Technik 28 (LBST) published in 2005 a forecast stating that fossilfuel exploitation (including coal) would rapidly decrease after 2010, due to various26 See further at www.global-hydrogen-bus-platform.com27 Hydro Electrolysers Iain Alexander Russel, Pietro d’Erasmo; Hydro Elecrtolysers email 10 th of Dec 200628 See further on www.LBST.de

NyOrka Page 27 12/18/2008factors. As an alternative, LBST suggests to fill the gap for energy into Europe withimported biofuels and non-carbon energy from neighbouring countries.Iceland:Geothermal powerHydro PowerNorway:Hydro PowerUkraine:Brown CoalHydro PowerRomania:BiomassHydro PowerBulgaria:Hydro PowerBiomassGeothermal PowerNorth Africa:Solar powerWind powerTurkey:BiomassFigure 11 Hydrogen or electricity by cable? Pathways for hydrogen import to Europe have beenmapped by the ‘Encouraged’ project29.4.2.6 Niche marketsIn 2006 there were 65 hydrogen fuelling stations listed as operational or planned inEurope 30 , mostly used to refuel buses. Hydrogen stations are foreseen to be introducedaligned with introduction of concentrated hydrogen fleets in certain communities. Thesewould be the basic hubs that later connect and form hydrogen – regions such as isplanned between Bergen, Norway, through the west coast of Sweden and across theNordic Sea to Denmark 31 .Another niche market is backup–power storage for peak–load demand or bufferingfluctuations between production and demand. Grid systems have limited capacity toaccept fluctuating supply from production units such as wind mills. Hydrogen acts as anelectricity storage that can deliver more power when the demand increases.29 Encouraged EC project no 006588, Energy corridor Optimisation for European Markets of Gas Electricity andHydrogen 6 th FP. Coordinating organisation: Frauenhofer ISI, Martin Wietschel30 www.h2stations.com31 Hy-Nor project as presented at HyFLEET:CUTE general assembly, Reykjavik May 2008.

NyOrka Page 28 12/18/2008Figure 12 The system setup in Ramea 32Island economies or remote communities that suffer from high importation costs of fossilfuels may move faster towards hydrogen than other societies 33 that have larger areas andabundant sources of biomass. Simultaneously, remote islands may have higher potentialto utilise renewable sources that tend to accumulate with this geographical position, suchas ocean energy, currents, wind and geothermal power. Orkney, north of Scotlandconsiders to exploit strong currents and export hydrogen (rather than electricity via cablesacross protected nature reserves in Northern Scotland) when oil excavation decreases inthe North Sea.In Germany preparations have been made to connect and coordinate wind farms andpower distributors for testing hydrogen and fuel cells to buffer electricity onto the gridwill start early 200734. A test project of this type was established in Utsira, Norway in2005 and a continuously operating system was installed in the community Ramea inNewfoundland in 2004. Wind generated power had substituted about 10% of the energydemand by April 2008, saving the diesel oil that would have gone into the same thing.But the wind power and demand do not match. Therefore dump-loads will be used togenerate hydrogen whereas the local grid installations do not accept the high peakproduction. This amounts up to 50% of the wind generated electricity on a constant basis.The Integrated system in Ramea is displayed in figure 12.Within the APEC (The Asian Pacific- Economic Cooperation), renewable energy andhydrogen is seen as entering first as a fuel for stationary CHP applications and later for32 Jones, G: Wind-hydrogen diesil Energy Project at Ramea Newfoundland, presentation held at the North AtlanticHydrogen Association conferenece, 25th of April 2008.33International seminar on the hydrogen economy for sustainable development; Geothermal Resources, currentdevelopment and potentialswww.un.org/esa/sustdev/sdissues/energy/op/hydrogen_seminar/hydrogen_seminar_programme.pdf34 Holger Grubel, (personal communication, December 13 2006) Vattenfall power company , Germany

NyOrka Page 29 12/18/2008transportation purposes, yet already before 2020 35 its market penetration is set at 5%,whereas China and India have already started their experimental use of hydrogen and fuelcells.4.3 Cost of hydrogen production from two sourcesThe most actual costs for hydrogen technology have been studied with real data derivedfrom H 2 bus demonstrations. Hydrogen vehicle operation in fleets will have spill-overeffects to development of other sectors of society. The production stations are,undergoing their first field demonstrations and the figures can only give an indication ofcost and efficiency, and therefore important as first points in a learning curve. Citedreports are deliverables from CUTE, HyFLEET:CUTE bus demonstration projects andthe Icelandic SMART-H 2 project. This section is presented as on overview of the currentcost proportions and forecast for the production costs, when using real data (figs 13 – 17).Note it is based on the technology which is currently in use for hydrogen and is derivedfrom small scale plants that fit transportation demonstrations.The most relevant parameters for the interpretation are:• The actual systems used come from differnt manufacturers and have differentboundary conditions such as production capacities. The production unit (PU) ofall both steam-reformer system and the electrolyzer system produce 60 Nm³/h ofhydrogen. Considering hydrogen losses that occur downstream of the productionunit, the steam-reformer system yields a delivered quantity of 43.157 kg H2 /year,while the electrolyzer system delivers a quantity of 43.465 kg H2 / year.• Of these produced quantities, 43.000 kg H2 /year (each system) are delivered tofuel cell buses, while the residual amount of hydrogen from the hydrogen fillingstation is considered as “overproduction” within the mass balance of the system.• Initial costs for the steam-reformer based system amount to 1,75 Mio. € and to1,74 Mio. € for the electrolyzer based system.The total consumption of energy amounts to 5,7kWh/Nm³ H 2 for both hydrogenproducing systems. In the case of the steam-reformer, this includes 4,7 kWh/Nm³ H 2natural gas. The amount 5,7 kWh/Nm³ H 2 also includes the energy consumption forthe compression of the hydrogen up to 350 bar at 15 °C. Electric energy, which meets theentire energy demand of the electrolyzer based system and 1kWh/Nm³ H2 at thesteamreformer system is assumed to be purchased for 0,10 €/kWh and natural gas isassumed to be purchased for 0,05 €/kWh. These prices are varied within one similation toshow the price elasticity.The cost contributions would be composed within the hydrogen supply chain, the cost ofmonitoring the quality and purification. The presentation is derived with GaBi4 asoftware tool for Life Cycle Engineering. LCA costs of dismantling and externalities. Thequality criteria were found to be relevant during the project CUTE project accounts forthese in their current and future cost estimations 36 .35 Minns David (editor) APEC2030 Integrated Roadmap Nov 2005: Future fuels for the APEC region36 Faltenbacher Michael Wittstock TREN/05/FP6EN/ S07.52298/019991

NyOrka Page 30 12/18/2008In Table 12 the cost of hydrogen from three different sizes of electrolytic station areshown. The water is set constant according to the footprint of the plant, as is the customin Reykjavik, but after use with fuel-cells the water could be collected and reused in thesame plant. Larger plants use proportionally less Nitrogen. The footprint of the plant doesnot need to grow linearly with the size of the station if pressure is increased for examplefrom 1,5 MPa to 3MPa during the production phase.Within the CUTE project a cost contribution analysis was made using data from the tenhydrogen stations used in the demonstrations. The range of cost was quite broad andtherefore figures 13 – 17 display three cost scenarios based on actual cost from differentsites, where the process had the least and most cost as well as the average cost.Table 12 Cost composition of three sizes of electrolytic hydrogen stations based on costs of newequipment and operation costs as experienced during 5 years of operation in Reykjavik. 37 The priceis in Isk where 100Isk=1€2.323.529 1.186.289 1.008.345Production capacity 130 485 970 Nm3/hA, InvestmentElectrolyser 80.549.000 115.070.000 195.619.000Other equipment cost 161.098.000 345.210.000 586.857.000Installation and start-up cost 60.411.750 115.070.000 195.619.000Total investment cost 302.058.750 575.350.000 978.095.000 krB, EnergySpecific energy constant 5 5 5 kWh/Nm3Needed installed power 0,65 2,425 4,85 MWC, Operation and maintenance costOperation and control cost per year 847.500 847.500 847.500Maintenance (material) per year 4.832.940 9.205.600 15.649.520Maintenance (staff) per year 6.000.000 12.000.000 15.000.000Water and nitrogen 2.400.000 4.800.000 8.400.000Total operation cost 14.080.440 26.853.100 39.897.020 kr. Per yearFigure 13 shows the overall hydrogen cost for 1kg H 2 produced electrolyser (manufacture2003) within the CUTE demonstration boundary conditions using the set cost forelectricity at 10ct/kWh. The red lines shown indicate the average diesel cost for 1 kghydrogen equivalent (120 MJ net cal) as of 30 th of January 2006 with and without taxes.This is the normal reference point while studying bus fuelDeliverable No. 1.5, Report on the findings regarding optimised hydrogen purity Mr. Bastian 1, Dr.-Ing. 237 Gudmundsdottir Lilja (2008): Analysis of the electric grid in Reykajvik, Greenland and Faroe Islands, MSc projectat the University of Iceland, financed by the North Atlantic Hydrogen Association.

NyOrka Page 31 12/18/2008Figure 14 shows similar analysis for cost of 1kg compressed hydrogen produced bysteam reforming within the CUTE boundary conditions (7 kWh natural gas per Nm 3hydrogen produced) see also Table 13. Costs for natural gas are set as 5ct/ kWh andelectricity of 10 ct/ kWh. The upper red line indicates the cost within the CUTEdemonstration boundary conditions which have been used as if the on site steam reformerwas to be operated at full load (4,7 kWh natural gas per Nm 3 hydrogen produced).The non operational cost proportional to total costs for steam reforming is greater than50% in all scenarios. They are therefore important when performing an economicanalysis of on-site hydrogen production. The cost for electricity does not influence theoverall share of the non operational cost significantly. This is based on the fact that theratio for the actual CUTE consumption figures the ratio of the gas to electricityconsumption is 7:1.Site preparationInvestment storageoperationElectricity costs: 10 ct per kWhInvestment Electrolyser, compressor, dispenserMaintenance infrastructure€ per kg hydrogen~ 3,4 €~ 1,7 €20 €18 €16 €14 €12 €10 €8 €6 €4 €2 €0 €min average maxDiesel 120 MJincl. taxw/o taxFigure 13 Measured cost of Equipment, site preparation, investment and operation cost (2005) forelectrolyser per kg hydrogen; electricity cost = 10 ct/ kWh; Nitrogen cost = 0,5 €/ Nm 33838 Wittstock Bastian, Michael Faltenbacher; 2007, del 1.5: Report on the findings regarding optimised hydrogen purity.EC funded project: HyFLEET:CUTE, contract no 2/161. TREN/05/FP6EN/ S07.52298/019991

NyOrka Page 32 12/18/2008Site preparationInvestment storageoperationInvestment Electrolyser, compressor, dispenserMaintenance infrastructure20 €18 €16 €14 €12 €10 €8 €6 €4 €~ 3,4 €~ 1,7 € 2 €0 €€ per kg hydrogen4,7 kWh gas/ Nm 3 H 2- full load -4,7 kWh gas/ Nm 3 H 2- full load -min average max4,7 kWh gas/ Nm 3 H2- full load -Diesel 120 MJincl. taxw/o taxFigure 14 Measured cost of equipment, site preparation, investment and operation cost (2005) for asteam reformer per kg hydrogen – electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh;nitrogen cost = 0,5 €/ Nm 3 .As mentioned, the criteria for purity of the hydrogen used with different types of fuelcells may add cost. Direct cost effects are, for instance, increased costs of monitoringdevicesor increased costs for external analyses. Indirect cost effects are reducedproduction quantities for a tighter specification. The effects are shown on Figure 15 39 .Figure 15 Cost burden from hydrogen purfication criteria39 HyFLEET:CUTE, Del no 1.5 Wittstock Bastian and Michael Faltenbacher: Reporting on the findingsregarding optimised hydrogen purity Nov 2007

NyOrka Page 33 12/18/20084.4 Future scenarios – cost comparisonReferring to the policy chapter and European alternative fuels policy then hydrogenshould constitute 2% of the fuel market by 2015 (and 3% by 2020). 170 hydrogen plantseach with 10 times greater capacity of most current stations or 600Nm3 are needed tofeed about 12500 hydrogen buses into this scenario, according to given parameters in thecharacter of buses 40 . Still the NEEDS project does not account for transport energy, thestationary fuel cells would mostly run on less pure feed stock. As shown in section 4.3the cost of hydrogen production depends to a high extent on the rate of the neededfeedstock, natural gas for reformation or price of electricity and water availability forelectrolysis. (Water can be collected from vehicles and reused). The production qualityfluctuates somewhat between these two production methods but PEM fuel cells are amore likely candidate to be used with hydrogen that is made from dump-load power fromfluctuating RE (grid) systems whereas they are more flexible in operation.When setting the price of electricity at 0,10€ as the mean cost of electricity from RE assuggested in a recent report made for the European renewable energy council 41 , a costcalculation can be presented as which production technology is preferable in fluctuatingpower settings. No increase in life time has been incorporated in the hydrogen productionstations but an expected learning curve decrease of cost (similar to the foreseen costreduction as are presented in the Hy-Ways European Hydrogen Road map p15) has beenincorporated as these 170 sites are inaugurated as well as 375.000€ for site preparation ineach case and similar costs for storage for the two types of hydrogen production.When comparing the hydrogen production costs calculated in this study with costnumbers provided by other studies it is essential to carefully consider the boundaryconditions that have been applied. These figures relate to actual measured data withrunning first generation equipment and the parameters for future forecasting are alsorestricted to specific boundaries. Note that while using eventually electricity that isdumped from renewable generation the price of electricity may be set less than 10€c.Table 13 shows the boundary conditions on which the calculations for on-site hydrogenproduction stations are based and refer to CUTE project conditions as presented by MarcBinder and Michael Faltenbacher 42 . The relevant economic parameters are shown inTable 14.40 These assuptions are listed in deliverable 6 page 2641 EREC (European renewable energy council) 2006: Renewable (r)evoltution; a sustainable oecd europe energy p. 2942 Binder Marc and Michael Faltenbacher ; Economic Analysis of the hydrogen infrastructure , Clean Transport forEurope, deliverable 6. EC funded project no NNE5-2000-113

NyOrka Page 34 12/18/2008Table 13 Boundary conditions for electrolyser and steam reformer set for comparison of productioncost of hydrogen.ElectrolyzerSteam ReformerTime of operation 20 years 20 yearsUsage (total filling station)electricity [kWh/ Nm 3 ]CUTE ∅: 5,8 [kWh/ Nm 3 ]Future scenario: 5,5 [kWh/ Nm 3 ]CUTE ∅: 1,0 [kWh/ Nm 3 ]Future scenario: 0,6 [kWh/ Nm 3 ]natural gas [kWh/ Nm 3 ] -----CUTE ∅: 7,0 [kWh/ Nm 3 ]CUTE (full load): 4,7 [kWh/ Nm 3 ]Future scenario: 4,2 [kWh/ Nm 3 ]nitrogen [Nm 3 / Nm 3 ] 0,015 [Nm 3 / Nm 3 ] 0,12 [Nm3/ Nm3]average utilization [capacity] 95% 95%down days per year 10 days 10 daysMaintenanceReformer modul -----replacementonce during lifetimeElectrolyser modul once during lifetime -----Mol Sieve once during lifetime once during lifetimeCatalyst of reformer module ----- every 5 yearsActivated carbon ----- depends on sulphur contentDeoxo catalyst every 3 years -----Compressorservice intervals between 4 month (min) to 2 years (max), dependend oncompressor type and input pressureTable 14 Parameters that are used to scale up future cost reduction potentialsParameter name description Electrolyser Steam ReformerIRR [% pa] Internal rate of return 12 12P [ ] Factor of cost decrease - learning curve 0,9 0,96-tenth factor upscaling 0,7 0,6use_time [a] Utilization period 20 20use_ratio [%] Utilization ratio 95 95Downdays [d] Down time in days per year 10 10Figure 16 three areas represent the cost of hydrogen production correlated with a range ofcost for natural gas.1) Blue area: When costs of gas is in the range of 0,035 and 0,103€/kWh thensteam reformation would be less costly than electrolysis where electricity priceis set at 0.1€/kWhAll steam reforming scenarios (min, average and max indicated by three red horizontallines) are less cost- intensive compared with the respective electrolyser min scenarios.2) Cyan area: When cost of gas is in the range of 0,103 and 0,127€ the cost ofhydrogen production depends on equipment, maintenance and preparationcost, which can vary between sites and manufacturers:Within this range the overall equipment, maintenance and preparation costs are decisivein determining the preferable hydrogen production technology.3) Yellow area: If price of gas is above 0,130€ then electrolysis is cheaper

NyOrka Page 35 12/18/2008All steam reforming cost scenarios (min, average and max) are more cost intensivecompared with the respective electrolyser max scenarios.Electrolyzer min Electrolyzer average Electrolyzer maxSteam Reformer min Steam Reformer average Steam Reformer maxResults for 0,1 € per kWh electricity14€ pro kg hydrogen12108642prosteam reformerdependent onoverall equipment,maintenance andpreparation costspro electrolyzerSR maxSR minElec maxElec min00,0350,0450,0550,0650,0750,0850,0950,1050,1150,1250,1350,1450,1550,165€ per kWh natural gasFigure 16 Future scenario: Reformer – Electrolyser; cost for electricity set at 0,10 € per kWhWhen the cost for electricity and natural gas is within this range, a detailed analysis of thenon operational cost is necessary to determine the preferable technology. The price ofnatural gas has slowly been rising since 1975 but peaked in October 2005. Also to benoted: competitiveness would if course also be skewed by diesel prices, such as were tobe found in 2008.4.5 Price trends in futureOther influential costs for the production are material costs of stainless steel (with Nickeland Chromium being the key alloying elements) and copper, and to a reduced extend alsoaluminium. Purification costs and quality monitoring of hydrogen made with eithermethod should not be neglected. These may amount to 12-13% of the production costsusing either steam reformation or electrolysis. Hydrogen infrastructure equipment willbecome more costly with higher energy prices.The energy conversion cannot be improved very much for the low temperatureelectrolysers. The conversion efficiency of today’s electrolysers is already high andtherefore basic research should address areas where a significant cost reduction inhydrogen costs can be achieved. The only way to reduce the energy consumption furtherwould be to increase the process temperature (e.g. to 800° C). This, so called hightemperature electrolyser, has great energy savings but substantial material challenges.Adding pressure only keeps the volume of the generated hydrogen down and would savespace and therefore land use.

NyOrka Page 36 12/18/2008The following areas or topics should therefore be considered:• Increasing efficiency and stability of electrodes for alkaline electrolysers to obtainincreased current density and possibly reduce cell voltage throughout. The watermolecule can be split at 1,23 volts at the ideal high heat conditions instead of1,48volts in the current lye electrolysis.o Catalyst research, with the aim of reducing the use of precious material.o Electrode design – zero gap and porosity of electrode with effective transportof gas from the electrode,• Synthetic materials research to increase durability and lifetime, particularly if highheat is used to substitute for a part of the electricity.• Diaphragm material research to achieve synthetic materials with low resistance andhigh threshold pressure€ per kg hydrogen18 €16 €14 €12 €10 €Site preparationInvestment storageoperation8 €6 €4 €2 €0 €CUTE ∅ status quoElectricity costs: 10 ct per kWhCUTE ∅ status quoInvestment Electrolyzer, compressor, dispenserMaintenance infrastructureCUTE ∅ status quomin average maxFigure 17 Composition of cost factors using projected learning effect but based oncurrent yet upscaled technology. Electrolyser scenario 600 Nm3/h and 170 plants;cost per kg hydrogen - electricity cost = 10 ct/ kWh; nitrogen cost = 0,5 €/ Nm3

NyOrka Page 37 12/18/2008Site preparationInvestment storageoperationInvestment Reformer, compressor, dispenserMaintenance infrastructure€ per kg hydrogen18 €16 €14 €12 €10 €8 €6 €4 €2 €CUTE ∅ status quoCUTE ∅ status quoCUTE ∅ status quo0 €min average maxFigure 18 Steam Reformer scenario 600 Nm3/h and 170 plants; cost per kghydrogen. Electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; N2 cost = 0,5€/ Nm3, all using foreThe cost comparison made within the CUTE /HyFLEET:CUTE project indicates thatnon-operational cost are likely to decrease in the future. This is due to decreased cost ofthe other than operational cost as a result of up-scaling and learning curve effects anddecrease of operational cost resulting from an increase of energy efficiency in the future.On the other hand, if the electricity that is used to operate the electrolysis is ratherrescued or “dumped pðewer” rather than bought, the price may become even lower.4.5.1 The potential role of hydrogen in a future energy supply systemIn January 2007 the project Encouraged 43 published its results from looking into thepotential import of gas, hydrogen and electricity to Europe. The report builds on the Hy-Ways scenarios for hydrogen which are still in formulation. The forecast outlines twoalternative market development scenarios – High (corresponding to ‘Very optimisticscenario’) and Low (‘realistically optimistic scenario’) until 2050. The most pessimisticscenario would then be the one which is foreseen in the EU Energy trends policy paper(2003): European Energy Outlook and Transport – Trends to 2030, which states that oilproducts keep their market share at least until 2030. Hydrogen is neither mentioned foruse in stationary CHP application nor as fuel for transport 44 . According to the pessimisticscenario the penetration would be 0 by 2030. A different scenario was presented from theHy-Ways project, s European Hydrogen Roadmap 45 as shown in Table 1543 Energy corridor optimisation for European Markets of Gas, Electricity and Hydrogen (ENCOURAGED, project no:006588, 6 th Framework Program, Scientific Support Policy (3.2). Project manager Martin Wietschel, Frauenhofer ISI44 European Commission Directorate-General for Energy and Transport, 2003: European energy and transport trends to2030. Prepared by National Technical University of Athens, E3Mlab45 Hy-Ways, European Hydrogen Roadmap available at: www.HyWays.de

NyOrka Page 38 12/18/2008Table 15 Total share of hydrogen vehicles according to the Hy-Ways scenarios; Pessimistic – veryoptimistic scenario. A Realistically optimistic would set hydrogen penetration at 2% of the vehiclefleet by 2020 and up to 50% in 2050.Total share of carfleet [%]2010* 2020 2030 2040 2050High 1 4 8 10Low penetration - 0,1 0,5 2 5Total share in 2010 2020 2030 2040 2050commercial sectorHigh penetration - 0,3 1,3 2,7 3,3Low penetration - - 0,2 0,7 1,7The ‘HyWays Low penetration scenario’ envisions only 5% of all households areassumed to have a 1 kW e system installed. In northern countries, micro-CHP is assumedto be mainly used for space heating where district heating has not been installed, but insouthern countries more for cooling. In addition the total hydrogen-based CHP installedin the tertiary sector (i.e. offices) is assumed to be 30% of the total power in theresidential sector. Intermediate values for 2020, 2030 and 2040 are derived through (nonlinear)interpolation.It is worth noting, that system design which is currently in development for example inEurope, USA and Japan (Figure 19) it may be unrealistic to separate between hydrogenand stationary and transportation applications. A systematic approach could raise totalenergy chain efficiency. The one in figure 16 is composed of electrolysis, heatmanagement and fuel cells. Hydrogen is made with off peak electricity, either from thegrid or local renewable installations. Heat goes to temperate a well insulated officebuilding and the hydrogen to power its equipment and fill staff vehicles. If Hydrogen isproduced on distributed sites, the fuel would both be used in the building and to fillvehicles of the company or the staff that works in the area, but the demand may besaturation.

NyOrka Page 39 12/18/20084.5.2 Integrated systemsThe efficiency of an energy chain that starts with renewable energy and ends withhydrogen for use in various applications may never be able to compete with theinfrastructure and well to tank efficiency provided in the carbon era. Yet the source forrenewable energy is said endless and the water becomes recyclable. The efficiencycriteria do not prevent the use of the unlimited sources. Some of the most advancedstudies in integrated, diversified and flexible systems are currently undertaken in Japanwhere research has been looking into raising efficiency in integrated systems not only inseparate components. The cleanliness and the flexibility of using hydrogen is considereda driver because of added customer value and new opportunities for the Japaneseindustry 46 .Figure 19 A hydrogen test system that is intended to monitor and raise total energy efficiency.5 Technology development perspectivesHydrogen storage and transportation, system efficiency as well as material developmentare the most important points for hydrogen technology development. The electrolyserswill go through high pressure to high heat and pressure electrolysers but in the far futureelectrolysers are foreseen to merge with fuel cells.Transportation of hydrogen is bound to be ineffective in small amounts, especially in thegaseous phase. Liquefaction decreases efficiency by 10 – 15%. Transferring electricity islikely to interact with distribution of hydrogen and vice versa. Kozawa et al have46 OKAMOTO Hideyuki, Yoshiaki KAWAKAMIP, Yoshiyuki KOZAWA, Makoto AKAIP P Total Energy SystemEngineering by Coring Metal Hydride Tanks

NyOrka Page 40 12/18/2008proposed that even though the contemporary fuel cells only display 50% conversionefficiency this can be optimized through other system components. If the surface area andthickness of a reversible PEM stack is adjusted, counter current flow of the oxygen andhydrogen implemented and specific design deployed to keep the humidity at around 60%(plus the heat which is released is put to full use), then the efficiency of the whole systemcould reach 80% in the full cycle (electricity – hydrogen – electricity and heat) 47 . Thosefigures give a real competitive edge against current thermal power systems. PEMelectrolysersHydrogen storage has been under securitization for several decades. The US Departmentof Energy has set the target for 6.5% hydrogen weight of the storage medium. Sodium-Borohydrides (NaBH 4 ) (recyclable solid hydrogen carrier 48 ), metal hydride mixtures,carbon mircrofibres, glass microstructures, salt-pellets soaked with ammonia,liquefaction and even soap solutions have been reported as possible storing agents 49 , 50 .Currently high pressure tanks made from steel and strengthened with carbon-fibercoatings have evolved most rapidly and are used by most car manufacturers.Hydrogen distribution has been foreseen by trucking in for small markets, (pressurized)gas pipe systems for lager market 51 or liquefaction and transportation in barge ships overlarger distances. These keep the hydrogen in enormous spheres that can be kept in dockwhile the hydrogen flow is connected to a land based piping system.Synthetic materials together with high pressure applied in the cell stacks on electrolysers,prove to be more capable of handling fluctuations in power input and are thereforeespecially suitable in combination with renewable energy sources. These types ofelectrolysers have become available in the market during the last decade, but mainly forsmall capacities. The future challenge for these materials will be to cope with higherpressure and larger capacity electrolysers.The PEM electrolyser was introduced to the market recently, but only for small capacities(Proton’s cell stack is currently max. 2 Nm3/h). The energy consumption is high and thelifetime of the cell stack or MEA (Membrane Electrode Assembly) is a challenge. Forlarge units the KOH or alkaline electrolysis under 30atm pressure is still seen as the mostefficient solution.Whereas data is available for the inventory of the Norsk Hydro electrolyser, that type hasbeen selected as a representative in the detailed study. It is said to have the highest energyefficiency including compression. The future NH types of electrolysers will be used as an47 Kosawa Yoshiyuki 2004: Pioneering of Genral purpose uses of hydrogen as a possible energy carrier in the future,Energy and resources, 25. no 5.48 Millienium cell gives a description of NaBH4 characteristics www.millenniumcell.com/fw/main/Hydrogen_as_Fuel-30.html49 A good overview is given by Fuel cell store refer to: http://fuelcellstore.com/information/hydrogen_storage.html50 Korean researches reported to Nature November 200551 Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery mode article pending to bepublised in the international journal of hydrogen energy.

NyOrka Page 41 12/18/2008example of the trends but comments have been sought from developmental experts inorder to ground the realistic possibilities.This is the essence of the hydrogen handling chain; it is likely to be produced locallyfrom various sources, transported minimally unless it is generated as a by-product inindustry or produced centrally from gas or other carbon sources where the carbon dioxidecan be sequestrated as well. All extra handling poses extra costs because of the lowenergy density pr volume hydrogen. Large electrolytic centers will therefore beconnected to nuclear power stations and gasification, but smaller units, even local (home,office buildings, and community centers) power stations may be coupled to off gridrenewable energy conversion equipment.As of yet, the hydrogen technology is in rapid development and therefore investments inlarge systems has not occurred; investors are waiting for more mature components. Pricefor petrol and decreased cost of an entire new infrastructure must give added value to theinvestors and the public before major changes will occur. The bio-fuel chain still has astronger stand on the world market as a newcomer in the environmental technologysector.Usually electricity is the only source of energy used in electrolysis. But the process isexothermic. It has been shown that the electrical energy can at least partially be replacedby heat. 52 Research is ongoing on high heat electrolysis, but when electrolysis is carriedout in temperatures above 700°C 10 – 20% of the electricity can be saved. Currently thecost and efficiency of electrolysis is not competitive to using steam reforming fromcarbon containing fuel.A reversible fuel cell /electrolyser has been demonstrated as an experimental unit.6 Specification of future technology configurationsTable 17 Hydrogen production technology datasheet: Electrolysis 53ELECTROLYSIS (30 BAR OUT) 2020 UnitSpecific hydrogen capacity (out) 2.500 kW(H 2 )Specific investment cost 500 €/kWTotal investment 1.250.000 €Annual operating hours 8.000 h/aLifetime 20 aAnnual hydrogen production 20.000.000 kWh(H 2 )/aOperation and Maintenance 1,5 % of investmentAnnual Operation and maintenance 100.000 €/aAnnuity 127.315 €/aTotal annual cost 146.065 €/aEfficiency (electricity-hydrogen) 70 %Input electricity 1,4286kWh(El.)/kWh(H2)Output hydrogen 1 kWh52Mansilla1 Christine, Jon Sigurvinsson1, André Bontemps, Alain Maréchal, François Werkoff: Heat management forhydrogen production by high temperature steam electrolysis, CEA, 200553 HySociety, 2003, Basic table of carriers and barriers, edited and updated by FhG-ISI, 2005 and Icelandic NewEnergy 2006

NyOrka Page 42 12/18/20087 ConclusionsThe first 8 years of this millennium have provided evidence that new energy carriers areessential to substitute the fossil fuel supply chain that mankind has depended on for 150years. Several millennia before that time all economy used solar energy and its derivedforces. Eventually all direct forms of solar power will substitute the energy that had beentrapped by photosynthesis and geological pressure into energy rich carbon compounds.When this era arrives, hydrogen will be used as the most flexible energy vector. In themeantime technological advancements need to raise energy efficiency along the deliverychain but the environmental effectiveness to deliver power without environmentaldamage is inherent in hydrogen as long as it is correctly handled.

NyOrka Page 43 12/18/20088 ReferencesAndreas Hofer Hochdrucktechnik GmbH 2006: Diaphragm Compressors – Models.www.andreas-hofer.de/english/htm/produkte/kompressoren_membran2.htmEC 2003, High level group to the commission: Hydrogen and fuel cells a vision of ourfutureEC Directorate-General for Energy and Transport, 2003: European energy and transporttrends to 2030. Prepared by National Technical University of Athens, E3MlabEC funded project HY-FLEET:CUTE See further at www.global-hydrogen-busplatform.comEC funded project: Euro Hyport, Ingolfsson Hjalti P.; Feasibility study for the export ofhydrogen from Iceland to the European continent, 2003 WP2 hydrogen Production andWP3 Transport of hydrogenEC funded project: Hy-Approval, handbook of hydrogen stations is still a livingdocument, whereas the content has not been approved in all European stateswww.hyapproval.org/publications.htmlEC funded project: HyFLEET:CUTE European project no:EC funded project: HySociety, 2003, Basic matrix of social carriers and barriers in theintegration of hydrogen; Matrix edited and updated by FhG-ISI, 2005 and Icelandic NewEnergy 2006EC funded project: HyWays – a hydrogen road map for Europe: www.HyWays.deEC supported project no: 006588, 6 th FP: ENCOURAGED, Scientific Support PolicyProject manager Martin Wietschel, Frauenhofer ISIEC supported project: Clean Transport for Europe CUTE; Faltenbacher Michael, PEInternational 2006, report on LCA of hydrogen production within CUTE cities, status ofreport is confined to partners.EC supported project: CUTE, NNE5-2000-113, Clean Transport for Europe, Binder,Marc and Michael Faltenbacher; 2007 Economic Analysis of the hydrogen infrastructure,deliverable 6.EC: Hydrogen Energy and Fuel Cells, a vision of our future, final report of the high levelgroup, p 12. Directorate-General for Energy and Transport. EUR 20719Encyclopaedia Britannica www.britannica.com

NyOrka Page 44 12/18/2008EREC (European renewable energy council) 2006: Renewable (r)evoltution; asustainable OECD Europe energy p. 29 A report compiled by Greenpeace for the council.EurActiv EU news, policy positions and EU Actors online; 9th of Marchwww.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=NewsEuropean news, www.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=NewsFuel cell store; Overview for hydrogen storage options is given by:http://fuelcellstore.comGudmundsdottir Lilja (2008): Analysis of the electric grid in Reykajvik, Greenland andFaroe Islands, MSc project at the University of Iceland, financed by the North AtlanticHydrogen Association.Hy-Nor: Nordic hydrogen highway connecting 3 countries. Ulfs Hafseld: presentation atthe North Atlantic Hydrogen Association, Reykjavik May 2008.IEA and OECD: Prospects for hydrogen and fuel cells 2005. The table is stated to becompiled from Prince-Richards S(2004) a Techno-Economic Analysis of DecentralizedHydrogen productin. University of Victory Canada and Stuart 2005 Vanderborre IMETtechnology characteristics, Stuart energy, www.stuartenergy.comJones, G: Wind-hydrogen diesel Energy Project at Ramea Newfoundland, presentationheld at the North Atlantic Hydrogen Association conference, 25th of April 2008.Kauffman Matthew, US department of Energy, presentation during US Electrolysis,2003, Workshop proceedings from Electrolysis production of hydrogen from wind andhydropower, Washington DC. Sept 2003Kerry-Ann (2007) Fuel Cell Today Large Stationary Survey Fuel Cell Today;www.fuelcelltoday.com/Kosawa Yoshiyuki 2004: Pioneering of Genral purpose uses of hydrogen as a possibleenergy carrier in the future, Energy and resources, 25. no 5.LBST: Physical and chemical characteristics of hydrogen and conversion factors or‘Efnis og eðliseiginleikar vetnis’ 2003, Icelandic New Energy:www.newenergy.is/publications.Ludwig Bölkow System, Hydrogen and renewable energy, report available at:www.LBST.deMailänder, Ellen 2003: Life Cycle Assessment (LCA) of Hydrogen Infrastructure forFuel Cell Driven Buses in the Public Transport of Reykjavik. StudiengangUmweltschutztechnik, University of Stuttgart.

NyOrka Page 45 12/18/2008Mansilla1 Christine, Jon Sigurvinsson1, André Bontemps, Alain Maréchal, FrançoisWerkoff: Heat management for hydrogen production by high temperature steamelectrolysis, CEA, 2005Millienium cell: NaBH4 characteristics www.millenniumcell.com/fw/main/Minns David (editor) APEC 2030 Integrated Roadmap Nov 2005: Future fuels for theAsian Pacific Economic Cooperation regionNature, November 2005 Short News, Korean researchesNorsk Hydro Electrolysers AS 2006: Appendix A: ECTOS Fuelling Station Description,Norsk Hydro Electrolysers AS 2006: Products – Hydrogen Filling Stations.www.electrolyzers.com.Norsk Hydro Electrolysers AS 2006: Technical Drawings, Hydrogen Filling Station 60Nm3 H2/h for Iceland.Norsk Hydro; Hydro Electrolysers www.electrolysers.comOkamodo Hideyuki, Y Kawakam ip, Y Kozawa, M Akai, Integrated hydrogen modulesTotal Energy System Engineering by Coring Metal Hydride TanksBallard, (March 2006) as presented by Geoff Budd; for CUTE, Scope of Supply, UtilityRequirements, Performance Data. TREN/05//FP&EN/S0755298/019991 deliverable 1.5to be issued for the public in 2009, , Vancouver CanadaUlleberg, Oystein, Susan Schoenung, Maria Maack, Bengt Ridell et al, World HydrogenEnergy Conference, WHEC, Conference paper 2007Ulleberg Oystein, 2008 IFE, Norway for IEA, Hydrogen Implementation Agreement,annex 18; Integrated hydrogen systems, subtask B, simulations of hydrogen systems,www.iea.org / hiaUNDP and DESA; International seminar on the hydrogen economy for sustainabledevelopment; Geothermal Resources, current development and potentialswww.un.org/esa/sustdev/sdissues/energy/op/hydrogen_seminar/hydrogen_seminar_programme.pdfUNEP and DESA and Icelandic Ministry for Industry and Commerce: 29 th Sept 2006International seminar on the hydrogen economy for sustainable development; GeothermalResources, hydrogen seminar/programme.pdfWatson Jim (ed) et al; UK Hydrogen Futures to 2050 Tyndall Centre; Tyndall CentreWorking paper no 46, Feb 2004Winter, Carl-Jochen & Joachim Nitsch, eds 1988; Hydrogen as an energy carrier,technologies, systems, economy (translation from: Wasserstoff als Energieträger)Springer Verlag, Berlin, New York.

NyOrka Page 46 12/18/2008Wittstock Bastian, Michael Faltenbacher; 2007, del 1.5: Report on the findings regardingoptimised hydrogen purity. EC funded project: HyFLEET:CUTE, contract no 2/161.TREN/05/FP6EN/ S07.52298/019991Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery modearticle pending to be publised in the international journal of hydrogen energy.Personal communicationChr. Machens, Hydrogenics, Germany,Christoffer Kloed, Hydro-Statoil April 2008Geoff Budd, Ballard, Vancouver Canada (March 2006)Hjalti P. Ingolfsson, Icelandic HydrogenHolger Grubel, Vattenfall power company Germany (December 13 2006)Iain Alexander Russel, Hydro Elecrtolysers personal communication, 10 th of Dec 2006Jon Björn Skulason, Icelandic New EnergyMonika Kentzler, Daimler, GermanyPietro d’Erasmo; Hydro Elecrtolysers email 10 th of Dec 2006Rouvroy , Steven Shell Hydrogen, HyFLEET:CUTE meeting, May 2008Scott Staily, Ford Motor Corporations, division of fuel cell development , April 25 th inReykjavik9 AnnexTable 4.1: Minimum air pollutant list of the reference plantsParameter Path UnitPresentElectrolytic H2Productionkg GH2Ammonia air kg 4,97E-04Arsenic air kg 1,76E-06Benzene air kg 1,67E-04Benzo(a)pyrene air kg 7,69E-07Cadmium air kg 3,65E-07Carbon dioxide, fossil air kg 2,84E+01Carbon monoxide, fossil air kg 1,36E-02Carbon-14 air kBq 9,62E-01Chromium air kg 8,14E-05Chromium VI air kg 2,00E-06Dinitrogen monoxide air kg 7,17E-04Formaldehyde air kg 4,77E-05Iodine-129 air kBq 9,77E-04Lead air kg 4,12E-03Methane, fossil air kg 4,53E-02Mercury air kg 9,86E-07Nickel air kg 1,95E-05

NyOrka Page 47 12/18/2008Nitrogen oxides air kg 5,19E-02NMVOC air kg 4,82E-03PAH air kg 1,69E-06PM2.5 air kg 7,82E-03PM10 air kg 1,05E-02PCDD/F (measured as I-TEQ) air kg 3,96E-12Radon-222 air kBq 1,70E+04Sulfur dioxide air kg 1,17E-01

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