第三部分：绿氢成本和潜力报告（英）-IRENAVIP专享VIP免费

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GLOBAL HYDROGEN TRADE TO

MEET THE 1.5°C CLIMATE GOAL

PART III

GREEN HYDROGEN COST AND POTENTIAL

Unless otherwise stated, material in this publication may be freely used, shared, copied, reproduced, printed

and/or stored, provided that appropriate acknowledgement is given of IRENA as the source and copyright

holder. Material in this publication that is attributed to third parties may be subject to separate terms of use and

restrictions, and appropriate permissions from these third parties may need to be secured before any use of such

material.

ISBN: 978-92-9260-432-5

Citation: IRENA (2022), Global hydrogen trade to meet the 1.5°C climate goal: Part III – Green hydrogen cost and

potential, International Renewable Energy Agency, Abu Dhabi.

Acknowledgements

This report was authored by Jacopo de Maigret, Edoardo Gino Macchi (Fondazione Bruno Kessler) and Herib

Blanco (IRENA) under the guidance of Emanuele Taibi and Roland Roesch. Technical support was provided by

Luca Pratticò (Fondazione Bruno Kessler). The report was produced under the direction of Dolf Gielen (Director,

IRENA Innovation and Technology Centre).

This report beneﬁted from input and review of the following experts. David Armaroli, Filippo Bartoloni, Paola

Brunetto, Ludovico Del Vecchio, Lodovico Della Chiesa d’Isasca, Matteo Moraschi, Michele Scaramuzzi, Irene

Varoli, and Marco Zampini (Enel); Carlo Napoli (Enel Foundation), Laurent Antoni (French Alternative Energies

and Atomic Energy Commission), Georgia Kakoulaki (Joint Research Centre), Bilal Hussain and Paul Komor

(IRENA), Brandon McKenna (Mærsk Mc-Kinney Møller Center for Zero Carbon Shipping).

The report was edited by Erin Crum.

Report available online: www.irena.org/publications

For questions or to provide feedback: publications@irena.org

IRENA is grateful for the scientiﬁc support from the Enel Foundation and the Fondazione Bruno Kessler in

producing this publication.

IRENA is grateful for the support of the Ministry of Economy, Trade and Industry (METI) of Japan in producing

this publication.

Disclaimer

This publication and the material herein are provided “as is”. All reasonable precautions have been taken by IRENA to verify the

reliability of the material in this publication. However, neither IRENA nor any of its ocials, agents, data or other third-party

content providers provides a warranty of any kind, either expressed or implied, and they accept no responsibility or liability for

any consequence of use of the publication or material herein.

The information contained herein does not necessarily represent the views of all Members of IRENA. The mention of speciﬁc

companies or certain projects or products does not imply that they are endorsed or recommended by IRENA in preference to

others of a similar nature that are not mentioned. The designations employed and the presentation of material herein do not

imply the expression of any opinion on the part of IRENA concerning the legal status of any region, country, territory, city or

area or of its authorities, or concerning the delimitation of frontiers or boundaries.

GLOBAL HYDROGEN TRADE TO MEET THE 1.5°C CLIMATE GOAL:

PART III – GREEN HYDROGEN COST AND POTENTIAL 3

TABLE OF CONTENTS

ABBREVIATIONS 5

EXECUTIVE SUMMARY 6

CONTEXT OF THIS REPORT ANDWHAT TO EXPECT 9

1 INTRODUCTION 12

2 METHODOLOGY 15

Geographical constraints and exclusion criteria 17

Techno-economic assumptions 19

3 LEVELISED COST OF HYDROGEN AROUND THEWORLD 24

Optimal combination of renewable energy sources and electrolysers 25

Global LCOH maps and potential 31

REFERENCES 41

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GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOALPARTIIIGREENHYDROGENCOSTANDPOTENTIAL©IRENA2022Unlessotherwisestated,materialinthispublicationmaybefreelyused,shared,copied,reproduced,printedand/orstored,providedthatappropriateacknowledgementisgivenofIRENAasthesourceandcopyrightholder.Materialinthispublicationthatisattributedtothirdpartiesmaybesubjecttoseparatetermsofuseandrestrictions,andappropriatepermissionsfromthesethirdpartiesmayneedtobesecuredbeforeanyuseofsuchmaterial.ISBN:978-92-9260-432-5Citation:IRENA(2022),Globalhydrogentradetomeetthe1.5°Cclimategoal:PartIII–Greenhydrogencostandpotential,InternationalRenewableEnergyAgency,AbuDhabi.AcknowledgementsThisreportwasauthoredbyJacopodeMaigret,EdoardoGinoMacchi(FondazioneBrunoKessler)andHeribBlanco(IRENA)undertheguidanceofEmanueleTaibiandRolandRoesch.TechnicalsupportwasprovidedbyLucaPratticò(FondazioneBrunoKessler).ThereportwasproducedunderthedirectionofDolfGielen(Director,IRENAInnovationandTechnologyCentre).Thisreportbenefitedfrominputandreviewofthefollowingexperts.DavidArmaroli,FilippoBartoloni,PaolaBrunetto,LudovicoDelVecchio,LodovicoDellaChiesad’Isasca,MatteoMoraschi,MicheleScaramuzzi,IreneVaroli,andMarcoZampini(Enel);CarloNapoli(EnelFoundation),LaurentAntoni(FrenchAlternativeEnergiesandAtomicEnergyCommission),GeorgiaKakoulaki(JointResearchCentre),BilalHussainandPaulKomor(IRENA),BrandonMcKenna(MærskMc-KinneyMøllerCenterforZeroCarbonShipping).ThereportwaseditedbyErinCrum.Reportavailableonline:www.irena.org/publicationsForquestionsortoprovidefeedback:publications@irena.orgIRENAisgratefulforthescientificsupportfromtheEnelFoundationandtheFondazioneBrunoKesslerinproducingthispublication.IRENAisgratefulforthesupportoftheMinistryofEconomy,TradeandIndustry(METI)ofJapaninproducingthispublication.DisclaimerThispublicationandthematerialhereinareprovided“asis”.AllreasonableprecautionshavebeentakenbyIRENAtoverifythereliabilityofthematerialinthispublication.However,neitherIRENAnoranyofitsofficials,agents,dataorotherthird-partycontentprovidersprovidesawarrantyofanykind,eitherexpressedorimplied,andtheyacceptnoresponsibilityorliabilityforanyconsequenceofuseofthepublicationormaterialherein.TheinformationcontainedhereindoesnotnecessarilyrepresenttheviewsofallMembersofIRENA.ThementionofspecificcompaniesorcertainprojectsorproductsdoesnotimplythattheyareendorsedorrecommendedbyIRENAinpreferencetoothersofasimilarnaturethatarenotmentioned.ThedesignationsemployedandthepresentationofmaterialhereindonotimplytheexpressionofanyopiniononthepartofIRENAconcerningthelegalstatusofanyregion,country,territory,cityorareaorofitsauthorities,orconcerningthedelimitationoffrontiersorboundaries.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL3TABLEOFCONTENTSABBREVIATIONS5EXECUTIVESUMMARY6CONTEXTOFTHISREPORTANDWHATTOEXPECT91INTRODUCTION122METHODOLOGY15Geographicalconstraintsandexclusioncriteria17Techno‑economicassumptions193LEVELISEDCOSTOFHYDROGENAROUNDTHEWORLD24Optimalcombinationofrenewableenergysourcesandelectrolysers25GlobalLCOHmapsandpotential31REFERENCES414FIGURESFIGURE0.1.Globalsupply-costcurveofgreenhydrogenfortheyear2050underoptimisticassumptions7FIGURE0.2.ScopeofthisreportseriesinthebroadercontextofIRENApublications9FIGURE1.1.Typesofrenewableenergypotentialsandapplicableconstraints13FIGURE2.1.Landtypedistributionandsuitabilityforvariablerenewableenergyforaselectionofcountries18FIGURE2.2.Percentageoflandexcludedforonshorewind(left)andutility-scalePV(right)duetolandexclusioncriteria19FIGURE2.3.Full-loadhoursachievabledependingonareaforoffshorewinddeploymentintheNorthSea(andexpectedyieldinterawatthours)21FIGURE2.4.Capitalcosttrendsforrenewabletechnologiestowards2050underoptimisticassumptionsandbenchmarkwithotherstudies22FIGURE2.5.RangeofWACCbytechnologyandscenario23FIGURE3.1.Comparisonbetweenlevelisedcostofsolar-andwind-producedhydrogenasfunctionofannualcapacityfactorandoptimalratio26FIGURE3.2.DifferenceinonshorewindpotentialbyresourcequalityinChile,GermanyandSaudiArabia(inGW)27FIGURE3.3.RelationshipbetweenLCOHandrenewabletoelectrolysercapacityasafunctionofcapacityfactorfor2030and205029FIGURE3.4.Optimalhybridsystemconfigurations(dots)in2050asafunctionofCAPEXofthegenerationtechnologiesforGermany(greenlines)andAustralia(bluelines)30FIGURE3.5.Breakdownofhydrogenproductionbyrenewabletechnologyforselectedcountries31FIGURE3.6.ComparisonbetweeneconomicpotentialofgreenhydrogensupplybelowUSD2/kgH2andforecasthydrogendemand,inEJ/year,by205032FIGURE3.7.Globalmapoflevelisedcostofgreenhydrogenin2030consideringwaterscarcity33FIGURE3.8.Ratiobetweenthepotentialdomesticproductionofgreenhydrogenandthepredicted2050hydrogendemandforcountrieswithhighestforecasthydrogendemandin205034FIGURE3.9.Greenhydrogensupply-costcurvesforselectedAfricancountriesin205036FIGURE3.10.Levelisedcostofhydrogenrangein2050derivedfromsupply-demandanalysis37FIGURE3.11.Globalsupply-costcurveofgreenhydrogenfortheyear2050underoptimisticassumptions38FIGURE3.12.Globalmapoflevelisedcostofgreenhydrogenin2050consideringwaterscarcity39FIGURE3.13.Effectofwaterconstraintsonlandeligibilityforonsiteproductionofgreenhydrogen40TABLESTABLE3.1.Classificationofresourcequalityforeachrenewabletechnology25BOXESBOX2.1.Impactofoffshorewindcapacityexpansiononcapacityfactor20BOX3.1.Africa’sgreenhydrogenpotential34GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL5ABBREVIATIONSCAPEXcapitalexpenditureCFcapacityfactorECMWFEuropeanCentreforMedium-RangeWeatherForecastsEJexajouleFLOHfull-loadoperatinghoursG20Groupof20GWgigawattHHVhigherheatingvalueIRENAInternationalRenewableEnergyAgencykgH2kilogramsofhydrogenkm2squarekilometrekWkilowattkWekilowattelectrickWhkilowatthourLCOElevelisedcostofelectricityLCOHlevelisedcostofhydrogenm3cubicmetreMENAMiddleEastandNorthAfricaMtH2milliontonnesofhydrogenMWmegawattMWhmegawatthourOPEXoperationalexpenditurePVphotovoltaicTWterawattUSDUnitedStatesdollarsWACCweightedaveragecostofcapital6EXECUTIVESUMMARYHydrogenisanessentialcomponentofanetzeroenergysystem.Itprovidesanalternativetodecarbonisesectorsthataredifficulttoelectrifysuchasheavyindustryandlong-haultransport.Electrolytichydrogenproducedthroughrenewables(greenhydrogen)isthemostsustainablehydrogenproductiontechnology.Itallowssectorcouplingwiththepowersectorprovidingadditionalflexibilitytointegratevariablerenewableenergy,anditprovidesanalternativeforseasonalstorageofenergyandprovisionofcapacityadequacy.Oneofthemainchallengesthatgreenhydrogenfacestodayisitshighercostcomparedwithfossilfuelsandotheralternativelow-carbontechnologies.Withtechnologyinnovationtoimproveperformance,deploymenttoincreaseglobalscale,largerelectrolyserplantsandcontinuousdecreaseinrenewablepowercost,whichisthemaincostdriver,greenhydrogenisexpectedtoreachcostparitywithfossil-derivedhydrogenwithinthenextdecade.Thisreportexplorestheglobalcostevolutionofgreenhydrogentowards2030and2050.Forthis,ageospatialapproachisusedsincetherenewableresourcesarehighlydependentonthelocation.Theworldisdividedinpixelsofroughly1squarekilometre(km2),andtheoptimalconfigurationamongrenewablegenerationtechnologies(solarPV,onshorewindandoffshorewind)andtheelectrolyserisdeterminedtoachievethelowestproductioncost.Thecostisbasedontheassumptionofdedicated(off-grid)plantsandrefersonlytoproductionwithouthydrogentransporttothecoastlineorpotentialconsumptionsite.Thepotentialforaspecificcountryorregionisbasedonthelandavailable,forwhichvariousexclusionzonesareappliedincludingprotectedareas,forests,wetlands,urbancentres,slopeandwaterscarcity,amongothers.Thisallowsestimatingboththeproductioncostandthepotentialforgreenhydrogenforeveryregion.Thegreenhydrogentechnicalpotentialconsideringtheselandavailabilityconstraintsisstillalmost20timestheestimatedglobalprimaryenergydemandin2050.Greenhydrogenpotential,however,isnotasinglevalue;itisacontinuousrelationshipbetweencostandrenewablecapacity(Figure0.1).Intermsofproductioncost,thisisdirectlydependentonthecostoftherenewableinput(majorcostdriver),theelectrolyserandtheWACC.In2050,almost14terawatts(TW)ofsolarPV,6TWofonshorewindand4‑5TWofelectrolysiswillbeneededtoachieveanetzeroemissionsenergysystem.Thankstothesedeployments,technologycostsareexpectedtodecreasedramaticallybecauseofinnovation,economiesofscaleandoptimisationofthesupplychain.Inthisfuture,greenhydrogenproductioncouldreachlevelsofalmostUSD0.65/kgofhydrogen(kgH2)forthebestlocationsinthemostoptimisticscenario.InamoreGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL7pessimisticscenariowithhighertechnologycosts,stillfor2050,thelowestproductioncostisUSD1.15/kgH2increasingtoUSD1.25/kgH2tomeetademandof74exajoules(EJ)peryear.Whileglobalgreenhydrogenpotentialismorethanenough,therearespecificcountrieswherepotentialisrestrictedandwheredomesticproductionmightnotbeenoughtosatisfydomesticdemand.Duetothenatureoftheirterritory,JapanandtheRepublicofKoreaarethemostrestricted:91%ofJapan’stotalcountrylandand87%oftheRepublicofKorea’stotalcountrylandisexcludedforhydrogenproduction.TheRepublicofKoreawouldneedtouseaboutone-thirdofitsrenewablepotentialtosatisfyitsdomesticenergydemandin2050.However,oncetheelectricityconsumptionisconsidered,thereishardlyanyleftforhydrogenproduction.ThetechnicalpotentialforJapanisabout380gigawatts(GW)ofPVand180GWofonshorewind,whichwouldbeenoughtoproduceabout20milliontonnesofhydrogen(MtH2)peryearofhydrogenbelowUSD2.4/kgH2.Thequalityoftheresourcesisrelativelypoor(lessthan14%forthemajorityofPVandlessthan30%forwind)andmostofthispotentialisusedtosatisfyelectricitydemandratherthanhydrogen.OthercountriesthatwouldrequirearelativelyhighshareoftheirrenewablepotentialtosatisfytheirdomestichydrogendemandareIndia(89%ofthelandisexcludedmainlyduetopopulationdensity,cropland,savannahsandforests);Germany(66%excludedmainlybyforestsandcropland);Italy(62%excludedmainlyduetoslope,populationdensityandcroplands);andSaudiArabia(94%excludedmainlyduetowaterstress).FIGURE0.1.Globalsupply-costcurveofgreenhydrogenfortheyear2050underoptimisticassumptions00.511.522.533.54Levelisedcostofhydrogen(USD/kgH)ChinaRestoftheworldRussianFederationSaudiArabiaSub-SaharanAfricaUnitedStatesArgentinaAustraliaBrazilCanadaMENAregion0200040006000800010000Hydrogentechnicalpotential(EJ/yr)Globalhydrogendemandin2050:74EJGlobalprimaryenergysupplyin2050:614EJNotes:MENA=MiddleEastandNorthAfrica.Optimisticassumptionsfor2050CAPEXareasfollows:PV,USD225/‌kilowatt(kW)toUSD455/kW;onshorewind,USD700/kWtoUSD1070/kW;offshorewind,USD1275/kWtoUSD1745/kW.WACCper2020valueswithouttechnologyrisksacrossregions.ElectrolyserCAPEXandefficiencysettoUSD134/kWeand87.5%(higherheatingvalue[HHV]).Technicalpotentialhasbeencalculatedbasedonlandavailabilityconsideringseveralexclusionzones(protectedareas,forests,permanentwetlands,croplands,urbanareas,slopeof5%[PV]and20%[onshorewind],populationdensityandwaterstress).8Waterisusedasinputtoelectrolysis,anditisperceivedasoneofthecriticalparametersforgreenhydrogenproduction.Inwater-scarceregions,desalinationcouldbeused.Eveninregionsfarfromthecoastline,watertransportcouldbeconsidered,whichwillincreasethecostofwatersupply,butitwillstillrepresentarelativelysmallshareofthetotalhydrogenproductioncost,reachinglevelsofUSD0.05/kgH2andrepresenting1-2%oftheenergyconsumptionoftheelectrolyser.TheregionswherethisconstraintrestrictsthehydrogenpotentialthemostareSaudiArabia(92%reduction);theMiddleEast(83%reduction);Morocco(63%reduction);andtherestofAsia(61%reduction).Eventhen,thepotentialremainsrelativelyvast.ThereducedPVpotentialinSaudiArabiawouldstillbeenoughtoproduceabout190MtH2/yearandMoroccowouldrepresentthesmallestonefromtheseregionsandstillbeabletoproduceabout90MtH2/year.Themainuncertaintiesfortheanalysislieinthecostlevelsand,inparticular,theevolutionofCAPEXforrenewables,andelectrolysisandtheWACCtowards2050.Ontheonehand,technologywillcontinuetoprogress,anddeploymentwillleadtooptimisationofglobalsupplychains,standardisationandfasterexecution.Ontheotherhand,asthesystemtransitionstofixedcapitalassetsratherthanfuels,cyclesincommoditypricessuchastheoneexperiencedin2021canleadtoperiodsofhighercapitalcostsalthoughwithasmallerimpactonenergypricessinceitwouldbeaffectingonlynewassets.Thefloorcostsforthevarioustechnologiesarenotyetknownwithcertainty.IfsolarPVcostcontinuesitsrecenttrendandelectrolysercostsalsoachievelowlevels,PV-dominatedcanbecomemorecost-effective.Multiplecountriesinsub-SaharanAfrica,theMiddleEastandLatinAmericahavevastrenewablepotentialandthemainuncertaintyintheircostlevelsishowmuchtheywillbeabletodecreasetheirhighWACCstowards2050.Thisprovedtobemorecriticalindefiningthecostdifferentialamongcountriesthanthequalityoftherenewableresource.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL9CONTEXTOFTHISREPORTANDWHATTOEXPECTTheGlobalHydrogenTradetoMeetthe1.5°CClimateGoalseriesofreportsisdividedintothreeparts(Figure0.2).Thefirstreportintegratesthesecomponentswiththedemand,analysingvariousscenariosfortechnologydevelopmenttowards2050toassesstheoutlookofglobalhydrogentrade.Italsopresentsshort-termactionstoachievethatlong-termvision(IRENA,2022a).Thesecondpartcoversthestate-of-the-artliteratureforfourdifferenttransporttechnologypathways(IRENA,2022b).Thethird(thisreport)coversthecostandpotentialofgreenhydrogenforvariousregionsandtimehorizonsunderdifferentscenariosandassumptions.TheGlobalHydrogenTradetoMeetthe1.5°CClimateGoalreportseriescomplementsotherIRENApublications.TheWorldEnergyTransitionsOutlook(IRENA,2022c)providesaperspectiveontheroleofhydrogenwithinthewiderenergytransitioninascenarioinlinewitha1.5°Cpathway.Thisoutlookcoversallenergysectorsandincludesthetrade-offbetweenhydrogenandothertechnologypathways(e.g.electrification,carboncaptureandstorage,bioenergy).Theshort-termactionstoenableglobaltradethatareidentifiedintheGlobalHydrogenTradetoMeetthe1.5°CClimateGoalreportareonlythebeginning.FIGURE0.2.ScopeofthisreportseriesinthebroadercontextofIRENApublicationsRoleofhydrogenintheenergytransitionGreenhydrogensupplyHydrogendemandHydrogencarriersandinfrastructureGlobalpowerandgasmodelwithhydrogentradeShort-termactionstoenableglobaltradeGeopoliticsWorldEnergyTransitionsOutlookGlobalhydrogentradetomeetthe1.5°CclimategoalPartI:Tradeoutlookfor2050andwayforwardPartII:TechnologyreviewofhydrogencarriersPartIII:GreenhydrogensupplycostandpotentialEnablingmeasuresroadmapsforgreenhydrogenThisreportGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOALPARTITRADEOUTLOOKFOR2050ANDWAYFORWARDGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOALPARTIITECHNOLOGYREVIEWOFHYDROGENCARRIERSGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOALPARTIIIGREENHYDROGENSUPPLYCOSTANDPOTENTIALEnablingmeasuresareneededtoacceleratehydrogendeployment.Whiletherearemeasuresthatareapplicableatthegloballevel(e.g.certification),someofthemeasureswillbecountry-specificdependingonlocalconditionsincludingenergymix,naturalresourcesandlevelofmitigation10ambition,amongothers.Thus,theglobaltoolboxofenablingmeasuresneedstobeadaptedtothelocalcontext.TheInternationalRenewableEnergyAgency(IRENA)hasalreadyaddressedthisforEuropeandJapan(IRENAandWEF,2021),withmoreregionstobeanalysedinthecomingmonths.Hydrogentradewillbedefinedbynotonlyproductionandtransportcostorcomparisonofdomesticandimportcostbutalsobyotherfactorssuchasenergysecurity,existenceofwell-establishedtradeanddiplomaticrelationships,existinginfrastructure,greenhousegasemissionsandairpollution.Stabilityofthepoliticalsystemwillalsohavealargeimpactonthetradepartnerseachcountrychoosestohave.Therefore,theactualtradepartnerswillprobablylookdifferentfromtheonespresentedinthisreportsincethese“softfactors”arenotconsideredinthemodel,whichisbasedonpurecostoptimisation.Thesegeopoliticalfactorsarecoveredinaseparatereport(IRENA,2022d)aspartofIRENA’sCollaborativeFrameworkonGeopolitics.Thepresentreportassessestheglobalgreenhydrogenproductionoutlookfor2030and2050,basedonageospatialanalysis.Theassessmentregards34globalregions,comprisedofGroupof20(G20)countries(aswellasChile,Colombia,Morocco,Portugal,SpainandUkraine)andmacro‑regionsrepresentingcountryaggregates(forexamplesub‑SaharanAfricaandtheMiddleEast/NorthAfrica).Themethodologysectionintroducesthemodelimplementedfollowedbythequantificationofalandsuitabilityanalysisfortheinstallationofstand-alonesystems,i.e.off-grid,greenhydrogengenerationsystems,withafocusontheimpactoflandtypologyonterraineligibilityfortheinstallationofutility-scalephotovoltaic(PV)andonshorewindparks.Subsequently,techno‑economicassumptionsofthemodelarepresentedastechnicalcharacteristicsofthegenerationtechnologies(utility-scalePV,onshoreandoffshorewind)alongsidethoseoftheelectrolyser.Economicassumptions,whichdefinethescenariotrends,arereportedintermsofcapitalexpenditure(CAPEX)andweightedaveragecostofcapital(WACC).TheCAPEXofthegenerationtechnologiesshowsitsdecreasingtrendbetween2030and2050andvariesamongtheassessedregions,whilethatoftheelectrolyserisassumedtobeequalglobally.ThevaluesofWACC,whichexpresstheriskofinvestmentinthesingleregions,arereportedwithabriefanalysisofitsimpactonthecostofhydrogen.Theimpactoftheabove-mentionedassumptionsisthenquantifiedinthesecondsection,startingwithananalysisofthelevelisedcostofhydrogen(LCOH)andoptimalsystemconfiguration.Inparticular,theindividualeffectsofthegenerationtechnologycapacityfactorsandtechnologyCAPEXarereported.Followingisaconsiderationofthehybridsystems’configuration(systemsinwhichanelectrolyserispotentiallycoupledwithbothsolarPVandonshore)withafocusontheeffectofgenerationtechnologyCAPEXonoptimalhybridconfigurations.Lastly,theglobaloutlookofgreenhydrogengenerationispresented.Globalsupply-costcurvesareshownaccompaniedbymapsillustratingtheglobaldistributionofLCOH.Thesupply-costcurvesservethepurposeofshowinghowinthe2030and2050timehorizons,theglobalsupplyofgreenhydrogenisfullysatisfiedwithcostsbelowUSD2(UnitedStatesdollars)perkilogramofhydrogen(kgH2)in2050.Themapsthenallowvisualisationofthegeospatialallocationofthedifferentregions’LCOH.Allvaluesareputinperspectivewithforecasthydrogendemand.ThisreportispartofIRENA’songoingprogrammeofworktoprovideitsmembercountriesandthebroadercommunitywithexpertanalyticalinsightsintothepotentialoptions,theenablingconditionsandthepoliciesthatcoulddeliverthedeepdecarbonisationofeconomies.Greenhydrogen,beinganindispensableelementoftheenergytransition,isonefocusofIRENAanalysis.RecentIRENApublicationsinclude:GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL11ThesereportscomplementIRENA’sworkonrenewables-basedelectrification,biofuelsandsyntheticfuelsandalltheoptionsforspecifichard-to-abatesectors.ThisanalyticalworkissupportedbyIRENA’sinitiativestoconveneexpertsandstakeholders,includingIRENAInnovationWeeks,IRENAPolicyDaysandPolicyTalks,andtheIRENACollaborativeFrameworkonGreenHydrogen.Theseinitiativesbringtogetherabroadrangeofmembercountriesandotherstakeholderstoexchangeknowledgeandexperience.HYDROGENFROMRENEWABLEPOWERTECHNOLOGYOUTLOOKFORTHEENERGYTRANSITIONSeptember2018www.irena.orgHydrogenfromrenewablepower(2018)Hydrogen:Arenewableenergyperspective(2019)HYDROGEN:ARENEWABLEENERGYPERSPECTIVESEPTEMBER2019Reportpreparedforthe2ndHydrogenEnergyMinisterialMeetinginTokyo,JapanReachingzerowithrenewables(2020)anditssupportingbriefsonindustryandtransportGreenhydrogen:Aguidetopolicymaking(2020)EliminatingCO2emissionsfromindustryandtransportinlinewiththe1.5oCclimategoalREACHINGZEROWITHRENEWABLESGREENHYDROGENAGUIDETOPOLICYMAKINGGreenhydrogencostreduction:Scalingupelectrolyserstomeetthe1.5°Cclimategoal(2020)Renewableenergypoliciesinatimeoftransition:Heatingandcooling(2020)GREENHYDROGENCOSTREDUCTIONSCALINGUPELECTROLYSERSTOMEETTHE1.5°CCLIMATEGOALH2O2RenewableEnergyPoliciesinaTimeofTransitionHeatingandCoolingGreenhydrogensupply:Aguidetopolicymaking(2021)Enablingmeasuresroadmapforgreenhydrogen(2021),incollaborationwiththeWorldEconomicForumGREENHYDROGENSUPPLYAGUIDETOPOLICYMAKINGSupportedbyAccentureVersion:January2022EnablingMeasuresRoadmapforGreenHydrogenEuropeJapanVersion:January2022WORLDECONOMICFORUMIRENA1ContentsPreviousNextGeopoliticsoftheenergytransformation:Thehydrogenfactor(2022)Greenhydrogenforindustry:Aguidetopolicymaking(2022).GeopoliticsoftheEnergyTransformationTheHydrogenFactorGREENHYDROGENFORINDUSTRYAGUIDETOPOLICYMAKING121INTRODUCTIONGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL13INTRODUCTIONHydrogenisrecognisedasanessentialelementforthedeepdecarbonisationofourenergysystemthatisrequiredtomeetthecurrentclimatetargetsandlimitingthetemperatureincreasebelow2°C(IEA,2021;DNVAS,2021;IRENA,2021).However,toestablishitselfinsucharoletheproductionofhydrogenmustbeguaranteedtobeemission-free(hydrogenproducedbysteammethanereformingemitsninemetrictonnespersinglemetrictonneofhydrogenproducedwithoutconsideringmethaneemissions[HowarthandJacobson,2021]).Hydrogenfromsteammethanereformingcoupledwithcarboncapture(bluehydrogen),electrolytichydrogenproducedthroughlow-carbonelectricity(yellowhydrogen)andelectrolytichydrogenproducedthroughrenewables(greenhydrogen)arethemainpotentialcandidatestosatisfytherequirement.Hydrogenhasawiderangeofindustrialapplications,fromrefiningtopetrochemicalstosteelmanufacturing.Furthermore,similarlytonaturalgas,H2canbestoredforalongtimeandtransportedoverconsiderabledistancesthroughpipelinesorshippedafterbeingconvertedintoliquidorganichydrogencarriersorammonia,orasliquefiedhydrogen.Thehydrogentransportmethodsatpresenthavevaryingcoststhatareforeseentosettletoasimilarvalueby2050,resultinginanincrementofaroundUSD1/kgH2onthetransportedhydrogen(IRENA,2022b).Moreover,transportinduceslossesandmayrequireenergy-intensiveprocessesfortheconversion(hydrogenliquefaction)andreconversion(ammoniacracking).Greenhydrogenproductioniscurrentlylimitedtoafewapplicationsduetoitshighcostanditsproductioncapacity.Whilegreenhydrogenuseintransportiscurrentlythemostrobustbusinesscase,thereisanincreasinginterestinusinghydrogeninhard-to-abatesectorssuchasproductionofsteelandcementandinoilrefineries.However,advancesinelectrolysistechnology,decreasingcostsofrenewablesandincreasedeconomiesofscaleshouldsignificantlyreduceitsproductioncostandmakeitaneconomicallyviablesolution.FIGURE1.1.TypesofrenewableenergypotentialsandapplicableconstraintsTheoreticalpotentialTechnicalpotentialEconomicpotentialMarketpotential•Energycontentofallwindandsolarresourceswhichcouldtheoreticallybetransformedintogreenhydrogen.•Solarandwindenergythatcanbeeectivelyharvestedthroughwindparksandutility-scalePV.•NotallhydrogentechnicalpotentialproductionmaypresentcompetitiveLCOH.•Dictatedbythepresenceofgreenhydrogenotakers.•Competitionbetweendirectsaleofcleanenergyandsaleofgreenhydrogenproducedwiththatenergy.•Theoreticalpotentialreducedbytechnologycharacteristicsandlandeligibilityconstraints.14Differenttypesofpotentialscanbeidentifiedwhendiscussingsustainablyproducedhydrogen(seeFigure1.1):theoretical,technical,economicandmarketpotentials.Theserepresentupperpotentiallimitsbasedonincreasinglystringentcriteria.Aregion’stheoreticalsolarandwindpotentialisdefinedastheoverallenergycontentofwindandsolarradiationinthatregion(McKennaetal.,2022),settingatrueupperboundarytohowmuchenergycanbeideallyharvestedfromrenewableresources.Next,thegreenhydrogentechnicalpotentialisdefinedastheenergycontentofthehydrogenthatcanactuallybeproducedbyelectrolysispoweredbyrenewables.Thisaccountsforthetechnologicalcharacteristicsandrequirementsofthesystem.First,efficienciesofthepowergenerationtechnologiesallowthatonlyaportionoftheexploitableenergyistransformedintopower.Second,theelectrolyserefficiencyensuresthatonlypartoftheharvestedenergyisconvertedintohydrogen.Technicaland/orregulatoryunsuitabilityoflandtohostsuchsystemsfurthercontributestothedecreaseofthetechnicalpotentialfromthetheoreticalone.Theeconomicpotentialisdefinedifthefocusisalsoposedonthecostoftheproducedhydrogen.TheLCOHisgivenbytheratiobetweenthetotalsystemcost(CAPEXandoperationalexpenditure[OPEX])andthetotalhydrogenproduction.Thislastquantityisdirectlydependentonthequalityofrenewableenergyresourcesandtheelectrolyser’scostandperformance.Tobeeconomicallyattractive,greenhydrogenmusthavecostscompatiblewiththosethatpotentialofftakersarewillingtopay.Thisisthereasoningbehindthedefinitionoftheeconomicpotential,whichrepresentstheportionofthetechnicalhydrogenproductionpotentialwhichhasanLCOHbelowacertainthreshold(excludingtheadditionalcostofstorageandtransportationtotheconsumptiongate).Theeconomicpotentialmaynotcorrespondtomarketdemand,whichleadstocurtailingproduction,hencepotential.Thereasonsforthismaybeforthelackofofftakersincertainlocationsor,insomecases,itmaybemoreeconomicallysoundtosellthegeneratedrenewablepowerdirectlytothenationalgrid,insteadofdedicatingitcompletelytohydrogenproduction.Thislastdecreaseinproductionpotentialdefinesthemarketpotential,theanalysisofwhichwillbeexcludedfromthisreport,whichfocusesonthedefinitionoftheeconomicpotentialof34globalregions.Ofthese,G20countriesareanalysedindividuallywhiletheremainingcountriesareaggregatedinmacro‑regionssuchastheMiddleEast/NorthAfricaandLatinAmerica.AnexceptionwasmadeforChile,Colombia,Morocco,Portugal,SpainandUkraine,whichwerealsoassessedindividuallybecauseoftheirgoodprospectsingreenhydrogenproduction.Insummary,theresultsofthisanalysisgiveaclearviewoftheeconomichydrogenpotential,thelocalhydrogenproductioncost,andtheareasavailableforrenewableenergyplantsandhydrogenproductionaswellasthosewithlowestLCOH.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL152METHODOLOGY16METHODOLOGY1MeteorologicaldatatakenfromERA5datasetproducedbytheEuropeanCentreforMedium-RangeWeatherForecasts(ECMWF)(CopernicusClimateChangeService,2017)presentsaspatialresolutionof0.28125degrees.Thistranslatesinto31x31kmlandareaattheequator.2Additionaldatasetspresentspatialresolutionof0.01degrees,whichcorrespondto1x1kmlandareasattheequator.3Wateravailabilityisassessedthroughwaterstress.Thisindicatorisdefinedastheratiobetweenthetotalwaterwithdrawalsandthesurface/groundwatersupplies(Hofsteetal.,2019).Allareaswherewithdrawalsaregreaterthanthesupplywereexcluded(Fraunhofer,2021).Thissectiondescribesthedataandtoolsusedinthisanalysis.Ingeneral,meteorologicaldataiscombinedwithlandeligibilitycriteriatodeterminewheregreenhydrogenproductionispossibleandatwhatcost.Themodelconsidersstand-alonehydrogengenerationsystemspoweredbysolarPV,onshorewindandoffshorewind.Basedonlandexclusioncriteriaandresourcequality,itmayoccurthatsomesystemsarehybrids,thatis,theelectrolysermaybepoweredbybothsolarPVandonshorewind.Anoptimisationprovidestheoptimalratiosbetweenthecapacitiesofthegenerationtechnologiesandthecapacityoftheelectrolyserdependingonthelocalresourcequalityandregionalcosts.Theaimistomaximisehydrogenproductionwhileminimisingthecostofthesystem,thusprovidingthelowestLCOH,allocatedgeospatially.ThisallowstheproductionofglobalLCOHmapswhichenableuserstovisuallygraspthesuitabilityofcertainregionstoproducegreenhydrogen.Moreover,thisanalysisalsogeneratesregionalgreenhydrogensupplycostcurveswhichaccompanytheLCOHmapstoprovidetheproductionpotentialcorrespondingtoagivenLCOH.Thesolarandwindresourcedatausedasinputtothemodelhasanhourlytemporalresolutionanda31x31kmspatialresolution.1Therefore,solarPVandonshore/offshorewindplantswillbecharacterisedbyhourlycapacityfactorprofilesfor961km2areas.Thereferenceyearforthemeteorologicaldatausedinthisanalysisis2018.Thisyearwasconsideredasrepresentativeoftheperiod2010‑20consideringweatheranomalies,whichwereofrelativelylowintensityfortheperiod2015‑20(NOAA,2022),whichincludesthemostcriticalyearsconcerningclimatechangeeffects.Morespecifically,2018wasaLaNiñayear,meaningagloballycoldyear.LaNiñayearspresentbetterwindandsolarirradiationforrenewableproduction(LiandXie,2018)(onaverageglobally).However,itwasalsothewarmestLaNiñarecorded(YaleClimateConnections,2018)thuspresentinganomaliesinwindandsolarirradiationthatarenottooextreme.Additionaldatasetsregardinglandcovertype,protectedareas,populationdensityandterrainslopewereaddedtothemodeltocharacteriselandunderdifferentaspects.Withahigherspatialresolutionof1x1km,2suchdatasetsallowedidentificationofwhatareasofaregionaresuitablefortheinstallationofthegreenhydrogengenerationsystems.DifferentexclusioncriteriawereappliedforsolarPV,onshorewindandoffshorewindpower.Inasecondstepofanalysisalandexclusioncriterionforwateravailabilityforelectrolysiswasalsoadded,andgeographicalareasinwhichwateravailabilityisproblematicwereexcluded.3However,desalinationwasconsideredasaviableoptionforelectrolysiswatersupplyinareaswithin50kmfromthecoast(Fraunhofer,2021).TheadditionalcostfordesalinationwasnotcomputedgiventhemarginalcontributionofwatersupplytotheoverallLCOH,despitethepotentialadditionalcostsofdesalination(Yatesetal.,2020).ReverseosmosisdesalinationandmultistageflashdistillationdesalinationproducewaterwithcostsbelowUSD3percubicmetre(m3)(ReddyandGhaffour,2007;KyriakarakosandPapadakis,2021;Huehmeretal.,2011).ItwasdeterminedthatatasitewithanannualproductionGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL17ofalmost2500tonnes/year,thetotalwaterconsumptionwouldbearound60m3/day4(or21900m3/year).ThesitepresentsLCOHofUSD0.7/kgH2,5andconsideringadesalinationcostofUSD3/m3theincrementofLCOHwouldbe3.8%.Asthisanalysisaimstoassesstheintrinsicgreenhydrogenproductionpotentialanditscostinacertainlocation,thefollowingassumptionshavebeenmade.First,allgreenhydrogenisproducedinoff-gridstand-alonesystemsplacedinaplotoflandofabout1x1km.Thesystemsarecharacterisedatcomponentlevelbytechno‑economicparameters.Thegenerationtechnologiesandtheelectrolyseraredescribedthroughinvestmentcosts,operatingexpenses,lifetimesandefficiencies.ThecapacitiesofthesystemcomponentsareoptimisedtoyieldthelowestLCOH,andthereforecurtailmentispresentwhenthehourlyaveragepowerproductionexceedstheelectrolysercapacity.Thisisaconservativeapproachasthepotentialsynergywiththegridisnotbeingconsidered.Becausethesystemsareassumedtobestand-alone,thereisnounderlyinghypothesisofthepresenceofpowerofftakerswhichmightmakethesystemmoreprofitablebysellingthecurtailedelectricity.Similarly,hydrogendemandisnotconsidered,resultinginafreeproductionofhydrogenwhenevertheresourcesallowit.GeographicalconstraintsandexclusioncriteriaTheadditionaldatasetsmentionedintheprevioussectionallowedapplyinglandeligibilitymasksforthethreetypesofgenerationtechnologies,accordingtodifferentlandexclusioncriteria.Regardinglandtype,allprotectedareas,6forestsandwetlands7wereexcludedfromtheanalysis,forbothsolarPVandonshorewind.Ontheotherhand,specialregardwastakenwhenexcludingcroplands,whichwereexcludedonlyforsolarPV.Thelandtypedatasetdistinguishesbetweencroplandandcropland/natural,whiletheformeriscompletelyexcludedfortheinstallationofPV,thelatter,beingamosaicof40-60%cultivatedlandand60-40%naturaltrees,shrubsorherbaceousvegetation,isexcludedbyonlya60%fraction.SoutheastAsia,FranceandGermanyarethemostaffectedbythislandeligibilitycriterion,excluding16%ofSoutheastAsia’stotallandarea,15%ofFrance’sand14%ofGermany's.Croplandsaregenerallyexcludedfortheinstallationofutility-scalePVsystemssincetheygenerallyimpedeagriculturaluseofland,whileonshorewindparkshavelittleimpactontheusabilityofcroplands.8Differentexclusioncriteriaarealsoappliedforterrainslope:assuggestedbyMaclaurinetal.(2021),theterrainslopethresholdfortheinstallationofonshorewindturbinesishigher(20%)thanthatofutility-scalePV(5%).9ThedifferencesinexclusioncriteriaforonshorewindandsolarPV,whichappeartobemorestringentforthelatter,willyieldlargerportionsoflandsuitablefortheinstallationofwindparks.Inaddition,sincethisassessmentconcernswindparksandutility-scalePVsystems,urbanareasandsettlementswerealsoexcludedfromtheeligibleareas.Thisisachievedwiththeaidoftwo4Electrolysercapacityfactoris31%,withgenerationsystemscapacitiesof50megawatts[MW]utility-scalePVand41MWelectrolyser,waterconsumptionof9litres/kgH2.5Techno‑economicassumptionsforChile2050.CAPEXsolarPV:USD312/kW.CAPEXalkalineelectrolyser:USD134/‌kWe.Alkalineelectrolyserefficiency:45kilowatthours(kWh)perkgH2.6StrictNatureReserve,WildernessArea,NationalPark,NaturalMonument,Habitat/SpeciesManagement,ProtectedLandscape/Seascape,ManagedResourceProtectedArea(IUCN-UNEP-WCMC,2019).7EvergreenNeedleleafForests,EvergreenBroadleafForests,DeciduousNeedleleafForests,DeciduousBroadleafForests,MixedForests,PermanentWetlands(Friedletal.,2010).8Inamoreconservativeapproach,agrophotovoltaicswasnotconsideredintheanalysis.Thisvariantoftheground-mountedutility-scalePVisnotapplicabletoallcroptypologies(FraunhoferISE,2020),thelocaldistinctionofwhichwouldincreasethecomplexityoftheglobalmodel.9Globalslopedatasetprovidesmeanslopevaluesfor1x1kmlandareas(Amatullietal.,2018).18distinctdatasets.Urbanlandtype(Friedletal.,2010)aswellaspopulationdensity(Gao,2017)wereimplementedtogether10inexcludingareaswhicharebuiltuporpresentapopulationdensitygreaterthanathresholdof130peoplepersquarekilometre.Amorein-depthanalysisandfurthertooldevelopmentsarerequiredtoalsoassessglobalrooftopPVpotential,andisthereforeexcludedfromthiswork.Landeligibilityfortheinstallationofoffshorewindparksdependsonmarineprotectedareasaswellasthemaximumwaterdepth,determinedthroughatopographicalanalysis(NOAANationalGeophysicalDataCenter,2009),andminimumdistancefromshore,whichweresetto40metresand5km,respectively.Existingwindandsolarparksarenotaccountedforinlandexclusioncriteria,leadingtoanoverestimationofthepotential.However,thedifferencebetweenthetechnicalrenewablepotentialandthecurrentlyinstalledpotentialislarge;thereforetheimpactoftheoverestimationisnegligibleinthisassessment.Figure2.1showsthelandtypecompositionforrelevantcountriesandthepercentageoflandexcludedbasedonlandtypesuitabilityassumptions.Countrieswithlargeareasofunusedspacewithlittlevegetation,namelyshrublandsanddesert,showalargeinstallablerenewablegenerationpotential.Australia,SaudiArabiaandtheUnitedStateshavelargeunuseddesert-likeareasthatcanbeusedforrenewablepower.Ontheotherhand,Japanismoreconstrainedduetothepresenceofforests.FIGURE2.1.Landtypedistributionandsuitabilityforvariablerenewableenergyforaselectionofcountries0%10%20%30%40%50%60%70%80%90%100%AustraliaChileChinaGermanyJapanSaudiArabiaUnitedStatesSnow/iceCroplandsBarrenShrublands,savannasandgrasslandsForestsPermanentwetlandsUrbanNote:SolidcoloursrepresentsuitablelandtypesforbothonshorewindandsolarPV.Hatch-patternedcoloursrepresentlandtypesexcludedforbothsolarPVandonshorewind.Theintentofthisrepresentationtoproviderepresentativecasesfordifferentcombinationsoflandtypologiesandtheirimpactindifferentregions.10LandtypedatasetistheMCD12C1Version6from2016basedontheworkof(Friedletal.,2010).ThepopulationdensitydatasetisfortheSharedSocioeconomicPathway2ndScenariobasedontheworkdoneby(Gao,2017).GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL19TheeffectofadditionalconstraintsonlandeligibilitycanbeobservedinFigure2.2.Byaddingconstraintsonprotectedareas,terrainslopeandmaximumpopulationdensity,eligiblelandforwindparkschanges.Thelimitationofthemaximumterrainslopeto20%(Maclaurinetal.,2021)willaffectcountriesknownforhavingmountainousregions.Agreatereffectofadditionalconstraintscanbenoticedinthecaseofutility-scalesolarPV.Besidestheexclusionofprotectedareasandthelimitationonpopulationdensity,amorestringentconstraintwasimposedonterrainslopecomparedwithonshorewind,andcroplandswereexcluded.Thismagnifiesitseffectoncountrieswithmountainousregionsandcountrieswithhighportionsoflandintendedforagriculture,suchasGermany,thePeople’sRepublicofChina(hereafterChina),JapanandtheUnitedStates.Inconclusion,thelandeligibilitycriteriaprovidetheframeworktodeterminethetechnicalpotentialofhydrogenproduction.Onlyafractionofthispotentialwillhaveattractivecosts,definingtheeconomicpotential.Thislaststepdefinedthemarketpotential,andasdiscussedintheintroduction,isnotconsideredintheassessment.FIGURE2.2.Percentageoflandexcludedforonshorewind(left)andutility-scalePV(right)duetolandexclusioncriteriaNoteligible0%10%20%30%40%50%60%70%80%90%100%AustraliaChileChinaGermanyJapanSaudiArabiaUnitedStatesAustraliaChileChinaGermanyJapanSaudiArabiaUnitedStatesOnshorewindSolarPVNote:Darkshadingindicatesthepercentageoflandnoteligiblefortheinstallationofeachgenerationtechnology.Theeligibleportion,reportedincolour,isthepercentageofeligiblelanddescribedinFigure2.1furtherdecreasedbyadditionalconstraintsonprotectedareas,terrainslopeandpopulationdensity.Techno‑economicassumptionsToestimatethepotentialgreenhydrogenproduction,renewableenergygenerationisassumedtobelocallycoupledwithanalkalineelectrolyser.Thistypeofelectrolyserwasselectedduetoitslowercostandhightechnologicalmaturity,alsoconsideringfutureimprovementsin20efficiencyanddynamicoperation(HydrogenEurope,2020).Thepossibleconfigurationsofthestand-alonesystemsaredictatedbythelandeligibilityanalysis.Duetothedifferencesinlandexclusioncriteria,itmayoccurthatsomestand-alonesystemsarecomposedofbothonshorewindandsolarPVinahybridconfiguration.Thelocalmeteorologicaldataofwindspeedandsolarirradiationaretranslatedintolocalhourlycapacityfactordistributions.Obtainedthroughtechnologycharacteristics,11theseprofilesrepresentthetechnicalinputstotheproblemofdeterminingthepotentialproductionofgreenhydrogen.Theeligiblelandcanbetranslatedintorenewablegenerationpotentialthroughthepowerdensities(perunitarea)ofsolarPV,onshorewindandoffshorewindpower.Theglobalvaluesusedinthisassessmentare45megawattsofalternatingcurrentpower(MWAC)perkm2forPV(BolingerandBolinger,2022;NREL,2013),5MW/km2foronshorewind,and7.43MW/km2foroffshorewind(EnevoldsenandJacobson,2021;IRENA,2015).Thepowerdensitiesforwindincludewakeeffectsbutdonotconsiderthereductionofthecapacityfactorasahighershareofthepotentialisused(Box2.1).Box2.1.ImpactofoffshorewindcapacityexpansiononcapacityfactorThedeploymentofoffshorewindhasbeenmuchmorelimitedtodatethanonshorewind.Bytheendof2021,thetotalinstalledoffshorewindcapacitywas56GWroughlysplitequallyacrossChinaandEuropeandrepresentingabout5%oftotalglobalwindcapacity.Thiswouldneedtogrowtoalmost2000GWby2050ina1.5°Cscenario(IRENA,2022c).Turbinescreatedownstreamwakes,inwhichthewindflowisreducedduetotheextractionofkineticenergybytheturbineitself.Sufficientlydownstreamfromtheturbine,thewakerecoversduetomixingwiththesurroundingundisturbedwindflow.Turbinespacingallowsavoidanceoratleastreductionoftheimpactofwakesonneighbouringturbines.However,theoverallkineticenergypresentintheundisturbedwindflowoveragivengeographicalareaisfinite.Therefore,ifaregionisdenselypopulatedbywindparks,thereplenishingofthedepletedwakeregionsisnotaseffective,thusinducingunforeseenlosseswhichdeviatecapacityfactorsfromtheexpectedones.Forexample,astudyforoffshorewindfarmsintheGermanBightfoundthatbyinstalling28GWofoffshorewindoveranareaof2800km2,thecumulativefull-loadoperatinghours(FLOH)woulddecreasefromanaverageof4500to3400,whichtranslatesintoacapacityfactorof39%.Theeffectisfurtherenhancediftheinstalledcapacityincreasesto72GWusingasurfaceareaof7200km2,decreasingtheFLOHto3000,resultinginacumulativecapacityfactorof34%(Figure2.3).Theunexpectedcapacityfactorreductionmayunderminetheeffectivenessofoffshoreinplayingaroleinthe2050climategoalssinceitsignificantlyincreasestheelectricitycostanderodesthemainadvantagethatoffshorewindhas,itshighercapacityfactor.Therefore,suchaphenomenonmustbeaccountedforbydedicatedspatialplanningoftheeligiblemaritimeregionsfortheinstallationofoffshorewindparks.Countrieswithdenselypackedexclusiveeconomiczones(e.g.NorthSea,BalticSea)mustco‑operatetoensuresufficientspacingbetweenfarmstoensureeffectivewakerecovery.Acomplementarysolutiontothisissueisthatofaccessingregionsofseaineligibleforfixed-bottomoffshore,withtheemergingfloatingoffshoretechnology.11Windspeedtransformedintohourlycapacityfactorthroughturbinepowercurve.Onshore:3MWV112,Vestas(Vestas,2021).Offshore:10MWSiemensGamesaSG10.0-193DD(Saint-Drenanetal.,2019).Solarirradiationtransformedintoglobaltiltedirradiation(JacobsonandJadhav,2018)thendividedby1000wattspersquaremetretoobtaincapacityfactorswithrespecttostandardtestconditions.Additionalsystemlossesof15%wereaddedforonshore/offshorewindand23%forsolarPV.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL21Box2.1.(Continued)FIGURE2.3.Full-loadhoursachievabledependingonareaforoffshorewinddeploymentintheNorthSea(andexpectedyieldinterawatthours)01000200030004000500002000400060008000Full-loadhoursAreausedinkm7,5MW/km10MW/km12,5MW/kmAreaspreadoutacrossNorthSeathroughcountryco-operationyieldsmorefull-loadhoursMoreintensiveuseinGermanBightonlyleadstolowerfull-loadhours~100TWh~220TWhNotes:TWh=terawatthours.Windspeedreductionsareestimatedwiththekineticenergybudgetoftheatmospheremethod.Source:AgoraEnergiewendeetal.(2020).AchallengeforhydrogenproductionfromoffshorewindisthehighcostofelectricitycomparedwithsolarPV.AuctionsandpowerpurchaseagreementdatasuggestthattheEuropeanmarketcouldreachelectricitycostsofUSD50permegawatthour(MWh)toUSD100/MWhforoffshorewindby2023,withsomeofthemostcompetitiveprojectsreachingUSD30/MWh(IRENA,2022c).EventhelowerboundwouldbetriplethecurrentlowestbidsforsolarPV(USD10/MWh)andwouldtranslateintoahydrogencostofUSD1.5/kgH2withoutaddinganycostsfortheelectrolyser.Thetrade-offforcountrieswithalargeoffshorepotentialisthehighercostofsupplyversusahigherenergyindependence.Thus,ahighercostofproductionmightbepreferredbysomecountries.Thehighgasandcommoditypricesduringlate2021andearly2022inEuropeanandAsianmarketshavere‑emphasisedtheneedforenergysecurity,makingdomesticproductionmoreattractive.Ontheotherhand,itisalsonecessarytoconsiderthecostsassociatedwiththehydrogengenerationsystems.Takingtheseintoconsiderationallowsonetodefinetheeconomicpotentialofproduction.Inordertoenvisionatransitionpathway,twotimehorizonswereconsidered:2030and2050.Foreachofthetimehorizons,anoptimisticandapessimisticscenariowereanalysed.Thesewillserveasanupperandlowerboundaryforthecostandpotentialproductionofgreenhydrogenintheglobalregions.Anadditionalscenariowasrunwiththeinclusionofthewateravailabilityconstraint.ThedefinitionofthedifferentscenariosdependsontheassumptionsregardingtheCAPEXofthecomponentsofthestandalonesystems,theefficiencyoftheelectrolyser12andtheWACC.Moreover,theCAPEXofthegenerationtechnologies(utility-scalePV,onshoreandoffshorewind)areconsideredvariablebyregion(Figure2.4).TheWACCsareconsideredtobevariablebybothtechnologyandregion.However,unliketheCAPEX,theWACCsareassumedtobefixedthroughto2050,forboththeoptimisticadpessimisticscenarios.12Alkalineelectrolyserefficiencyvariesbasedonthetimehorizon(2030,2050)andscenario(optimistic,pessimistic).Thespecificelectricalenergyconsumptionsin2030are48.5kWh/kgH2and52.2kWh/kgH2,whilein2050theyare45.0and48.0kWh/kgH2,fortheoptimisticandpessimisticscenarios,respectively.22FIGURE2.4.Capitalcosttrendsforrenewabletechnologiestowards2050underoptimisticassumptionsandbenchmarkwithotherstudies10001500200025003000350020302035204020452050CAPEX(USD/kW)OshorewindEasternAsiaJapanAustraliaChileChinaGermanyUnitedStatesSaudiArabia20302035204020452050EasternAsiaRepublicofKoreaAustraliaChileChinaGermanyJapan80010001200140016001800CAPEX(USD/kW)Onshorewind0100200300400500600700800900100020302035204020452050CAPEX(USD/KW)Utility-scalePVEasternAsiaRussianFederationAustraliaChileChinaGermanyJapanIRENAIEADNVJanssenetal.ERINITISimon,Gils&FichterLeonardoDiCaprioFound.TeskeLUTVartiainenetal.600Notes:Optimisticassumptionsused.Solidlinesaretheassumptionsforthisreportanddotsarepreviousstudies.TheupperandlowerboundariesarerepresentedbytheregionspresentingthehighestandlowestCAPEXforeachcategory.Therelevantcountriesarereportedandliewithinthisrange.Referencevaluesfoundinliteraturearesuperimposed.Sources:IRENA(2019);IEA(2019);DNVGL(2019);Janssenetal.(2022);ERI&ChinaNationalRenewableEnergyCentre(2017);NITIAayog(2015);Simon,GilsandFichter(2016);LeonardoDiCaprioFoundation(2019);Teskeetal.(2015);LUTUniversityandEnergyWatchGroup(2019);Vartiainenetal.(2021).GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL23TheWACCisusedasthediscountratefortheinvestmentsinhydrogengenerationsystems.Thisparameterisusedtoexpresstheriskofinvestmentinaparticularregion.TherangeofWACCvaluesacrosscountriesforvariousscenariosandtechnologiesisshowninFigure2.5.Besidesthehighlightontherelevantcountries,asignificantoutlierisrepresentedbyArgentina.13Thisparticularlyabove-averageriskofinvestmentwillhaveasignificantimpactonthecostoftheproducedhydrogen.TherespectiveimpactofWACCandCAPEXcanbeassessedthroughtheireffectonthelevelisedcostofelectricity(LCOE).Assuminganannualcapacityfactorof21%forsolarPVandfixingtheCAPEXtoUSD245/kW,14effectsoftheWACCincreasecanbequantified.AWACCincreasefrom4%to6%wouldcausetheLCOEtoincreasefromUSD18.7/MWhtoUSD25.5/MWh(37%increase).Ontheotherhand,fixingtheWACCto4%andincreasingtheCAPEXby50%toUSD381/kWyieldsUSD26.3/MWhofelectricityproduced(41%increase).FIGURE2.5.RangeofWACCbytechnologyandscenario2%4%6%8%10%12%14%16%AlltechnologiesoptimisticSolarPVpessimisticOnshorewindpessimisticOshorewindpessimisticOutliersMaximumAverageMinimumWeightedaveragecostofcapital(%)Notes:Boxandwhiskerchartsshowvariationwithinasetofdata,similartoahistogram.Thelineandthexwithintheboxrepresentthemedianandthemeanrespectively.Theupperandlowerboundariesoftheboxrepresentthefirst(Q1)andthird(Q3)quartilesofthedataset.AvalueisconsideredanoutlierifgreaterthanQ3+1.5(Q3-Q1)orsmallerthanQ1‑1.5(Q3-Q1).Finally,theupperandlowerwhiskersrepresentthemaximumandminimumvalueswhicharenotoutliers.Theelectrolysercapitalcostsperkilowattusedforthisassessmentareinlinewiththepotentialcostdecreaseforelectrolysersasafunctionofdeployedcapacity,consideringthecostcorrespondingto5TWofdeployedcapacitybytheyear2050(IRENA,2020).TheseareexpectedtofallfromUSD384/kWein2030toUSD134/kWein2050underoptimisticassumptionsandUSD688/kWetoUSD326/kWeinapessimisticscenario.Thesevaluesincludeinstallationcosts.Theremaininginputsfortheoptimisationproblemaretechnology-specificcharacteristicssuchaslifetimesandoperatingexpenditures.LowerperformanceduetodegradationforsolarPVwasnotconsidered.Allsystemcomponents’lifetimesweresetto25yearswhiletheyearlyoperatingexpendituresweresetto1%ofCAPEXforsolarPV,3%foronshorewindand2.5%foroffshorewind.1513Thereareotheroutliersatthecountrylevel,butthesearepartofoneofthe34regions(seeMethodologysection)averagingouttheseextremevalueswhenallthecountriesintheregionareconsidered.14ValuescorrespondtoChinain2050inanoptimisticscenario.15IRENAownassumptions.243LEVELISEDCOSTOFHYDROGENAROUNDTHEWORLDGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL25LEVELISEDCOSTOFHYDROGENAROUNDTHEWORLDOptimalcombinationofrenewableenergysourcesandelectrolysersTheLCOHdependsontheyearlyproductionandcostofthehydrogengenerationsystem,whichinreturnareafunctionofthesizeofthesinglecomponentsofsaidsystem.Singletechnologyconfigurationscoupleonegenerationtechnologywithanelectrolyser,whilehybridsystemscombineanelectrolyserwithtwogenerationtechnologies(solarPVandonshorewind).Inallcasesthereisanoptimalcombinationbetweenthecapacitiesofthecomponentswhichyieldthemaximumhydrogenproductionattheminimalcost.Thisoptimalsystemconfigurationisdictatedbythelocalmeteorologicalconditionsandtheregionalcostsandrisksofinvestments(representedbyWACCs).Ingeneral,foragivengenerationtechnologycapacity,increasingthecapacityoftheelectrolyserincrementsthemarginalhydrogenyieldatahigherratethanthemarginalsystemcost.Theoptimalelectrolysercapacityisthatatwhichanyfurthercapacityincrementcausesalowerincreaseinhydrogenproductioncomparedwiththatofthesystemcost.Inpractice,anoversizedelectrolyserforagivenlocalresourcewillfinditselfidlingformostoftheyear,remainingunproductive.Anadditionalresourcequalitycharacterisationwasimplementedbydeterminingcapacityfactordistributionscharacteristictoeachregion.Afterapplyingthelandexclusioncriteria,suchprofilesaredeterminedbyassigningthespatiallydistributedresourcedistributionstoaqualityclass,basedontheyearlycapacityfactorproducedbythatresource.Thebest-performingresourceisallocatedtoClass1andtheworsttoClass5.Theprofilesineachclassarethenaveragedtoproduceacharacteristichourlyprofileforthatregion’sclass.Table3.1showstheresourcequalityclassboundariesforPVandwind.TABLE3.1.ClassificationofresourcequalityforeachrenewabletechnologyCLASSSOLARPVONSHORE/OFFSHOREWINDANNUALCFINTERVALIN%1CF>20CF>60217<CF≤2045<CF≤60314<CF≤1730<CF≤45411<CF≤1415<CF≤3050<CF≤110<CF≤15Notes:CF=capacityfactor.Thevaluesrepresenttheannualcapacityfactor(ratiobetweenthefull-loadoperatinghoursandthetotalhoursinayear).26Eachresourcequalityclassanditscharacteristicprofileareassociatedwithapotentiallyinstallablegenerationtechnologycapacity.Thecharacteristiccapacityfactorprofilesarerepresentativeforthesingleregionsandallowtheintroductionofaregion-levelgeneralisationontheoptimalgreenhydrogengenerationsystemsconfigurations.Regardingsingle-technologysystems,theratiobetweenthecapacityofpowergenerationandthecapacityoftheelectrolyserthatensuresminimumLCOHswilltendtowardsunityiftheresourceallowsforreachinghighyearlycapacityfactors.Thiscanbeseeninthedirectcomparisonbetweentwosingle-technologysystemsusingdifferentqualityresources.First,thedifferentoptimalsolarPV-to-electrolyserratiosforsystemsbenefitingfromhighestqualitysolarresourceinChile(PVClass1)andthehighest-qualitysolarresourcepresentinGermany(PVClass3)areshowninFigure3.1.Consideringtheannualcapacityfactorobtainedfromtheresourceis24%forChileand14%forGermany(alsoshowninFigure3.1),theoptimalPV-to-electrolyserratiosare1.3forChileand1.8forGermany.Undertheassumptionofanoptimistic2050scenario,theminimumLCOHsobtainedareUSD0.73/kgH2(Chile)andUSD0.95/kgH2(Germany)forPV-fedelectrolysersystems.Withevenlessperformingresource,theoptimalPVcapacitymayalsoendupbeingtwiceasmuchastheelectrolyser’s.Forexample,usingthecostassumptionsfortheUnitedStatesforthe2050optimisticscenarioanda10%annualcapacityfactorsolarPVresource,theratiobetweenthegenerationtechnologyandtheelectrolyserincreasesto2.14,yieldinganLCOHofUSD1.62/kgH2,ascanbeseeninFigure3.1.FIGURE3.1.Comparisonbetweenlevelisedcostofsolar-andwind-producedhydrogenasfunctionofannualcapacityfactorandoptimalratio0.7511.251.51.7522.252.5GenerationtechnologytoelectrolyserratioChileCFPV=24%GermanyCFPV=14%UnitedStatesCFPV=10%ChileCFOnshore=63%SaudiArabiaCFonshore=31%JapanCFonshore=20%ChilePVminimumGermanyPVminimumUnitedStatesPVminimumChileonshoreminimumSaudiArabiaonshoreminimum0.511.522.530.5JapanonshoreminimumLevelisedcostofhydrogen(USD/kgH)Notes:HighlightedistheimpactoftheresourcequalityontheoptimalgenerationtechnologytoelectrolysercapacityratioandLCOH,whicharereportedasdiscretepoints.Ingeneral,theoptimalratiosareafunctionofthecapacityfactor,withhigher-qualityresourcesensuringlowerratios.ThecurvesforChile,GermanyandSaudiArabiaweregeneratedthroughtheirbest-performingcharacteristicresource.ThecurvesfortheUnitedStatesandJapanontheotherhandarerepresentativeoftheeffectofpoor-qualityresourcesontheLCOHandoptimalratio.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL27Asimilarcomparisonisshownbetweenwind-generatedhydrogeninChileandinSaudiArabia.Inbothcasestheirbestavailableresourcewasused,presentingannualcapacityfactorsof63%(onshoreClass1)forChileand31%(onshoreClass3)forSaudiArabiarespectively(seeFigure3.1).Theoptimalratiosbetweenthecapacitiesofwindandelectrolyserare1.13forChileand1.3forSaudiArabia.Assumingagainanoptimistic2050scenario,LCOHsareUSD0.76/kgH2forChileandUSD1.66/kgH2forSaudiArabia.Afurtherincreaseoftheoptimalratiooccursiftheannualcapacityfactordecreases.Under2050optimisticscenariocostassumptionsforJapanandanannualcapacityfactorof20%,theresultisanLCOHofUSD2.43/kgH2,ataratioof1.52.BycomparingtheunfavourablecasesofPVandwind(GermanyandSaudiArabia),itcanbenoticedhowtheoptimalratioishigherforPVandthisisduetothelowercapacityfactorofPVinGermany.However,giventhemuchlowerCAPEXofthePVtechnology,theLCOHproducedinGermanybysolarPVismuchmorecompetitive.Figure3.2showshowthemajorityofChile’sonshorewindpotentialbelongstotheworstperformingtechnologyclass,whichonlyhasanannualcapacityfactorof4%,anditisnoteconomicallyfeasible.Ontheotherhand,SaudiArabia’slargeonshorepotentialisallocatedmainlytothebetter-performingtier(Class4).WithreferencetoFigure3.2,Chilecanlargelybenefitfromitshigh-qualitysolarPVresource(PVClass1)whilethebest-qualityresourceinGermany(Class3)haslittlecapacitypotential.ThemajorityofsolarPVcapacityisallocatedtoClass4.FIGURE3.2.DifferenceinonshorewindpotentialbyresourcequalityinChile,GermanyandSaudiArabia(inGW)Class5(4%)1631Class2(52%)128Class4(20%)89Class4(21%)7417Class5(9%)1037Class3(31%)18Class1(63%)0.6Class3(37%)30ChileSaudiArabiaClass1(24%)6627Class2(19%)359Class3(15%)528Class4(13%)1171Class4(13%)768Class3(14%)2ChileGermanySolarPVOnshorewindNotes:Representedinthesefiguresarethepotentialsingigawattsoftheinstallableutility-scalePVandonshorewindfoundintheirrespectiveresourcequalityclasses,definedbytheannualcapacityfactor(reportedasapercentageinbrackets).Thepotentialsaredeterminedbyapplyingthepowerdensityofthetechnologiestotheeligiblearea.Eachclassischaracterisedbyanaverageannualcapacityfactor.TheclassupperandlowerboundariesarethosespecifiedinTable1.28Itcanbeseenhow,inChile,thebestresourcesofsolarPVandonshorewindyieldcomparableLCOHsthoughtheannualcapacityfactorsdifferwidely(24%ofPVagainst63%ofonshore).ThisisduetothedifferenceinCAPEXofthetwogenerationtechnologies:USD312/kWforPVandUSD864/kWforonshore.Theratiosbetweenthegenerationtechnologyandelectrolyserarelowerinthecaseofonshorewind,thereforetheminimumLCOHsareensuredbyasmallercapacityelectrolyser,comparedwiththecaseofsolarPV.Theoptimalratiosbetweenthegenerationtechnologiesandtheelectrolysercapacitiesalsodependontheeconomicassumptionsofthemodel.Byconsideringsingle-technologysystemsoperatingwiththesameannualcapacityfactors,adecreaseinthesystemcostwillcausetheoptimalratiotoalsodecrease.InFigure3.3,theprocessishighlightedforsolarPVandonshorewindhydrogengenerationsystems.Theresourcequalityusedtoassesstheoptimalratiosisthebestperformingofeachcountryandisusedforbothtimehorizons.ThelandsuitabilityassessmentmightinsomecasescoincideforbothsolarPVandonshorewind,potentiallygivingwaytohybridhydrogengenerationsystems.TheoptimalratiosamongthecapacitiesofthethreesystemcomponentsarethosethatensurethelowestLCOHandwilldependonthelocalsolarandwindresourcebutalsoontheregionalcostassumptions.InFigure3.4,thecomparisonbetweenAustraliaandGermanyintermsoftheratiobetweentheoptimalPVcapacityandtheoverallhybridsystemgenerationcapacityisshownasafunctionofincreasingCAPEXofsolarPV(x-axis)andonshorewind(y-axis).Notethattherenewableresourcesarefixedandyieldannualcapacityfactorsof21%and48%forAustralia,and14%and46%forGermany,forsolarPVandonshorewindrespectively.TheelectrolyserCAPEXandefficiencyarealsofixedtothevaluescorrespondingtothe2050Optimisticscenario(USD134/‌kWeand87.5%[HHV]).Thepotentiallyhybridhydrogengenerationsystems’optimalconfigurationmaybeoneinwhichonepowergenerationsystemisstronglydominantovertheother.MorecompetitiveCAPEXofoneofthegenerationtechnologiesmightcausetheoptimalratiotofavourthattechnology.Therefore,potentiallyhybridsystemconfigurationsmaybeledbacktosingle-technologytypesystemspreviouslydiscussed.Under2050optimisticassumptions,andwithoutconsideringwateravailabilityasalandexclusioncriterion,itwasdeterminedthat,onglobalaverage,93.2%ofthelandsurfacethatcouldpotentiallyhosthybridgenerationsystems(over56millionkm2)atagloballevelyieldsminimumLCOHwhenoperatingasasolarPV-onlysystem.ThisresultismainlyduetothepenalisingCAPEXvaluesofonshorewindwhich,onglobalaverage,arenearlythreetimesthoseofsolarPV.MostregionspresentthetotalityorneartotalityofpotentiallyhybridsystemsyieldingminimumLCOHwhenoperatingasaPV-onlysystem,withtheexceptionoftheUnitedKingdom(34%),Canada(43%)andtheRussianFederation(hereafterRussia)(57%).Ontheothersideofthescale,potentiallyhybridsystemsthatfindtheiroptimalconfigurationwhenoperatingasonshore-onlysystemsrepresent,onglobalaverage,onlyashareof2.93%.Canada(34%),Russia(32%)andtheUnitedKingdom(16%)aretheonlythreecountriespresentingmuchhigherthanaverageshares,followedbyChile(9%),theUnitedStates(2.6%)andJapan(2%).Thisoptimalconfigurationisstronglydictatedbythelocalmeteorologicalconditions,whichensurehighonshorewindcapacityfactorsagainstpoor-qualitysolarPVones.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL29FIGURE3.3.RelationshipbetweenLCOHandrenewabletoelectrolysercapacityasafunctionofcapacityfactorfor2030and20500.50.70.91.11.31.51.71.92.12.32.51.21.31.41.51.61.71.81.922.12.22.3LCOH(USD/kgH)PVtoelectrolyserratio[-]Solargeneratedhydrogen0.50.7511.251.51.7522.252.52.75LCOH(USD/kgH)1.11.151.21.251.31.351.41.451.51.55Onshorewindtoelectrolyserratio[-]Wind-generatedhydrogenAustraliaCF=48%ChileCF=63%ChinaCF=52%GermanyCF=46%JapanCF=48%SaudiArabiaCF=31%UnitedStatesCF=61%AustraliaCF=21%ChileCF=24%ChinaCF=21%GermanyCF=14%2030205020302050JapanCF=17%SaudiArabiaCF=22%UnitedStatesCF=21%Notes:CapacityfactorsusedforPVandonshorewindarethesamefor2030and2050.ChangingCAPEXassumptions(intheoptimisticscenario)forbothgenerationtechnologiesandtheelectrolyser(aswellasefficiency)causestheshiftoftheoptimalratios.30Lastly,trulyhybridsystemsrepresentonly,onglobalaverage,2.48%foronshoreprevalent,and1.38%forsolarPVprevalent,ofallpotentiallyhybridsystems.SolarPVprevalenthybridsystemsaremostlyencounteredintheUnitedKingdom(25%),followedbyRussia(4.6%)andCanada(3%).OnshoreprevalenthybridconfigurationsaremostlyfoundintheUnitedKingdom(25%),Canada(19%),Japan(9%)Argentina(6.6%).Theseconfigurationsarealsostronglydependentonlocalmeteorologicalconditions.TherenewableresourcesusedinFigure3.4arethebest-performingresourceclassinAustraliaandGermany.FIGURE3.4.Optimalhybridsystemconfigurations(dots)in2050asafunctionofCAPEXofthegenerationtechnologiesforGermany(greenlines)andAustralia(bluelines)600650700750800850900950100010501100100200300400500600700OnshorewindCAPEX(USD/kW)PVCAPEX(USD/kW)AustraliaPVonlyGermanyPVonlyGermanyhybridGermanyonshorewindonlyAustraliaonshorewindonlyAustraliahybridBoundarybetweenPVonlyandhybrid(Germany)BoundarybetweenPVonlyandhybrid(Australia)Boundarybetweenhybridandonshorewindonly(Germany)Boundarybetweenhybridandonshorewindonly(Australia)Notes:Therenewableresourcesusedinthisrepresentationarethebest-performingresourceclassinAustraliaandGermany.ThepointsrepresentthefollowingCAPEXvalues:Germany,solarPV:USD254/kW,onshorewind:USD771/‌kW;Australia,solarPV:USD315/kW,onshorewindUSD864/kW.ThemajorityofsolarPVandonshorewindpotentialsinGermanyareallocatedtoareaswherethecapacityfactorsarelower(13%forsolarPVand21%foronshorewind).Basedonthe2050CAPEXofsolarPVandonshorewind,thehybridhydrogengenerationsystemswiththelowestcostsuseasinglegenerationtechnology,specifically,solarPV.TheunderlyingCAPEXassumptionsarethoseofthe2050optimistictimehorizon(seeFigure2.4),rangingbetweenUSD245/kWandUSD690/kWforsolarPVandbetweenUSD743/kWandUSD1434/kWforonshorewind.TheoutcomeofthecostdifferenceofthetwogenerationtechnologiesisthatthevastmajorityofthepotentiallyhybridsystemsyieldminimumLCOHwheninstallingonlysolarPVasagenerationtechnology.InthecaseofAustralia,mostofthelandisdeemedaseligibleforbothPVandonshore(asshowninFigure3.5)andbasedontheabove-mentionedanalysis,mostofthesepotentiallyhybridsystemswillensureminimalLCOHswhenoperatingasPV-onlysystems.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL31FIGURE3.5.Breakdownofhydrogenproductionbyrenewabletechnologyforselectedcountries0%10%20%30%40%50%60%70%80%90%100%AustraliaChileChinaGermanyJapanSaudiArabiaUnitedStatesHybridPVOnshorewindHybridonshorePVNotes:Thecompositionofeachcountrydependsonthelandexclusioncriteriaappliedandthequalityoftheresourcepresentattheeligiblesites.Hybridsystemswithoptimalcapacitiesstronglyinfavour(ratiolowerthan1%)ofonetechnologyarereportedassingle-technologysystems.TheproperhybridsystemsaredividedintoPVoronshoreprevalent.ThisrepresentationaccountsonlyforsystemsyieldingLCOHlowerthanUSD5/kgH2.Theintentofthisrepresentationisthatofprovidingrepresentativecasesfordifferentcombinationsoflanduse,costassumptionsandresourcequality.Ontheotherhand,inGermanythelandeligibilityanalysis(asshowninFigure2.2)highlightsthatmostoftheavailablelandiselectedassuitablefortheinstallationofonshorewind.However,inthoseareaswhereahybridsystemcouldbeinstalled,costassumptionsandresourcequalitystillfavoursolarPV-exclusivesystems.InFigure3.5,thesystemcompositionisreportedforrelevantcountriesfortheyear2050underoptimisticassumptions.ItcanbeseenhowhybridsystemsrepresenttheminorityoftheoverallgenerationsystemssimplybecauseofthelowCAPEXassumedforsolarPV.InregionswheretheCAPEXforsolarPVishigher(orCAPEXforonshorewindislower),thenhybridconfigurationscanbeattractive.GlobalLCOHmapsandpotentialForthisstudy,theworldisdividedinto34regions.G20countriesaremodelledindividually,whiletherestoftheworldisclusteredineightregions.Furthermore,someselectedcountriesthatcouldplayanimportantroleasexportersandimportersarealsoanalysedindividually(Chile,Colombia,Morocco,Portugal,SpainandUkraine).Theresultsoftheanalysisshowthat32forstand-alonegreenhydrogenproductionsystemsin2050,theLCOHisonaveragequitelow,withvaluesbelowUSD1.5/kgH2inmostcountrieswhenthebestrenewableresourcesareused.Concerningthehydrogenproductionpotential,itisevidentthattheeconomicpotentialbelowUSD2/kgH2ishugeandlargelysatisfiestheforecastdemandfortheyear2050(Figure3.6).Thetotaldemandforhydrogenin2050represents12%ofthetotalfinalenergydemandandamountsto74EJ(IRENA,2022c).Ofthis,24EJwillbededicatedtothepowersectorwhiletheremaining50EJwillbemostlybetweenthechemical(mostlyammonia)andtransportationsectors(IRENA,2022c).However,iftheeconomicpotentialofthesinglecountriesisaddressed,itmayfallbelowtheforecasthydrogendemandfortheyear2050.Underoptimisticassumptionsandincludingwateravailabilityconstraints,thehydrogenproductionpotentialunderUSD2/‌kgH2ofJapanandtheRepublicofKoreaisalreadyhalfandone-thirdoftheforecastdemand,deemingthemaspotentialfutureimporters.FIGURE3.6.ComparisonbetweeneconomicpotentialofgreenhydrogensupplybelowUSD2/kgH2andforecastedhydrogendemand,inEJ/year,in2050766NorthAmerica977LatinAmerica343Europe276MiddleEastandNorthAfrica1923Sub-SaharanAfrica278RestofAsia60SoutheastAsia266NortheastAsia676Oceania267231441476716023065925391754151HDemandPessimisticOptimisticNotes:AssumptionsforCAPEX2050areasfollows:optimistic,PV:USD225/kWtoUSD455/kW;onshorewind:USD700/kWtoUSD1070/kW;offshorewind:USD1275/kWtoUSD1745/kW.Pessimistic,PV:USD271/kWtoUSD551/kW;onshorewind:USD775/kWtoUSD1191/kW;offshorewind:USD1317/kWtoUSD1799/kW.WACC:optimistic,per2020valueswithouttechnologyrisksacrossregions.Pessimistic,per2020valueswithtechnologyrisksacrossregions.Technicalpotentialhasbeencalculatedbasedonlandavailabilityconsideringseveralexclusionzones(protectedareas,forests,permanentwetlands,croplands,urbanareas,slopeof5%[PV]and20%[onshorewind],populationdensityandwaterstress).Totalhydrogendemand,notincludingpowersector(24EJ/year),isequalto50EJ/year.Disclaimer:Thismapisprovidedforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplyanyendorsementoracceptancebyIRENA.ConcerningtheeconomicpotentialofgreenhydrogenbelowUSD4/kgH2inthe2030timehorizon,sub‑SaharanAfricaholdsthegreatestproductionpotential,withvaluesrangingbetween1650EJand1242EJ/year(wheretheupperandlowervaluesrepresentthepessimisticandoptimistictechno‑economicassumptions).FollowingtheleadareAustralia(520EJto598EJ/‌year),Brazil(376EJto461EJ/year),theUnitedStates(213EJto385EJ/year),Russia(198EJto276EJ/year),Canada(185EJto274EJ/year)andtheMiddleEast/NorthAfrica(112EJto214EJ/year).Ontheotherendofthescale,countriesthataregeographicallyconstrainedGLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL33bytheirhighwaterstress,landuse,orographyand/orandprotectedareas(reportedasnoteligibleareasinFigure3.7),presentsignificantlylowerhydrogenproductionpotentials.ThemostpenalisedistheRepublicofKorea,withapotentialrangingbetween0.2EJand0.1EJ,followedbyJapan(0.1EJto1.2EJ/year),Italy(1.1EJto1.3EJ/year),Portugal(1.8EJto2.1EJ/year),Germany(2.6EJto4.3EJ/year)andFrance(2.9EJto5.6EJ/year).TheeconomicpotentialdecreasessignificantlyifthethresholdisloweredtoUSD2/kgH2,andmostcountriesandregionsdonotpresentanyhydrogenproductionpotentialunderpessimisticassumptionsin2030.FIGURE3.7.Globalmapoflevelisedcostofgreenhydrogenin2030consideringwaterscarcity10.621.532.543.54.5LCOH>55NoteligibleUSD/kgHNotes:GeospatialdistributionofLCOHbelowUSD5/kgH2for2030underoptimisticassumptions.Inthisrepresentation,landexclusioncriteriaalsoaccountforwateravailability.Disclaimer:Thismapisprovidedforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplyanyendorsementoracceptancebyIRENA.Focusingonthe2050timehorizonandconsideringthegeneraldecreaseoftheCAPEXofthetechnologies,evenloweringtheeconomicpotentialthresholdtoanLCOHofUSD2/kgH2,the2050timehorizonhydrogenproductionpotentialisstilllarge.Sub-SaharanAfricastillholdsthegreatestpotential(Box3.1),varyingbetween1845EJand602EJ/year,underthepessimisticandoptimisticassumptionsrespectively.FollowingareAustralia(584EJto659EJ/year),Brazil(86EJto511EJ/year),theUnitedStates(193EJto426EJ/year)andChina(230EJto265EJ/‌year).Thecountriespresentingthelowesteconomicpotentialsin2050aretheRepublicofKorea(0.15EJto0.2EJ/year),Japan(0.04EJto1.3EJ/year),Italy(1.3EJto1.4EJ/year)andPortugal(1.9EJto2.4EJ/year).Thesevaluescanbeputinperspectivebycomparisonwiththeforecasttotalhydrogendemand(excludingthatofthepowersector)in2050of50EJ.ManyregionswillhavemorethansufficientdomesticsupplyofgreenhydrogenbelowUSD2/kgH2,consideringthatthehighestdemandregionsareChina(12.2EJ/year),theMiddleEast/NorthAfrica(4.5EJ/year),India(4.2EJ/year)andtheUnitedStates(4EJ/year)(Figure3.8).34FIGURE3.8.Ratiobetweenthepotentialdomesticproductionofgreenhydrogenandtheestimated2050hydrogendemandforselectedcountriesOptimisticPessimistic020406080100120UnitedStatesMiddleEastandNorthAfricaChinaIndiaRatioofdomestichydrogenpotentialtodemandin2050Notes:Hydrogensupplydeterminedwithcostwithtechno‑economicassumptionsfortheyear2050underoptimisticandpessimisticscenarios.Wateravailabilityforelectrolysisisconsideredinthisanalysis.Box3.1.Africa’sgreenhydrogenpotentialAfricacombinesgood-qualityresourcesforPV(acrosstheentirecontinent)withonshorewind(particularlyintheWesternSaharaandtheSomaliPeninsula),largeareasofland,andaburgeoningenergysector.Greenhydrogenprovidesanadditionalopportunitytosatisfythegrowingenergyneedsofthecontinentwhileatthesametimeprovidingprospectsforeconomicgrowthandindustrialdevelopmentthroughexportofhydrogenanditsderivatives.TheAfricanHydrogenPartnershiphasidentifiedregionswithintheAfricancontinentwithsufficientlyfavourableconditionstoestablishfuturegreenhydrogenhubs:DemocraticRepublicofCongo,Egypt,Ethiopia,Kenya,MauritaniaandNamibia(AHP,2019).Thesesixregionsareplacedstrategicallyaroundthecontinentatmajorinterconnectionsbetweentrans-Africanhighways,andwillserveasbothsupplyanddemandcentresforgreenhydrogen.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL35Box3.1.(Continued)Therearemultipleactivitiesthathavebeenannouncedaimingtotakeadvantageofthisvastpotential.Moroccohaspublishedagreenhydrogenroadmap(MEM,2021)andannouncedabilateraltradeagreementwithGermanyandtheNetherlands.EgypthastodaythelargesthydrogendemandinAfrica(1.4MtH2in2020)(IRENA,2022d)andrevealedaUSD5billionprojectforproducinggreenammonia(Reuters,2022).TheEthiopia-DjiboutiregioncombinesbenefitsofEthiopianrenewableenergypolicy,needforfertiliserammoniaandgood-qualityresourceswithDjibouti’saccesstotheRedSeaandIndianOcean.KenyaandTanzaniacouldcreatesupplyanddemandforgreenhydrogengiventhedemandforfertilisersinKenyaandthestrategicpositionofTanzaniaontheChineseSilkRoutewiththeBagamoyoharbourproject(AHP,2019).TheDemocraticRepublicoftheCongoisalreadybeingbackedbyGermanyforthedevelopmentandconstructionoftheworld’slargesthydroelectricdam.InMauritania,twomajorgreenhydrogenprojectsareunderway:Aman(30GWofwindandsolarPV)andNour(10GWofrenewablesandpotentiallythefirstAfricanoffshorewindfarm.NamibiahasannouncedbilateraltradeagreementswithBelgium,GermanyandtheNetherlands(IRENA,2022d)andhasalsoannouncedaUSD9.4billioninvestmenttodevelopa300ktH2/yeargreenhydrogenproject.AchallengeforAfricaiswaterscarcity,butgreenhydrogencouldprovideanopportunitytotacklethischallengeinsteadofaggravatingit.EvenforlowLCOHscenarios,watersupply,inthemostconservativecase,throughdesalination,representsonlylessthan4%ofthetotalLCOH(seeMethodology),whichmeansitisrelativelycheapwhencomparedwiththehydrogensupply.Thewatersupplysystemcouldbeexpandedtocaterforotherwateruses(e.g.sanitary)atarelativelysmallcostpenaltyforthehydrogenbutprovidingtheeconomiesofscaleneededtoachievelowwatercosts.Otherchallengesarethelackofenergyaccess,lowelectrificationrateandlowdeploymentofrenewables.Thismeanshydrogenproductionforexportneedstoconsiderthesecompetingneedsforrenewablecapacity.Ifplannedtogether,hydrogencouldhavesocio‑economicbenefitsacrossthesedimensionsandaccelerateprogressratherthanhinderit.Forinstance,projectscouldincludeprovisionsforaminimumshareofenergyforlocalusersorbylargereconomiesofscale,lowerfinancingcostsandsupplychaindevelopmentforrenewablesleadingtolowercostsofenergy.MeasurestofosterinnovationandcreatenewjobsinAfrica,couldbeembodiedinpoliciestosupporttheproduction,useandexportofgreenhydrogenfromcountrieswithabundantresources.Greenhydrogencanabsorbexcessrenewableelectricity,leadingtohighersystemefficienciesandenergysecurity(IRENAandAfDB,2022).Figure3.9showsthehydrogensupplycostcurvesforkeyAfricancountries.Thecurveshowsthecostofgreenhydrogenasafunctionofthetechnicalpotentialfromutility-scalePV,onshorewindoroffshorewind.Foranoptimisticcostscenario,EgyptandMauritaniareachcostlevelsbelowUSD1.1/‌kgH2withpotentialsof40EJ/year(Egypt)and60EJ/year(Mauritania),whichwouldalreadybeenoughtosatisfytheentireprimarysupplyoftheAfricancontinentin2019.AllsixcountrieshaverelativelyflatsupplycurvesandmostcostsareunderUSD1.4/kgH2.Tounlockthisfuture,capitalcostsforsolarPVwouldneedtoreachvaluesaslowasUSD340/kWcombinedwithalowcost(USD130/kWe)oftheelectrolyserandahighefficiency.IncreasingthecapitalcostsofsolarPVby20%andtheelectrolyserbyalmost2.5timeswouldincreasethecoststotheUSD1.8/‌kgH2toUSD2.3/kgH2range.36Box3.1.(Continued)FIGURE3.9.Greenhydrogensupply-costcurvesforselectedAfricancountriesin20500.811.21.41.61.82010203040506070802050scenarioHydrogenproductioncost(USD/kgH)Hydrogenproductioncost(USD/kgH)1.51.71.92.12.32.52.72.93.13.33.5010203040506070802050scenarioHydrogentechnicalpotential(EJ/yr)Hydrogentechnicalpotential(EJ/yr)EgyptDem.Rep.oftheCongoEthiopiaKenyaNamibiaMauritaniaoptimisticpessimisticNotes:(Topchart)CAPEX:PV:USD278-573/kW,onshorewind:USD829-1088/kW,offshorewind:USD1494‑1540/kW,electrolyser:USD134/kWe.Electrolyserefficiency:87%(HHV).WACCrange:6-11%.(Bottomchart)CAPEX:PV:USD253-416/kW,onshorewind:USD888-1006/kW,offshorewind:USD1369‑1540/kW,electrolyser:USD326/kWe.Electrolyserefficiency:82%(HHV).WACCrange:7-12%.Commonassumptionsforbothcharts:ElectrolyserCAPEXandefficiencysetequalforallcountries.Technicalpotentialhasbeencalculatedbasedonlandavailabilityconsideringseveralexclusionzones(protectedareas,forests,permanentwetland,croplands,urbanareas,slopeof5%[PV]and20%[onshorewind],populationdensity),wateravailability.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL37Bycomparingthedemandfortheyear2050,theLCOHofeachregioncanbedeterminedthroughthesupply-costcurvesofthesinglecountriesandregions(Figure3.10).ThecountriesbestsuitedfordomesticgreenhydrogenproductionandconsumptionappeartobeChina,IndiaandtheUnitedStates:allpresentalargeproductionpotentialatlowLCOH(USD0.65/kgH2toUSD0.78/kgH2)mainlybecauseoftheirhigh-qualitysolarresources.EuropeancountriessuchasFrance,Germany,ItalyandSpainarecharacterisedbyahigherLCOH,aroundUSD0.8/kgH2toUSD1.1/kgH2.Theproductionpotentialisusuallyquitelargeevenforthesecountries;onlyItalyhasalowereconomicallyviablepotential(1000petajoulesatLCOHlowerthanUSD1.15/kgH2)duetoitsorographyanddenseurbanisation.Ontheotherhand,theUnitedKingdompresentsahigherLCOH(USD1/kgH2toUSD2/kgH2)mainlybecauseofitspoorsolarresourcequality.FIGURE3.10.Levelisedcostofhydrogenrangein2050derivedfromsupply-demandanalysis00.511.522.533.544.5RepublicofKoreaJapanUkraineRestofEuropeArgentinaRussianFederationTurkeyGermanyUnitedKingdomSoutheastAsiaFranceSub-SaharanAfricaMiddleEastandNorthAfricaBrazilItalyIndonesiaRestofAsiaEuropeSouthAfricaPortugalCanadaLatinAmericaSpainSaudiArabiaUnitedStatesIndiaOceaniaMexicoAustraliaColombiaMoroccoChileChinaLevelisedcostofhydrogen(USD/kgH)PessimisticOptimisticNotes:Levelisedcostofhydrogenderivedfromsupply-costcurvesofindividualcountriesandregionsbasedontheirestimatedhydrogendemandfor2050.Wateravailabilityforelectrolysisisconsideredinthehydrogensupply-costcurves.38Anadditionalassessmentwasmadeforrelevantcountriesonlyforthe2020costscenario.TheresultingLCOHsarefoundtobeequaltoUSD85/MWhandUSD190/MWhandifcomparedwiththecostsofnaturalgasof2020‑21ofaroundUSD30/MWh(Statista,2021),arestillnotcompetitiveenough.Thecostsproducedbythisassessmentfortheyear2050underoptimisticcostassumptionsrangefromUSD0.65/kgH2toUSD1.5/kgH2consideringaproductionpotentialof9000EJ/year,consideringwaterscarcityasanexclusioncriterion(Figure3.11).Thispotentialhydrogensupplyismanytimesthevalueofthefutureglobalhydrogendemand(inallsectors)of74EJ/yearaswellasthetotalglobalfinalenergydemand(614EJ/year).ThesetwodemandscouldbemetbysupplywithLCOHofUSD0.7/kgH2andUSD0.8/kgH2,respectively.FIGURE3.11.Globalsupply-costcurveofgreenhydrogenfortheyear2050underoptimisticassumptions00.511.522.533.54Levelisedcostofhydrogen(USD/kgH)0200040006000800010000Hydrogentechnicalpotential(EJ/yr)ChinaRestoftheworldRussianFederationSaudiArabiaSub-SaharanAfricaUnitedStatesArgentinaAustraliaBrazilCanadaMENAregionGlobalprimaryenergysupplyin2050:614EJGlobalhydrogendemandin2050:74EJNote:Thelandexclusioncriteriaaccountnotonlyforlandtypology,protectedareas,slopeandpopulationdensity,butalsoforwateravailability.Thecostassumptionsarethoseofthe2050optimisticscenario,reportedinFigure2.1.TheWACCvaluesarealsothoseoftheoptimisticscenarioshowninFigure2.2.ElectrolyserCAPEXandefficiencysettoUSD134/kWeand87.5%(HHV).Herewaterscarcityisnotincludedamongtheexclusioncriteria.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL39Figure3.12showstheglobalallocationofhydrogenproductionanditscostfortheyear2050underoptimisticassumptions.Inthiscasewateravailabilitywasalsoaccountedfor.Itcanbeseen,incomparisonwiththe2030scenariomap(Figure3.7),thatareaswherethecostofhydrogenhadincreasedtovaluesaboveUSD5/kgH2arenowbelowthisvalue.AnexampleofthisphenomenonisthePampasregioninArgentina,whichisalmostexclusivelyusedforagriculture(i.e.croplands).Therefore,theonlyviablehydrogengenerationsystemisthroughwindonshore,whichhasalmostthreetimestheCAPEXofPV(USD333/kWofsolarPVversusUSD912/kW).ThesegenerationsystemsarealsoaffectedbythehighWACCinArgentinaofalmost13%.FIGURE3.12.Globalmapoflevelisedcostofgreenhydrogenin2050consideringwaterscarcity10.621.532.543.54.5LCOH>55NoteligibleUSD/kgHNotes:GeospatialdistributionofLCOHlowerthanUSD5/kgH2for2050underoptimisticassumptions,seenotesofFigure3.6forspecificvalues.Inthisrepresentationlandexclusioncriteriaalsoaccountsforwateravailability.Disclaimer:Thismapisprovidedforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplyanyendorsementoracceptancebyIRENA.Ontheotherhand,Figure3.12providesaviewoftheregionsinwhichtheinclusionofwateravailabilityasanexclusioncriterionhasthehighestimpact.Someofthemostpromisingareasarestronglyunderminedbythelackofwatersources.NorthernChina,south-westernAustraliaandaridzonesingeneralarenotsuitablefortheproductionofgreenhydrogenifwateravailabilityisconsidered,despiteshowinggreatpotentialinproducingamongthelowest-costhydrogen.ThemostaffectedregionsbywaterscarcityareSaudiArabiaandtheMiddleEast/NorthAfricaregion,whichseetheireconomicpotentialbelowUSD2/kgH2decreaseby94%and84%,respectively(Figure3.13).China,withtheexclusionoftheitsnorthernterritories(whichwouldpresentahighyieldoflow-costhydrogen)decreasesitseconomicpotential(lowerthanUSD2/‌kgH2)by59%.40FIGURE3.13.EffectofwaterconstraintsonlandeligibilityforonsiteproductionofgreenhydrogenConsideringwaterstressNotconsideringwaterstress0%20%40%Non-eligibleland(%)60%80%100%AustraliaUnitedStatesSouthAfricaMexicoRestofAsiaChinaMoroccoEasternAsiaMiddleEastandNorthAfricaSaudiArabiaNote:Landexclusioncriteriaregardlandtypology,protectedareas,terrainslopeandpopulationdensity.Theimpactofwateravailabilityasanexclusioncriterionishighlighted.Itisnecessarytoaddthatremotenesswasnotincludedasanexclusioncriterion.Therefore,remoteareas,namelyNorthernCanada,SiberiaandtheTibetanPlateau,wereincludedintheassessment.Realistically,eventhoughinsomecasestheseareasmightproducecompetitivelypricedhydrogen,thenecessaryinvestmentininfrastructure(iftechnicallypossible)toconnectproductiontodemandofpotentialofftakerswouldsignificantlyincreasethecost.GLOBALHYDROGENTRADETOMEETTHE1.5°CCLIMATEGOAL:PARTIII–GREENHYDROGENCOSTANDPOTENTIAL41REFERENCESAgoraEnergiewende,etal.(2020),"Makingthemostofoffshorewind:Re-evaluatingthepotentialofoffshorewindintheGermanNorthSea,"AgoraEnergiewende,BerlinAHP(AfricanHydrogenPartnership)(2019),“GreenAfricanhydrogenoperationalplanning,”https://899bf48d-9609-4296-ac4c-db03c22bc639.filesusr.com/ugd/6a6d83_9a8692e3a4b64dad969fad9e9c6e68ee.pdf.Amatulli,G.etal.(2018),“DataDescriptor:Asuiteofglobal,cross-scaletopographicvariablesforenvironmentalandbiodiversitymodelingBackground&Summary,”https://‌doi.‌org/10.1038/‌sdata.2018.40.Bolinger,M.andG.Bolinger(2022),“LandRequirementsforUtility-ScalePV:AnEmpiricalUpdateonPowerandEnergyDensity,”pp.1-6.CopernicusClimateChangeService(2017),“ERA5:fifthgenerationofECMWFatmosphericreanalysesoftheglobalclimate,”CopernicusClimateChangeServiceClimateDataStore(CDS),https://cds.climate.copernicus.eu/cdsapp#!/dataset/reanalysis-era5-single-levels?tab=overview.DNVAS(2021),“Energytransitionoutlook2021executivesummary:Aglobalandregionalforecastto2050,”p.40,https://eto.dnv.com/2021.DNVGL(2019),“Energytransitionoutlook2019:Aglobalandregionalforecastto2050”,technicalreport,https://eto.dnvgl.com/2019.Enevoldsen,P.andM.Z.Jacobson(2021),“Datainvestigationofinstalledandoutputpowerdensitiesofonshoreandoffshorewindturbinesworldwide,”EnergyforSustainableDevelopment,Vol.60,pp.40–51,InternationalEnergyInitiative,https://doi.org/10.1016/j.esd.2020.11.004.ERI(EnergyResearchInstituteofAcademyofMacroeconomicResearchoftheNationalDevelopmentandReformCommission)&ChinaNationalRenewableEnergyCentre(2017),ChinaRenewableEnergyOutlook.Fraunhofer(2021),“PtXatlas,”DeV-KopSysproject,https://maps.iee.fraunhofer.de/ptx-atlas/.FraunhoferISE(2020),"Agrivoltaics:AguidelineforGermany–Opportunitiesforagricultureandtheenergytransition",www.ise.fraunhofer.de/en.Friedl,M.A.etal.(2010),“MODISCollection5globallandcover:Algorithmrefinementsandcharacterizationofnewdatasets,”RemoteSensingofEnvironment,Vol.114/1,pp.168–182,Elsevier,https://doi.org/10.1016/J.RSE.2009.08.016.Gao,J.(2017),DownscalingGlobalSpatialPopulationProjectionsfrom1/8-degreeto1-kmGridCells.,NCARTechnicalNote(No.NCAR/TN-537+STR),https://doi.org/10.5065/D60Z721H.42Hofste,R.etal.(2019),Aqueduct3.0:UpdatedDecision-RelevantGlobalWaterRiskIndicators,WorldResourcesInstitute,https://doi.org/10.46830/writn.18.00146.Howarth,R.W.andM.Z.Jacobson(2021),“Howgreenisbluehydrogen?,”EnergyScienceandEngineering,Vol.9/10,pp.1676–1687,https://doi.org/10.1002/ese3.956.Huehmer,R.etal.(2011),“Costmodelingofdesalinationsystems,”Internationaldesalinationassociationworldcongress,Perth.HydrogenEurope(2020),StrategicResearchandInnovationAgendaFinalDraftOctober2020Contents,https://hydrogeneurope.eu/reports/.IEA(InternationalEnergyAgency)(2021),WorldEnergyOutlook2021,revisedversionOctober2021,IEA,Paris.IEA(2019),WorldEnergyOutlook2019,IEA,Paris,https://doi.org/10.1787/caf32f3b-en.IRENA(InternationalRenewableEnergyAgency)(2022a),GlobalHydrogenTradetoMeetthe1.5°CClimateGoal:PartI–Tradeoutlookfor2050andwayforward,IRENA,AbuDhabi.IRENA(2022b),Globalhydrogentradetomeetthe1.5°Cclimategoal:PartII–Technologyreviewofhydrogencarriers,IRENA,AbuDhabi.IRENA(2022c),WorldEnergyTransitionsOutlook2022:1.5°CPathway,IRENA,AbuDhabi.IRENA(2022d),Geopoliticsoftheenergytransformation:Thehydrogenfactor,IRENA,AbuDhabi.IRENA(2021),WorldEnergyTransitionsO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