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RENEWABLE POWER GENERATION COSTS IN 2022

RENEWABLE

POWER

GENERATION

COSTS IN 2022

2023

RENEWABLE POWER GENERATION COSTS IN 2022

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.

Citation: IRENA (2022), Renewable power generation costs in 2022, International Renewable Energy Agency, Abu Dhabi.

ISBN 978-92-9260-544-5

Acknowledgements

This report was developed under the guidance of Roland Roesch (Director, IRENA Innovation and Technology Center) and

Michael Taylor (IRENA).

The report was authored by Michael Taylor, Sonia Al-Zoghoul and Pablo Ralon (IRENA), with assistance from Olga Sorokina

(European Energy Link Group).

The authors are grateful for the valuable contributions from Erick Ruiz Araya, Francis De Jaeger, Juan Pablo Jimenez Navarro,

Binu Parthan and Ludovico Del Vecchio (IRENA) in the preparation of this study.

This report benefited from the reviews and comments of numerous experts, including Ana Andrade (Direção Geral de Energia

e Geologia [DGEG]), Alex Campbell and Rebecca Ellis (IHA), Manuel Quero (Sunntics), Alexander Hogeveen Rutter (ISA),

Christoph Walter (DEA), Yuetao Xi (CREEI) and Feng Zhao (GWEC). All opinions and errors remain those of the authors.

Publications, editorial and communications support were provided by Francis Field, Stephanie Clarke, Nicole Bockstaller and

Daria Gazzola..

The report was copy-edited by Jonathan Gorvett and Stefanie Durbin, and a technical review was provided by Paul Komor.

The graphic design was provided by Ignacio de la Concepción Sanz.

For further information or to provide feedback: publications@irena.org

This report is available for download: www.irena.org/publications

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 officials, 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.

About IRENA

TThe International Renewable Energy Agency (IRENA) is an intergovernmental organisation

that supports countries in their transition to a sustainable energy future and serves as the

principal platform for international co-operation, a centre of excellence, and a repository of

policy, technology, resource and financial knowledge on renewable energy. IRENA promotes the

widespread adoption and sustainable use of all forms of renewable energy, including bioenergy,

geothermal, hydropower, ocean, solar and wind energy, in the pursuit of sustainable development,

energy access, energy security and low-carbon economic growth and prosperity. www.irena.org

The growing competitiveness

of renewable power continues to

provide the most compelling pathway

to the decarbonisation of the global

energy system

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RENEWABLEPOWERGENERATIONCOSTSIN20222RENEWABLEPOWERGENERATIONCOSTSIN2022©IRENA2023Unlessotherwisestated,materialinthispublicationmaybefreelyused,shared,copied,reproduced,printedand/orstored,providedthatappropriateacknowledgementisgivenofIRENAasthesourceandcopyrightholder.Materialinthispublicationthatisattributedtothirdpartiesmaybesubjecttoseparatetermsofuseandrestrictions,andappropriatepermissionsfromthesethirdpartiesmayneedtobesecuredbeforeanyuseofsuchmaterial.Citation:IRENA(2022),Renewablepowergenerationcostsin2022,InternationalRenewableEnergyAgency,AbuDhabi.ISBN978-92-9260-544-5AcknowledgementsThisreportwasdevelopedundertheguidanceofRolandRoesch(Director,IRENAInnovationandTechnologyCenter)andMichaelTaylor(IRENA).ThereportwasauthoredbyMichaelTaylor,SoniaAl-ZoghoulandPabloRalon(IRENA),withassistancefromOlgaSorokina(EuropeanEnergyLinkGroup).TheauthorsaregratefulforthevaluablecontributionsfromErickRuizAraya,FrancisDeJaeger,JuanPabloJimenezNavarro,BinuParthanandLudovicoDelVecchio(IRENA)inthepreparationofthisstudy.Thisreportbenefitedfromthereviewsandcommentsofnumerousexperts,includingAnaAndrade(DireçãoGeraldeEnergiaeGeologia[DGEG]),AlexCampbellandRebeccaEllis(IHA),ManuelQuero(Sunntics),AlexanderHogeveenRutter(ISA),ChristophWalter(DEA),YuetaoXi(CREEI)andFengZhao(GWEC).Allopinionsanderrorsremainthoseoftheauthors.Publications,editorialandcommunicationssupportwereprovidedbyFrancisField,StephanieClarke,NicoleBockstallerandDariaGazzola..Thereportwascopy-editedbyJonathanGorvettandStefanieDurbin,andatechnicalreviewwasprovidedbyPaulKomor.ThegraphicdesignwasprovidedbyIgnaciodelaConcepciónSanz.Forfurtherinformationortoprovidefeedback:publications@irena.orgThisreportisavailablefordownload:www.irena.org/publicationsDisclaimerThispublicationandthematerialhereinareprovided“asis”.AllreasonableprecautionshavebeentakenbyIRENAtoverifythereliabilityofthematerialinthispublication.However,neitherIRENAnoranyofitsofficials,agents,dataorotherthird-partycontentprovidersprovidesawarrantyofanykind,eitherexpressedorimplied,andtheyacceptnoresponsibilityorliabilityforanyconsequenceofuseofthepublicationormaterialherein.TheinformationcontainedhereindoesnotnecessarilyrepresenttheviewsofallMembersofIRENA.ThementionofspecificcompaniesorcertainprojectsorproductsdoesnotimplythattheyareendorsedorrecommendedbyIRENAinpreferencetoothersofasimilarnaturethatarenotmentioned.ThedesignationsemployedandthepresentationofmaterialhereindonotimplytheexpressionofanyopiniononthepartofIRENAconcerningthelegalstatusofanyregion,country,territory,cityorareaorofitsauthorities,orconcerningthedelimitationoffrontiersorboundaries.AboutIRENATTheInternationalRenewableEnergyAgency(IRENA)isanintergovernmentalorganisationthatsupportscountriesintheirtransitiontoasustainableenergyfutureandservesastheprincipalplatformforinternationalco-operation,acentreofexcellence,andarepositoryofpolicy,technology,resourceandfinancialknowledgeonrenewableenergy.IRENApromotesthewidespreadadoptionandsustainableuseofallformsofrenewableenergy,includingbioenergy,geothermal,hydropower,ocean,solarandwindenergy,inthepursuitofsustainabledevelopment,energyaccess,energysecurityandlow-carboneconomicgrowthandprosperity.www.irena.orgThegrowingcompetitivenessofrenewablepowercontinuestoprovidethemostcompellingpathwaytothedecarbonisationoftheglobalenergysystem©JasonWinter/Shutterstock.com4RENEWABLEPOWERGENERATIONCOSTSIN2022AsthenationsoftheworldpreparetoconveneintheUnitedArabEmiratesforCOP28,theInternationalRenewableEnergyAgency(IRENA)continuestowarnthattheworldisnotontracktomeetitssharedcommitmentsundertheParisAgreementtoavoiddangerousclimatechange.Thepathwaytoa1.5°Cfuturerequiresincreasedglobalambitioninrenewablesdeployment,enabledbyphysicalinfrastructure,policyandregulations,andstrengthenedinstitutionalandworkforcecapabilities.Sinceshortlyafteritsinception,IRENAhastrackedtrendsinthecostsandcompetitivenessofrenewablepowergenerationtechnologies,chartingthefallingcostsoftheenergytransitionbeyondmostcommentatorsexpectations.Thishasopenedupnewavenuesfordecarbonisationviaelectrificationtodeliveraclimate-safefuture,asotheroptionshavefailedtoscale.Thecompetitivenessofrenewablepowertodayhaspositionedelectrificationasacentralpillaroftheenergytransition.Thisoffersanopportunitytoplacerenewableenergyatthecentreofthesolutionwhilesimultaneouslyenhancingenergysecurity,reducingenergycostsandenablingforward-lookingindustrialdevelopment.WiththelingeringimpactofCOVID-19supplychaindisruptions,rapidgrowthinsolarphotovoltaic(PV)deploymentandrisingcommodityprices,2022wasamixedyearforsolarandwindpowercosts,asmanycountriessawincreasingcostsinrealterms.Despitethis,theglobalaveragecostofelectricityfromsolarPVfellby2%andthatofonshorewindby5%in2022,asChinaonceagaindominatednewcapacityadditions.Theglobalaveragecostofelectricityfromutility-scalesolarPVfelltoUSD0.049perkilowatt-hour(kWh)andthatofonshorewindtoUSD0.033/kWh.Thismeantthatin2022,atleast86%ofnewutility-scalesolarPVcapacityadditionsand87%ofonshorewindcapacityadditionshadlowercoststhannewfossilfueloptions.FOREWORDFrancescoLaCameraDirector-GeneralInternationalRenewableEnergyAgency5FOREWORDYetthisisonlyapartialviewof2022;thefossilfuelpricecrisisinEuropehadramificationsaroundtheworldforenergyprices.Asaresult,thecompetitivenessofrenewablepowergenerationtechnologiesin20countrieswhereIRENAhasdetailedfossilfuelandrenewablecostdataimprovedsignificantlyin2022inallcasesforsolarPVandonshorewind.Theyear2022alsohighlightedtheveryreal-butoftenoverlookedoverthelastdecade-energysecuritybenefitsofrenewablepower.InEurope,theexistingrenewablecapacityinstalledsince2010reducedelectricitygenerationcostsbyUSD176billionfromwhattheymighthaveotherwisebeen.Astheconsequencesofclimatechangebecomeevermoreevident,thefallingcostsandimprovedcompetitivenessofrenewablepowergenerationoverthelastdecaderepresentabeaconfortheworldtosteertoward.Wehavethetoolstoacceleratetheenergytransition,anddoingsoisdramaticallycheaperthanthebusiness-as-usualapproach,butwemustactnow.6RENEWABLEPOWERGENERATIONCOSTSIN2022Figures,tablesandboxes.....................................8Abbreviations.............................................14Highlights.................................................15EXECUTIVESUMMARY........................................16LATESTCOSTTRENDS........................................24Introduction.........................................................................25ONSHOREWIND............................................68Highlights...........................................................................69Introduction.........................................................................70Windturbinecharacteristicsandcosts.................................................70Totalinstalledcosts..................................................................73Capacityfactors.....................................................................77Operationandmaintenancecosts......................................................82Levelisedcostofelectricity............................................................83SOLARPHOTOVOLTAICS......................................88Highlights...........................................................................89Recentmarkettrends.................................................................90Totalinstalledcosts..................................................................90Capacityfactors...................................................................104Operationandmaintenancecosts....................................................105Levelisedcostofelectricity..........................................................108OFFSHOREWIND...........................................114Highlights.........................................................................115Introduction.......................................................................116Totalinstalledcosts................................................................121Capacityfactors...................................................................127Operationandmaintenancecosts....................................................131Levelisedcostofelectricity..........................................................13201020304CONTENTS7EXECUTIVESUMMARYCONCENTRATINGSOLARPOWER..............................134Highlights.........................................................................135Introduction.......................................................................136Totalinstalledcosts................................................................138Capacityfactors...................................................................142Operationandmaintenancecosts....................................................145Levelisedcostofelectricity...........................................................147HYDROPOWER............................................150Highlights.........................................................................151Totalinstalledcosts................................................................152Capacityfactors...................................................................160Operationandmaintenancecosts....................................................162Levelisedcostofelectricity..........................................................163GEOTHERMAL.............................................166Highlights.........................................................................167Introduction.......................................................................168Totalinstalledcosts................................................................170Capacityfactors......................................................................172Levelisedcostofelectricity..........................................................173BIOENERGY...............................................176Highlights.........................................................................177Bioenergyforpower...............................................................178Biomassfeedstocks................................................................178Totalinstalledcosts................................................................179Capacityfactorsandefficiency......................................................182Operationandmaintenancecosts....................................................183Levelisedcostofelectricity..........................................................184REFERENCES..............................................188ANNEXICOSTMETRICMETHODOLOGY........................191Changingfinancingconditionsforrenewablesandtheweightedaveragecostofcapital....195Totalinstalledcostbreakdown:DetailedcategoriesforsolarPV.........................202ANNEXIITHEIRENARENEWABLECOSTDATABASE.................204ANNEXIIIREGIONALGROUPINGS............................206060708058RENEWABLEPOWERGENERATIONCOSTSIN2022FIGURESFigureS.1ChangeincompetitivenessofsolarandwindbycountrybasedonglobalweightedaverageLCOE,2010-2022...17FigureS.2Globalfossilfuelcostsavingsintheelectricitysectorin2022fromrenewablepoweraddedsince2000...18FigureS.3GlobalLCOEfromnewlycommissioned,utility-scalerenewablepowertechnologies,2021-2022.............19FigureS.4GlobalLCOEfromnewlycommissionedutility-scalerenewablepowertechnologies,2010and2022.......22Figure1.1GlobalLCOEfromnewlycommissionedutility-scalerenewablepowertechnologies,2021-2022...........32Figure1.2GlobalweightedaverageLCOEfromnewlycommissioned,utility-scalerenewablepowergenerationtechnologies,2010-2022.............36FigureB1.2aFossilfuel-firedLCOEbyfuel/technologyandyearfor20countries,2010-2022.............38FigureB1.2bFossilfuel-firedLCOEbyfuel/technologyandcostcomponentfor12countries,2010...............39Figure1.3Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEfromnewlycommissionedsolarPV,onshorewindpowerandoffshorewindpower,2010-2022..........................42Figure1.4Fossilgasandcoalpricemarkerorimportcostbycountry,2004to2022.......................44Figure1.5Annualnewutility-scalerenewablepowergenerationcapacityaddedatalowercostthanthecheapestfossilfuel-firedoption,2010-2022.....45Figure1.6Renewablegenerationandnetsavingsinnon-OECDcountriesfromnewcompetitiverenewablegenerationcapacityaddedbyyear,2010-2022...47Figure1.7Competitivenesstrendsforutility-scalesolarPVbycountryandyear,2010-2022..........................50Figure1.8Annualchangeincompetitivenessofnewutility-scalesolarPVcapacityaddedbycountryandyear,2010-2022..........................52Figure1.9Competitivenesstrendsforonshorewindbycountryandyear,2010-2022..........................54Figure1.10Annualchangeincompetitivenessofnewonshorewindcapacityaddedbycountryandyear,2010-2022..........55Figure1.11TheglobalweightedaveragetotalinstalledcostlearningcurvetrendsforsolarPV,CSP,andonshoreandoffshorewind,2010-2022............57Figure1.12TheglobalweightedaverageLCOElearningcurvetrendsforsolarPV,CSP,andonshoreandoffshorewind,2010-2022..........................58Figure1.13Largesttwo-yearfossilfuelpriceincreasesduringthefirstandsecondoilshockcomparedto2020to2022...619FIGURES,TABLESANDBOXESFigure1.14GlobalandEuropeanannualfuelsavingsintheelectricitysectorfromrenewablepowergenerationdeploymentsince2000in2022........................62Figure1.15IncreasesinEuropeanwholesaleelectricityprices,andpricestolargeconsumersandhouseholds,2019-2022..........................64Figure1.16ChangesinannualnewsolarPVcapacityadditionspercapitacomparedtoLCOEtrendsbycountry,2010-2022..........................66Figure2.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforonshorewind,2010-2022............69Figure2.2Weightedaverageonshorewindrotordiameterandnameplatecapacityevolution,2010-2022................71Figure2.3Windturbinepriceindicesandpricetrends,1997-2023...................72Figure2.4Totalinstalledcostsofonshorewindprojectsandglobalweightedaverage,1984-2022..........................73Figure2.5Totalinstalledcostsofonshorewindprojectsin15countries,1984-2022...74Figure2.6Onshorewindweightedaveragetotalinstalledcostsinsmallermarketsbycountry,2010-2022..................76Figure2.7Onshorewindweightedaveragecapacityfactorsfornewcapacityin15countries,1984-2022.............78Figure2.8Onshorewindweightedaveragecapacityfactorsfornewprojectsinsmallermarketsbycountryandyear,2010-2022..........................80Figure2.9Changeintheweightedaveragecapacityfactorandwindspeedfornewprojectsbycountrybetween2010and2020......................81Figure2.10Full-service(initialandrenewal)O&MpricingindexesandweightedaverageO&McostsinBrazil,Denmark,Germany,Ireland,Japan,Norway,SwedenandtheUnitedStates,2008-2022.........82Figure2.11LCOEofonshorewindprojectsandglobalweightedaverage,1984-2022...84Figure2.12WeightedaverageLCOEofcommissionedonshorewindprojectsin15countries,1984-2022...........85Figure2.13OnshorewindweightedaverageLCOEinsmallermarketsbycountryandyear,2010-2022..........................87Figure3.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforPV,2010-2022..............89Figure3.2AveragemonthlysolarPVmodulepricesbytechnologyandmanufacturingcountrysoldinEurope,2010to2022..............91FigureB3.1aAverageyearlysolarPVmodulepricesbytechnologysoldinEurope,2010to2021and2022Q1;average(left)andpercentageincrease(right)...........92FigureB3.1bPolysiliconpricingperkilogramme,percentchangeperyearandthree-yearmovingaverageofpolysiliconexcessmanufacturingcapacity,2003-H12023......................93Figure3.3TotalinstalledPVsystemcostbyprojectandweightedaverageforutility-scalesystems,2010-2022.................9610RENEWABLEPOWERGENERATIONCOSTSIN2022FigureB3.2aGlobalweightedaveragetotalinstalledcostsofutility-scalesolarPVsystemsandcostreductionsbysource,2010-2022..........................97FigureB3.2bGlobalweightedaveragetotalinstalledcostsofutility-scalesolarPVsystemsandcostreductionsbysource,2010-2016and2016-2022............97Figure3.4Utility-scalesolarPVtotalinstalledcosttrendsinselectedcountries,2010-2022..........................98Figure3.5Utility-scalesolarPVtotalinstalledcosttrendsintop20utility-scalemarkets,2021-2022................100Figure3.6Detailedbreakdownofutility-scalesolarPVtotalinstalledcostsbycountry,2022...................101Figure3.7Breakdownofutility-scalesolarPVtotalinstalledcostsbycountry,2018and2022.....................103Figure3.8Surveyresultsforthemedianall-inO&Mcostsforutility-scalesolarPVbycostcategoryandcountry,2020-2022....106Figure3.9Surveyresultsforthemedianall-inO&Mcostsforutility-scalesolarPVbycostcategoryandregion,2020-2022.....107Figure3.10Globalutility-scalesolarPVprojectLCOEandrange,2010-2022.........108FigureB3.3aDriversofthedeclineoftheglobalweightedaverageLCOEofutility-scalesolarPV,2010-2022................109FigureB3.3bSourceofthedeclineintheglobalweightedaverageLCOEofutility-scalesolarPVintwoperiods,2010-2016and2016-2022...........110Figure3.11Utility-scalesolarPVweightedaveragecostofelectricityinselectedcountries,2010-2022.........................111Figure3.12Utility-scalesolarPVweightedaverageLCOEtrendsintop20utility-scalemarkets,2021-2022................112Figure4.1Globalweightedaverageandrangeoftotalinstalledcosts,capacityfactorsandLCOEforoffshorewind,2010-2022.........................115Figure4.2AveragedistancefromshoreandwaterdepthforoffshorewindinEurope,Chinaandtherestoftheworld,2000-2022............118Figure4.3Distancefromshoreandwaterdepthforoffshorewindprojectsbycountry,1999-2025.........................119Figure4.4Projectturbinesize,globalweightedaverageturbinesizeandwindfarmcapacityforoffshorewind,2000-2022........................121Figure4.5Projectandglobalweightedaveragetotalinstalledcostsforoffshorewind,2000-2022.........................122Figure4.6Representativeoffshorewindfarmtotalinstalledcostbreakdownsbycountry/region,2013,2016,2017and2019..........................125Figure4.7InstallationtimeandMWinstalledperyearbyoffshorewindprojectinEurope,2010-2020.................126Figure4.8Projectandglobalweightedaveragecapacityfactorsforoffshorewind,2000-2022.........................12811FIGURES,TABLESANDBOXESFigure4.9Globalweightedaverageoffshorewindturbinerotordiameterandhubheight,2010-2022.........................128Figure4.10CapacityfactorandwindspeedtrendsbyprojectinEurope,2010-2025.....129Figure4.11Offshorewindcapacityfactorsandspecificpowerbyprojectandcountry...........................130Figure4.12OffshorewindprojectandglobalweightedaverageLCOE,2000-2022...133Figure5.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforCSP,2010-2022.......135Figure5.2TotalinstalledcostbreakdownofCSPplantsbytechnology(2010-2011and2019-2020).........138Figure5.3CSPtotalinstalledcostsbyprojectsize,collectortypeandamountofstorage,2010-2022.........................140Figure5.4CapacityfactortrendsforCSPplantsbydirectnormalirradianceandstorageduration,2010-2022................143Figure5.5AverageprojectsizeandaveragestoragehoursofCSPprojects,2010-2022.........................144Figure5.6Capacityfactors,storagehoursandthesolarresource,2010-2022...145Figure5.7LCOEforCSPprojectsbytechnologyandstorageduration,2010-2022.....147Figure5.8ReductioninLCOEforCSPprojects,2010-2020,bysource...............148Figure6.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforhydropower,2010-2022.............151Figure6.2Totalinstalledcostsbyprojectandglobalweightedaverageforhydropower,2010-2022.............155Figure6.3Totalinstalledcostsforsmallandlargehydropowerprojectsandtheglobalweightedaverage,2010-2022.......156Figure6.4Distributionoftotalinstalledcostsoflargeandsmallhydropowerprojectsbycapacity,2010-2015and2016-2022.....................157Figure6.5Totalinstalledcostbyprojectandcapacity-weightedaveragesforlargehydropowerprojectsbycountry/region,2010-2022.......159Figure6.6Totalinstalledcostsbyprojectandcapacity-weightedaveragesforsmallhydropowerprojectsbycountry/region,2010-2022.......159Figure6.7LargehydropowerprojectLCOEandcapacity-weightedaveragesbycountry/region,2010-2022.......165Figure6.8SmallhydropowerprojectLCOEandcapacity-weightedaveragesbycountry/region,2010-2022.......165Figure7.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforgeothermal,2010-2022..........167Figure7.2Geothermalpowertotalinstalledcostsbyproject,technologyandcapacity,2007-2022.........................171Figure7.3Capacityfactorsofgeothermalpowerplantsbytechnologyandprojectsize,2007-2022.........................172Figure7.4LCOEofgeothermalpowerprojectsbytechnologyandprojectsize,2007-2022.........................17412RENEWABLEPOWERGENERATIONCOSTSIN2022TABLESTableH.1Totalinstalledcost,capacityfactorandLCOEtrendsbytechnology,2010and2022......................15Table2.1Totalinstalledcostrangesandweightedaveragesforonshorewindprojectsbycountry/region,2010and2022.......75Table2.2Country-specificaveragecapacityfactorsfornewonshorewind,2010,2021and2022......................79Table2.3RegionalweightedaverageLCOEandrangesforonshorewindin2010and2022......................86Table3.1Globalweightedaveragecapacityfactorsforutility-scalePVsystemsbyyearofcommissioning,2010-2022.........................104Table4.1ProjectcharacteristicsinChinaandEuropein2010,2015and2021......120Table4.2Regionalandcountryweightedaveragetotalinstalledcostsandrangesforoffshorewind,2010and2022.......125Table4.3Weightedaveragecapacityfactorsforoffshorewindprojectsinsevencountries,2010and2022...........129Table4.4RegionalandcountryweightedaverageLCOEofoffshorewind,2010and2022.....................133Table5.1All-in(insuranceincluded)O&McostestimatesforCSPplantsinselectedmarkets,2019-2020................146Figure8.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforbioenergy,2010-2022..............177Figure8.2Totalinstalledcostsofbioenergypowergenerationprojectsbyselectedfeedstocksandcountry/region,2000-2022.........................181Figure8.3Totalinstalledcostsofbioenergypowergenerationprojectsfordifferentcapacityrangesbycountry/region,2000-2022.........................181Figure8.4Projectcapacityfactorsandweightedaveragesofselectedfeedstocksforbioenergypowergenerationprojectsbycountryandregion,2000-2022.........................182Figure8.5LCOEbyprojectandweightedaveragesofbioenergypowergenerationprojectsbyfeedstockandcountry/region,2000-2022.........................185Figure8.6LCOEandcapacityfactorbyprojectofselectedfeedstocksforbioenergypowergenerationprojects,2000-2022.........................186FigureA1.1Countryandtechnology-specificrealafter-taxWACCassumptionsfor2021and2022.....................198FigureA2.1DistributionofprojectsbytechnologyandcountryinIRENA'sRenewableCostDatabase.....................20513FIGURES,TABLESANDBOXESTable6.1Totalinstalledcostbreakdownbycomponentandcapacity-weightedaveragesfor25hydropowerprojectsinChina,IndiaandSriLanka,2010-2016,andEurope,2021........154Table6.2Totalinstalledcostsforhydropowerbyweightedaverageandcapacityrange,2000-2022..................157Table6.3Hydropowerprojectweightedaveragecapacityfactorsandrangesforlargehydropowerprojectsbycountry/region,2010-2022..........161Table6.4Hydropowerprojectweightedaveragecapacityfactorsandrangesforsmallhydropowerprojectsbycountry/region,2010-2022..........161Table6.5HydropowerprojectO&Mcostsbycategoryfromasampleof25projects........................163Table8.1Projectweightedaveragecapacityfactorsofbioenergyfiredpowergenerationprojects,2000-2022......183TableA1.1StandardisedassumptionsforLCOEcalculations..................194TableA1.2O&McostassumptionsfortheLCOEcalculationofonshorewindprojects...........................200TableA1.3O&McostassumptionsfortheLCOEcalculationofPVprojects......201TableA1.4O&McostassumptionsfortheLCOEcalculationofonshorewindprojects...........................201TableA1.5BoScostbreakdowncategoriesforsolarPV.......................203BOXESBox1.1Theimportanceofunderstandingrealandnominalpricesinaperiodofhighinflation.....................31Box1.2Fossilfuelpowergenerationcosts....37Box3.1RecentuptickinsolarPVmodulecosts...............................92Box3.2Driversofthedeclineinutility-scalesolarPVtotalinstalledcosts..........97Box3.3Unpackingthedeclineinutility-scalesolarPV'sLCOEfrom2010to2022......................10914RENEWABLEPOWERGENERATIONCOSTSIN2022ABBREVIATIONSACalternatingcurrentBoSbalanceofsystemCCGTcombined-cyclegasturbineCCScarboncaptureandstorageCHPcombinedheatandpowerCO2carbondioxideCODcommercialoperationdateCSPconcentratingsolarpowerDCdirectcurrentDCFdiscountedcashflowDNIdirectnormalirradiationDWSdiamondwiresawingEEAEuropeanEconomicAreaEIATheU.S.EnergyInformationAdministrationEPCengineering,procurementandconstructionETSEmissionsTradingSchemeEUEuropeanUnionFFfossilfuelGWgigawattsHJTheterojunctionHTFheattransferfluidIBCinterdigitatedbackcontactIEATheInternationalEnergyAgencyIFCTheInternationalFinanceCorporationILRinverterloadingratioIMFInternationalMonetaryFundIPCCTheIntergovernmentalPanelonClimateChangeIPPindependentpowerproducerkgkilogrammekWhkilowatthourLCOElevelisedcostofelectricityLNGliquefiednaturalgasmgmilligrammesmmmillimetresMWmegawattsMWhmegawatthourO&MoperationsandmaintenanceOECDtheOrganisationofEconomicCo-operationandDevelopmentOEMoriginalequipmentmanufacturerOPEXoperationalexpensesPERCpassivatedemitterandrearcellPPAPowerPurchaseAgreementPTCparabolictroughcollectorPVphotovoltaicSTsSolartowersTTFTitleTransferFacilityTWhterawatthoursUSDUSdollarsVREvariablerenewableenergyWACCweightedaveragecostofcapitalWACCwattμmmicrometre15HIGHLIGHTSHIGHLIGHTSIn2022,theglobalweightedaveragecostofelectricityfromnewlycommissionedutility-scalesolarphotovoltaics(PV),onshorewind,concentratingsolarpower(CSP),bioenergyandgeothermalallfell.Thiswasdespiterisingmaterialsandequipmentcosts.ChinawasthekeydriveroftheglobaldeclineincostsforsolarPVandonshorewind,withothermarketsexperiencingamuchmoreheterogeneoussetofoutcomesthatsawcostsincreaseinmanymajormarkets.Fornewlycommissionedonshorewindprojects,theglobalweighted‑averagelevelisedcostofelectricity(LCOE)fellby5%between2021and2022,fromUSD0.035/kWhtoUSD0.033/kWh.Forutility‑scalesolarPVprojects,theglobalweighted‑averageLCOEdecreasedby3%year-on-yearin2022,toUSD0.049/kWh.Foroffshorewind,thecostofelectricityofnewprojectsincreasedby2%,incomparisonto2021,risingfromUSD0.079/kWhtoUSD0.081/kWhin2022.Thefossilfuelpricecrisisof2022wasatellingreminderofthepowerfuleconomicbenefitsthatrenewablepowercanprovideintermsofenergysecurity.In2022,therenewablepowerdeployedgloballysince2000savedanestimatedUSD521billioninfuelcostsintheelectricitysector.Duetosoaringfossilfuelprices,the2021-2022periodsawoneofthelargestimprovementsinthecompetitivenessofrenewablepowerinthelasttwodecades.Lookingatthetrendsince2010:•In2010,theglobalweighted‑averageLCOEofonshorewindwas95%higherthanthelowestfossilfuel-firedcost;in2022,theglobalweighted‑averageLCOEofnewonshorewindprojectswas52%lowerthanthecheapestfossilfuel-firedsolutions.•EventhisimprovementwassurpassedbythatofsolarPV,however.Thisrenewablepowersourcewas710%moreexpensivethanthecheapestfossilfuel-firedsolutionin2010;however,drivenbyaspectaculardeclineincosts,itcost29%lessthanthecheapestfossilfuel-firedsolutionin2022.TableH.1Totalinstalledcost,capacityfactorandLCOEtrendsbytechnology,2010and2022TotalinstalledcostsCapacityfactorLevelisedcostofelectricity(2022USD/kW)(%)(2022USD/kWh)20102022Percentchange20102022Percentchange20102022PercentchangeBioenergy29042162-26%72721%0.0820.061-25%Geothermal2904347820%8785-2%0.0530.0566%Hydropower14072881105%44464%0.0420.06147%SolarPV5124876-83%141723%0.4450.049-89%CSP100824274-58%303619%0.3800.118-69%Onshorewind21791274-42%273735%0.1070.033-69%Offshorewind52173461-34%384210%0.1970.081-59%16RENEWABLEPOWERGENERATIONCOSTSIN2022EXECUTIVESUMMARYTHECOMPETITIVENESSOFRENEWABLEPOWERIMPROVEDDRAMATICALLYIN2022,DESPITECOSTINFLATION.Afterdecadesoffallingcostsandimprovingperformanceinsolarandwindtechnologies,theeconomicbenefitsofrenewablepowergeneration–inadditiontoitsenvironmentalbenefits–arenowcompelling.Indeed,duetosoaringfossilfuelprices,the2021to2022periodsawoneofthelargestimprovementsinthecompetitivenessofrenewablepowerinthelasttwodecades.Thiswasdespitemostmarkets,excludingChina,seeingequipmentpriceincreasesforsolarphotovoltaic(PV)modulesandwindturbines.Itwasalsodespitethefactthatmanymarketsexperiencedoverallsolarwindpowercostinflation.In2021,ofthe20countriesforwhichIRENAhasdetaileddata,ninesawthecompetitiveness1oftheirutility-scalesolarPVimprovebymorethantheglobalweighted‑averagelevelisedcostofelectricity(LCOE)forthatyear.In2022,eightcountriessawsuchanimprovement.Foronshorewind,thesituationwasevenstarker.Inthe2021‑2022period,ofthe20countriesexaminedforonshorewind,15sawtheirlargestabsoluteimprovementincompetitivenesssincedetaileddatabecameavailable.Thisincludedmarketswhichsawtotalinstalledcostsincrease,withfossilfuelpricesrisingfarmorethanthepricesoftheirrenewablealternatives.Therateatwhichthecompetitivenessofsolarandwindpowerhasimprovedasthecostofelectricityfromsolarandwindpowerhasfallenisalsoquiteremarkable.1IRENAhascalculatedacompetitivenessmetricfor20countries.Thisisbasedonaweightedaveragecostofnewfossilfuelscalculatedfromproject-levelcapitalcostdataandcountry-specificfossilgasandcoalfuelmarkerpricestoelectricitygenerators.Thecompetitivenessmetricsubtractsthecountryweightedaveragefossilfuellevelisedcostofelectricity(LCOE)fromtherenewablepowerLCOE,sonegativevaluesrepresentrenewablepowerLCOEslowerthanthoseoffossilfuels.17EXECUTIVESUMMARYIn2010,theglobalweighted‑averageLCOEofonshorewindwasUSD0.107/kilowatthour(kWh).Thiswas95%higherthanthelowestfossilfuelcostofUSD0.056/kWh.By2022,theglobalweighted‑averageLCOEofnewonshorewindprojectswasUSD0.033/kWh,52%lowerthanthecheapestfossilfuel-firedoption,whichhadrisentoUSD0.069/kWh(FigureS.1).Overthesameperiod,theglobalweighted‑averageLCOEofoffshorewindwentfrombeing258%moreexpensivethanthecheapestfossilfueloptiontobeingjust17%moreexpensive,asthecostfellfromUSD0.197/kWhtoUSD0.081/kWh.Concentratingsolarpower(CSP)sawitsglobalweighted‑averageLCOEfallfrom591%higherthanthecheapestfossilfueloptionin2010to71%higherin2022.EventhisimprovementwassurpassedbythatofsolarPV,however.Thisrenewablepowersourcehadaglobalweighted‑averageLCOEofUSD0.445/kWhin2010–710%moreexpensivethanthecheapestfossilfuel-firedoption.Yet,by2022,aspectaculardeclineincosts–toUSD0.049/kWh–madesolarPV’sglobalweighted‑averageLCOE29%lowerthanthecheapestfossilfuel-firedoption.Indeed,withfossilfuel-firedpowergenerationcostsrisingin2021-2022,primarilybecauseoffossilfuelpriceincreases,around86%,or187gigawatts(GW),ofnewlycommissioned,utility-scalerenewablepowergenerationprojectscommissionedin2022hadcostsofelectricitylowerthantheweighted‑averagefossilfuel-firedcostbycountry/region.Thisfigurewas8%higherthanthe174GWestimatedfor2021.Overall,between2010and2022,1120GWofrenewablepowergenerationwithalowerLCOEthanthatoftheweighted‑averagefossilfuel-firedLCOEbycountry/regionwasdeployed.RELCOElessthanfossilfuelRELCOEgreaterthanfossilfuel---SolarphotovoltaicConcentratingsolarpowerOffshorewindOnshorewindthpercentilethpercentileFigureS.1ChangeincompetitivenessofsolarandwindbycountrybasedonglobalweightedaverageLCOE,2010-2022Note:TheglobalweightedaverageLCOEdatabytechnologyandthefossilfuelLCOEdatausedtoderivethischartispresentedindetailinChapter1;RE=renewableenergy.18RENEWABLEPOWERGENERATIONCOSTSIN2022RENEWABLEPOWERPROVIDESMAJORENERGYSECURITYBENEFITS.Thefossilfuelpricecrisisof2022wasatellingreminderofthepowerfuleconomicbenefitsthatrenewablepowercanprovide,intermsofenergysecurity.Indeed,2022wastheyearthattheenergysecuritybenefitsofrenewableswerewidely‘rediscovered’.Unlikeenergysecuritypoliciesthatfocusonthephysicalsupplyoffossilfuels,renewablepowerreducestheeconomiccostsofexposuretoinherentlyvolatilefossilfuelpricesbyreducingtheneedforfossilfuelsandtheirimport.Inshort,substitutestofossilfuelsthathavestablecostsovertheirlifetime,suchasrenewablepowerandenergyefficiency,andcanbedeployedrapidly,providebyfarthelargestenergysecuritybenefits.Thismayseemobvious,butinthescrambletosecureadditionalfossilfuelsuppliesin2022,thiswasoftenasecondarypriorityamongpolicymakers.2In2022,therenewablepowerdeployedgloballysince2000savedanestimatedUSD521billion3infuelcostsintheelectricitysectoralone(FigureS.2).InEurope,thatfigurewasUSD176billion.Inaddition,itispossiblethatthebuild-outofrenewablessince2010probablysavedthecontinentfromafull-blowneconomiccrisis,asintheabsenceofrenewablepowergeneration,4thedirecteconomiccostsofthefossilfuelpricehikeswouldhavebeenmuchhigher.GlobalelectricitysectorfuelsavingsinUSD521billionOnshorewindUSDbillionSolarphotovoltaicUSDbillionOshorewindUSDbillionBiomassUSDbillionHydroUSDbillionAsiaUSDbillionEuropeUSDbillionSouthAmericaUSDbillionNorthAmericaUSDbillionEurasiaUSDbillionAfricaUSDbillionGeothermalMiddleEastOceaniaCentralAmericaandtheCaribeanFigureS.2Globalfossilfuelcostsavingsintheelectricitysectorin2022fromrenewablepoweraddedsince20002Itisworthnotingthatpolicymakerswereoverwhelmedbytheimpactofthefossilfuelpricecrisisin2022.Itisthereforenotsurprisingthat,givenlimitedinstitutionalresourcesandthewide-rangingcallonpolicymakers,differentareaswereprioritised.Itdoesrepresentsomethingofamissedopportunity,however.3Thisiscouldbealowestimate.Itisprobablethatthehigherfossilfueldemandin2022–asaresultofthehypotheticallowerrenewablesdeployment–wouldhaveraisedpricesevenhigherandmadethesupplyshockevenmoredamaging.4Thisisbeforecountingtheimpactoftheuseofheatpumps,solarthermalwaterheatersandenergyefficiencymeasures.19EXECUTIVESUMMARYIN2022,THEGLOBALWEIGHTEDAVERAGECOSTOFELECTRICITYFROMSOLARPV,ONSHOREWIND,CSP,BIOENERGYANDGEOTHERMALALLFELL.Fornewlycommissionedonshorewindprojects,theglobalweighted‑averageLCOEfellby5%between2021and2022,fromUSD0.035/kWhtoUSD0.033/kWh(FigureS.3).In2022,Chinawasonceagainthelargestmarketfornewonshorewindcapacityadditions,withitsshareofglobalnewdeploymentrisingfrom41%to50%between2021and2022.Thisresultedinmarketswithhigherinstalledcostsdecreasingtheirsharerelativeto2021.IfChinahadbeenexcluded,theglobalweighted‑averageLCOEcurveforonshorewindfortheperiodwouldhaveremainedflat.Fornewlycommissioned,utility‑scalesolarPVprojects,from2021to2022,theglobalweighted‑averageLCOEdecreasedby3%,toUSD0.049/kWh.Thiswasdrivenbya4%declineintheglobalweighted‑averagetotalinstalledcostforthistechnology,fromUSD917/kilowatt(kW)in2021toUSD876/kWfortheprojectscommissionedin2022.Overall,thesolarPVexperiencein2022wasmixed,withdifferentmarketsmovingindifferentdirections.ThedeclineinLCOEin2022waslessthanthe13%year-on-yeardeclineexperiencedin2021,as11ofthetop20utility-scalesolarPVmarketsforwhichIRENAhasdetaileddatasawtheirtotalinstalledcostincreaseinrealterms,with12seeinganincreaseinnominalterms.Someoftheseincreasesweresubstantial–therewasa34%hikeinFranceandGermany,forexample,whileGreecesawanestimated51%costincreasedrivenbyrisingPVmoduleandcommoditypricesattheendof2021andinto2022.Someofthisvariabilityrepresentsthenormalvariationinindividualprojectcosts,butitisclearcommodityandlabourcostinflationhadasignificantimpactonsomemarkets.Thattheglobalweightedaveragecostofelectricityfromnewlycommissionedutility-scalesolarPVfellin2022,however,wasduetothefactthatChinahadlowercoststhanmostmarketsanditsshareofglobalutility-scalesolarPVdeploymentincreasedfrom38%in2021toanestimated45%in2022.Year-on-yearpercentagereduction-SolarphotovoltaicConcentratingsolarpowerOnshorewindOshorewind-3%+2%-5%-2%-13%-22%+18%BioenergyHydropowerGeothermalFigureS.3GlobalLCOEfromnewlycommissioned,utility-scalerenewablepowertechnologies,2021-202220RENEWABLEPOWERGENERATIONCOSTSIN2022Theoffshorewindmarketadded8.9GWofnewcapacityin2022.Thiswouldhavebeenanewrecord,ifnotfortheunprecedentedexpansionseenin2021,when21GWwasaddedglobally,drivenbyasurgeinChina.Indeed,in2022,thefallinChina’sshareinnewcapacityadditionsandthecommissioningofprojectsinnewmarketssawtheglobalweighted‑averagecostofelectricityofnewprojectsincreaseby2%,incomparisonto2021,fromUSD0.079/kWhtoUSD0.081/kWh.Theincreaseinglobalweighted‑averagetotalinstalledcosts(fromUSD3052/kWin2021toUSD3461/kWin2022)waspartiallyoffsetbytheincreaseincapacityfactorsfornewlycommissionedprojectsfrom39%in2021to42%in2022.Fornewlycommissionedbioenergyforpowerprojects,theglobalweighted‑averageLCOEfellby13%between2021and2022,fromUSD0.071/kWhtoUSD0.061/kWh.Thisoccurredastheshareofnew,low-cost,projectscommissionedinChinaandBrazilincreasedin2022.Forgeothermalpowerprojects,between2021and2022theglobalweighted‑averageLCOEofthetenprojectscommissionedfellby22%,toUSD0.056/kWh.Newlycommissionedhydropowerprojects,incontrast,sawtheirglobalweighted‑averageLCOEincreaseby18%between2021and2022,fromUSD0.052/kWhtoUSD0.061/kWh.In2022,anumberofprojectsthatexperiencedsignificantdelaysandlargecostoverrunswerecommissionedpartially,orinfull.Asaresult,theglobalweightedaveragetotalinstalledcostofnewhydropowerprojectsincreasedfromUSD2299/kWin2021toUSD2881/kWin2022,ariseof25%.BETWEEN2010AND2022,SOLARANDWINDPOWEREXPERIENCEDREMARKABLECOSTDEFLATION.Theexperienceofthelasttwoyearshaschangedstakeholders’understandingofpriceexpectationsinfossilfuelmarkets,whilealsodemonstratingthevulnerabilityofcountriesdependentonfossilfuelsforpowergeneration.Evenpriortothefossilfuelpricecrisisin2022,however,renewableswereout-competingfossilfuels.Indeed,whennewelectricitygenerationcapacitywasrequiredin2021,renewablessignificantlyundercutnewfossilfueladditions,whileinmanylocationsrenewablesevenundercutexistingplants,oncetheimpactoffinancialsupportwasfactoredout.Thecompetitivenessofrenewablepowersawasignificantleapin2022asfossilfuelpricesspiked.Since2010,solarPVhasexperiencedthemostrapidcostreductions.Theglobalweighted‑averageLCOEofnewlycommissionedutility‑scalesolarPVprojectsdeclinedfromUSD0.445/kWhtoUSD0.049/kWhbetween2010and2022–adecreaseof89%(FigureS.4).ThisreductioninLCOEhasbeenprimarilydrivenbydeclinesinmoduleprices.Thesefellbyaround90%betweenDecember2009andDecember2022,despiteanincreasein2022.Importantreductionshavealsooccurredinbalanceofplantcosts,operationsandmaintenance(O&M)costsandthecostofcapital.21EXECUTIVESUMMARYForonshorewindprojects,between2010and2022,theglobalweighted‑averagecostofelectricityfellby69%,fromUSD0.107/kWhtoUSD0.033/kWh.Costreductionsforonshorewindweredrivenbytwokeyfactors:windturbinecostdeclinesandcapacityfactorincreasesfromturbinetechnologyimprovements.WindturbinepricesoutsideofChinafellby39-55%between2010and2022,dependingonthewindturbinepriceindex,whilethedeclineinChinawasalmosttwo-thirds,at64%.Theglobalweighted‑averagecapacityfactorofnewlycommissionedprojectsincreasedfrom27%in2010to39%forthosecommissionedin2021.Thisglobalweightedaveragethenfellbackto37%in2022,astheshareofnewdeploymenttakenbyChinaincreased,owingtothecountry'sgenerallypoorerwindresourcelocations.Fornewlycommissionedoffshorewindprojects,between2010and2022theglobalweighted‑averageLCOEdeclinedfromUSD0.197/kWhtoUSD0.081/kWh,areductionof59%.In2010,ChinaandEuropesawnewlycommissionedoffshoreprojectswithweightedaverageLCOEsofUSD0.189/kWhandUSD0.198/kWh,respectively.In2021,newlycommissionedEuropeanprojectshadaweighted‑averagecostofUSD0.056/kWh,whichwaslowerthantheUSD0.083/kWhcostinChinathatyear.In2022,theweighted‑averageLCOEinEuropeincreasedtoUSD0.074/kWhasarangeofmoreexpensiveprojectswerecompleted,includinginnewmarkets.Europe’sLCOE,however,wasstillaround4%lowerthanChineseprojectscompletedin2022,withtheseseeingaweightedaverageofUSD0.077/kWh.CSPdeploymentremainsdisappointing,withlessthan0.1GWaddedin2022andglobalcumulativecapacitystandingat6.5GWattheendof2022.Fortheperiod2010to2022,theglobalweighted‑averagecostofnewlycommissionedCSPprojectsfellfromUSD0.38/kWhtoUSD0.118/kWh–adeclineof69%.TheLCOEofCSPfellrapidlybetween2010and2020,despiteannualvolatility.Since2020,however,thecommissioningofprojectsthatwereeitherdelayedorincludednoveldesignshasseentheglobalweighted‑averagecostofelectricityfromthistechnologystagnate.CSPwouldbenefitfromadditionalpolicysupport,giventheimpressivecostreductionsithasmanagedwithjust6.5GWofcumulativedeployment.Bioenergyforpowerprojectssawitsglobalweighted‑averageLCOEexperienceacertaindegreeofvolatilityduringthe2010‑2020period,withoutanotabletrendupwardsordownwards.In2022,however,bioenergy’sglobalweighted‑averageLCOEofUSD0.061/kWhwas13%lowerthanthe2021valueandone-quarterlowerthanthevaluein2010,whichhadbeenUSD0.082/kWh.Forgeothermalprojects,theglobalweighted‑averageLCOEfell22%between2021and2022,toUSD0.056/kWh.Thiswas6%higherthanin2010,butwellwithintheUSD0.053/kWhtoUSD0.091/kWhrangeseenbetween2013and2021.22RENEWABLEPOWERGENERATIONCOSTSIN2022Newlycommissionedhydropowerprojectssawtheirglobalweighted‑averageLCOEriseby47%between2010and2022,fromUSD0.042/kWhtoUSD0.061/kWh.Thiswasstilllowerthanthecheapestnewfossilfuel-firedelectricityoptionin2022,despitethefactthatglobalweightedaveragecostsincreasedby18%thatyear.Theincreasein2022over2021wasdrivenbythecommissioningofanumberofprojectsthatexperiencedverysignificantcostoverruns,notablyinCanada.USDkWhFossilfuelcostrangeBiomassGeothermalHydropowerSolarphotovoltaicConcentratingsolarpowerOffshorewindOnshorewindthpercentilethpercentileFigureS.4GlobalLCOEfromnewlycommissionedutility-scalerenewablepowertechnologies,2010and2022Note:Thesedataarefortheyearofcommissioning.ThethicklinesaretheglobalweightedaverageLCOEvaluederivedfromtheindividualplantscommissionedineachyear.TheLCOEiscalculatedwithproject-specificinstalledcostsandcapacityfactors,whiletheotherassumptions,includingweightedaveragecostofcapital(WACC),aredetailedinAnnexI.Thegreybandrepresentsthefossilfuel-firedpowergenerationcostin2022,assumingthat2021fossilgaspriceswerethecorrectlifetimebenchmarkratherthanthecrisispricesof2022.Whilethebandsforeachtechnologyandyearrepresentthe5thand95thpercentilebandsforrenewableprojects.©MichaelTaylorZacariasdaMata©Shutterstock.com01LATESTCOSTTRENDSP.Steeger©Gettyimages.com25INTRODUCTIONTheyear2022wasarguablyoneofthemostdramaticindecadesfortheenergysector.AsglobalsupplychainchallengesstilllingeredfromtheCOVID-19globalpandemicmixedwithreducedRussiangasflowstoEuropeasaresultofthecrisisinUkraine,thesituationdeterioratedfromaseriousconcerntoafull-fledged,fossilfuelpricecrisis,theimpactofwhichwasfeltaroundtheworld.Thecombinationofsoaringfossilfuelenergycostsandcontinuedincreasesinthepriceofcommoditiesandmanufacturedgoods(onlyinpartdrivenbyhigherfuelcosts)saw2022alsobecometheyearwhenacostoflivingsqueezeputsignificantstrainonhouseholdsandbusinesses.Policymakersreactedtotheemergingenergysecurityandfossilfuelinflationcrisismoreorlessrapidly,asthedepthandseverityofthechallengebecameincreasinglyapparent.Actionsbypolicymakersgenerallytookthreeforms:•IdentifyingandsecuringadditionalsuppliesoffossilgasinEuropefromexistingpipelinesorimportsin2022andbeyond.Thiswentalongwithcommunicatingdemandreductiontargetsandenactingminimumgasstoragelevelstonavigatethewinterheatingseasondemandpeak.•Passingmeasurestoinsulatehouseholdsandbusinessesfromtheeffectsofunsustainablyhighincreasesinenergycostsontheirbudgetstoavoidhardshipandbusinessfailures.•Implementingpoliciesforthelongertermtomitigatetheimpactofthefossilfuelpricecrisisbyacceleratingtheenergytransitionandaddressingtheweaknessesinenergymarketsexposedbythecrisis.•Policymakersinnon-OECDcountrieswerealsoactive,usingcashtransfers,taxmeasures,fueldutyreductions,fuelsubsidies,pricecapsandlimitsonpriceincreases(OECD,2023).26RENEWABLEPOWERGENERATIONCOSTSIN2022PolicymakersmovedtoshoreupsuppliesoffossilgasinEuropeviaexistingpipelinesandthroughincreasedliquefiednaturalgas(LNG)imports.PlanstoexpandLNGimportcapacity,notablyinGermanyviafloatingoffloadingandre-gasificationvessels,wereputintoaction,whilehigherthroughputatexistingLNGimportterminalsalsooccurred.ThiscausedLNGcargopricesaroundtheworldtoincrease,asEuropeoutbidcompetitorsdivertingcargoesofLNGfrom(predominantly)developingmarketstoEurope,withtheassociatedchallengesforthosemarkets.Europealsoactedtosecuremoresuppliesinthelongertermthroughcontractualarrangements.ThirteenEuropeancountries,plustheEuropeanUnion(EU),haveannouncedcontractualarrangementsforadditionalfossilgasvolumes(eitherbypipelineorLNGimports)withstartdatesrangingfrom2022to2027(Sgarvatti,TagliapietraandTrasi,2022).Europeangovernmentshavealsobeenactiveinimplementingpoliciestoshieldhouseholdsandbusinessesfromtheunsustainablepriceincreasesinfossilgas,thermalcoalandelectricitythatoccurredin2022.All27EUmembers,aswellasNorwayandtheUnitedKingdom,haveimplementedreliefmeasuresinsomeform,withtotalcommitmentsworthEUR657billion(euros)or692billioninUnitedStatesdollars(USD)intheEU,EUR103billion(USD108billion)intheUnitedKingdomandEUR8.1billion(USD8.5billion)inNorway(Sgaravattietal.,2023).InGermany,Europe’slargesteconomy,thevalueofthissupportisestimatedat7.4%ofgrossdomesticproduct(GDP),whileinallbutsixofthe29countriesforwhichtherearedata,thevalueexceeds2%ofnationalGDP.Afteradecadeofrelativecomplacency,countriesareagainlearningthattheenergysecurityimplicationsofcontinuedrelianceonfossilfuelsisnotjustanotionalcost.ActionshavenotbeenrestrictedtoEurope,either.Overall,non-EuropeanadvancedeconomieshavecommittedUSD163billiontomeasurestoinsulateconsumersfromtheworstimpactsofrisingfossilfuelprices,whilethefigureforemergingmarketsanddevelopingeconomieswasUSD114billion(IEA,2023).PolicymakersinArgentina,Chile,China,Colombia,CostaRica,Indonesia,India,TürkiyeandSouthAfricawereactiveinreducingtheburdenonhouseholdsandbusinesses.Actionsincludedfuelandelectricitysubsidies,reductionsinfueltaxesandexciseduties,directcashtransfers,fuelpricefreezesandcaps,valueaddedtaxreductionsandsupportforpublictransport(OECD,2023).Amajorresponsetothefossilfuelpricecrisishasbeenanewimpetustoacceleratetheenergytransitiontounlockgreaterenergysecurityandeconomicandenvironmentalbenefitssooner.Inresponsetothecrisis,inMay2022theEuropeanCommissionproposedraisingthe2030targetforrenewablesfromthe40%decidedin2021to45%aspartofitsREPowerEUplan.Thefinalagreement(adoptedinMarch,2023)resultedinabindingtargetof42.5%,withtheambitiontoreach45%.Ifthe45%targetwashit,thiswouldincreaserenewablecapacityfromtheprevious1067gigawatts(GW)to1236GWfor2030(EuropeanCommission,2022and2023).Theproposalalsoincludedgoalstodoubleheatpumpdeploymentsandstrengthensupplychainsforrenewablesandheatpumps,aswellasfurtherintegratinggeothermalandsolarthermalenergysystems.Acceleratingpermittingisalsoconsideredvitaltoacceleratedeploymentsespeciallyforwindpower,whereoffshorewindisseenasasignificantopportunitytocompetitivelyreducegasconsumptioninthepowersector.Actionsarealsoplannedtoacceleratestationaryenergystorage.Theplanalsoincludedtargetsfor2030of35billioncubicmetres(bcm)productionperannumofbiomethane,alongwithdomesticrenewablehydrogenproductionof10milliontonnesperannum,withanequivalentamountofimports.27LATESTCOSTTRENDSIntheUnitedStates,theInflationReductionActincludessignificantincentivestobothdevelopdomesticsupplychainsandacceleratethedeploymentofrenewablepowergeneration,storageandothertechnologiesfortheenergytransition(TheWhiteHouse,2022).Despitecontinuinghighcommodityprices–evenifmanyhaveeasedsincetheirpeaksin2022–andsupplychainchallenges,2022representedanotherrecordfornewrenewablecapacityadditions,with295GW5added(IRENA,2023a).Thiswas30GW(12%)higherthanthe264GWaddedin2021and2.6timestheadditionsin2010,when113GWwasadded.SolarPVcapacityadditionssurgedin2022,withthe191GWaddedrepresentinganincreaseof36%overthe141GWaddedin2021,6.5timeshigherthanthe29.4GWaddedoveradecadeagoin2012.Afterarecord105GWofonshorewindcapacitywasaddedin2020,drivenbyaremarkablesurgeinnewadditionsinChina,newcapacityadditionsfellforthesecondyearstraight.In2022,65.7GWofnewonshorewindcapacitywasadded,whichrepresentsa10%declineonthe72.6GWaddedin2021.Themaindriverinthedeclinein2022relativetotheadditionsin2021wastheUnitedStatesmarket,wherenewcapacityadditionsalmosthalvedcomparedto2021,droppingfrom14.3GWaddedin2021to7.8GWin2022.China’scapacityadditionsin2022increasedby3GWover2021to32GW.Offshorewindcapacityadditionsin2022were8.9GW,55%lowerthantherecord19.9GWaddedin2021.However,if2021hadnotbeenarecordyear,2022wouldhaverepresentedanewrecord,with34%morecapacityaddedthanthepreviousrecordof6.1GWaddedin2020.TheoverwhelmingdriveroftheslowinginnewcapacityadditionswasChina,wherenewcapacityadditionsdeclinedfromarecord17.4GWaddedin2021to4.1GWin2022.In2022,7.6GWofbioenergyforpowercapacitywasadded,downonthe8.1GWaddedin2021.Chinadominatedthenewcapacityadditionsin2022,with6.2GWofthetotaladded.Hydropowercapacityadditionswere20.4GWin2022,downslightlyonthe22.1GWaddedin2021.Geothermalforpowercapacityadditionsin2022werearound200megawatts(MW),whilethoseforconcentratingsolarpower(CSP)were126MW.Between2000and2022,renewablepowergenerationcapacityworldwideincreasedjustover4.5times,from752GWto3372GW(IRENA,2023a).Overall,withmodestcapacityadditionsofnuclearandfossilfuelsin2022,renewablesagaindominatedthenewcapacityadditions.Renewablesaccountedfor83%ofnewpowergenerationcapacityaddedin2022andhaveaveragedaround80%forthelastthreeyears.Theoutlookisfornewrenewablecapacityadditionrecordstobebrokenintheyearsaheadgiventhecompetitivenessofrenewablepowerintheglobalmarketandpolicyresponsestothefossilfuelpricecrisis,net-zeroemissionsambitions,andtheurgencyrequiredtokeeptheParisAgreementgoalsinplay.Thefactis,renewablepowergenerationhasbecome,almosteverywhere,thedefaultsourceofleast-costnewpowergeneration.5Alldatainthisreport,unlessexpresslyindicated,referstotheyearaprojectwascommissioned.Thisissometimesreferredtoasthecommercialoperationdate(COD).Thisisthedateatwhichaprojectbeginssupplyingelectricitytothegridonacommercialbasis.Itthereforecomesafteranyperiodofplanttestingorinjectionofsmallquantitiesofelectricityintothegridaspartofthecommissioningprocess.28RENEWABLEPOWERGENERATIONCOSTSIN2022IRENA’scostanalysisprogrammeIRENA’scostanalysisprogrammehasbeencollectingandreportingthecostandperformancedataofrenewablepowergenerationtechnologiessince2012.Thegoalistoprovidetransparent,up‑to‑datecostandperformancedatafromareliablesource,giventhatthesedataarevitalinensuringthepotentialofrenewableenergyisproperlytakenintoaccountbypolicymakers,energyandclimatemodellers,andotherstakeholders.IRENA’sMemberStatesalsorelyonthisdatacollectionandreporting.Withoutit,keydecisionmakersingovernmentandtheenergysectorwillstruggletocorrectlyidentifythemagnitudeoftherolerenewableenergycanplayinmeetingoursharedeconomic,environmentalandsocialgoalsfortheenergytransition.Withhighlearningrates6andrapidgrowthininstalledcapacityofrenewableenergytechnologies,accesstocomprehensiveandup-to-datedata–bymarketandtechnology–isessential.ThebodyofdatarepresentedbytheIRENARenewableCostDatabasealsoallowstimeseriesanalysisofkeytrendsincostsandperformance,helpingtosupportdecisionsaroundthenextstageintheenergytransition.IRENA’scostreportsalsoprovideanopportunitytoexaminerecenttrendsincommoditycostsandequipmentpricingandtheirimpactontotalinstalledcostsinthisperiodofcostinflation.IRENAmaintainstwocoredatabases,supplementedbymoregranulardataforarangeofmetrics.ThesehavebeencreatedtoensureIRENAcanrespondtoitsMemberStates’needswhilealsoensuringthatindustryandcivilsocietyhaveeasyaccesstothelatestrenewablepowergenerationcostandperformancedata.Thetwocoredatabasesare:•TheIRENARenewableCostDatabase:Thisincludesproject‑levelcostandperformancedataforaround2200GWofcapacityfromaround21500projects7commissioneduptoandincluding2022.•TheIRENAAuctionandPowerPurchaseAgreement(PPA)Database:Thisdatabasecontainsdataonaround13500projects,orprogrammeresults,wherepricingdataarenotdisclosedforindividualwinners.Insummarisingthelatestcostandperformancedataforprojectscommissionedin2022,aswellasthecostsandtrendsforimportantequipmentbenchmarks(e.g.solarphotovoltaic[PV]modules,windturbineprices,etc.)andtechnologycharacteristics(e.g.onshorewindturbinecapacitysizes),thisreportpresentsaconsistentsetofcoremetricswithwhichtomeasurethecostandperformanceofrenewablepowergenerationtechnologiesandhowtheyhaveevolvedovertime.ThebreadthanddepthofthedataintheIRENARenewableCostDatabaseallowsforameaningfulunderstandingofvariationsbetweencountriesandtechnologies,aswellasthroughtime.Thesevariationsarereportedacrosseachtechnologyandandcostmetricforananalysisofhowdifferentcostmetricshavechangedthroughtimebetweenparticulartechnologies(e.g.solarPVandonshorewind)andindifferentmarketsforthosetechnologies.6Learningratesaredefinedasthepercentagereductionincostorpriceforeverycumulativedoublinginproductionorinstallation.7Thisexcludesprojectswithaninstalledcapacityoflessthan1MW.29LATESTCOSTTRENDSInrecentyears,IRENAhasalsoinvestedmoreresourcesincollectingbenchmarkequipmentcostsandtotalinstalledcostbreakdowns,particularlyforsolarPV,tounderstandunderlyingcostreductiondriversandthedifferencesbetweenmarkets.IRENAhasalsoexpandedtherangeofcostandperformancemetricsittracks.Theagencynowreportsregularlyonanincreasingrangeofcostandperformancemetricsacrossawiderrangeofcountries.ThishasbeendrivenbytheneedtobetterunderstandcosttrendsandsupplychaindynamicstosupportdecisionmakersastheurgencyofscalinguprenewablepowerdeploymenttomeetcountrycommitmentsundertheParisAgreementhasbecomemoreacute.Theprimarygoalofthisreportremains,however,thereportingoftheconstituentdriversofrenewablepowergenerationprojectsthatenableanassessmentofthelevelisedcostofelectricity(LCOE)8anditsunderlyinginfluences.TheLCOEofagiventechnologyistheratiooflifetimecoststolifetimeelectricitygeneration,bothofwhicharediscountedbacktoacommonyearusingadiscountratethatreflectstheaveragecostofcapital.Thecostandperformancemetricscommontoalltechnologychaptersthereforeinclude:•totalinstalledcosts(includingcostbreakdowns,whenavailable)thatrepresentthetotalcostofcompletingaproject(e.g.includingprojectdevelopmentcosts,gridconnection,equipment,installation,civilengineering,contingency,etc.);•capacityfactors,calculatedastheratioofannualgenerationrelativetothetheoreticalcontinuousmaximumoutputoftheplant,expressedasapercentage;•operationsandmaintenance(O&M)costs;and•theLCOE.AnnexIdiscussesinmoredetailthemetricsused,theboundaryconditionsforcostcalculationsandthekeyassumptionstakeninrelationtotheweightedaveragecostofcapital(WACC),projecteconomiclifeandO&Mcosts.Whereappropriate,thechaptersalsoincludeadditionalcostandperformancemetricsthatallowforamoredetailedunderstandingofcomponentcostsandhowthesearedrivingtrendsintheLCOE.ThesecontextualdataandvariedcostmetricsallowIRENAnotonlytofollowtheevolutionofthecostsofrenewablepowergenerationtechnologies,butalsotoanalysewhattheunderlyingdriversare,atagloballevelandinindividualcountries.Theselayersofdataandthegranularityavailableprovidedeeperinsightsforpolicymakersandotherstakeholders.WherepossiblethisreportdiscussestheimpactoftherecentcommoditypriceincreasesandequipmentcostsontotalinstalledprojectcostsandLCOE.8Notethat‘LCOE’and‘costofelectricity’aresedinterchangeablyinthisreport,aswellastheterms‘weightedaverageLCOE’and‘weightedaveragecostofelectricity’,wheretheweightingisbyinstalledMWs.30RENEWABLEPOWERGENERATIONCOSTSIN2022Yet,althoughLCOEisausefulmetricforafirst-ordercomparisonofthecompetitivenessofprojects,itisastaticindicatorthatdoesnottakeintoaccountinteractionsbetweengeneratorsinthemarket.NeitherdoestheLCOEtakeintoaccountthatatechnology’sgenerationprofilemeansthatitsvaluemaybehigherorlowerthantheaveragemarketprice.Asanexample,CSPwiththermalenergystoragehastheflexibilitytotargetoutputduringhighcostperiodsintheelectricitymarket,irrespectiveofwhetherthesunisshining,whilesolarPV’svalueinthemiddleofthedayoftendeclinesathighpenetrationrates(albeit,notuniformlyovertheyear).TheLCOEalsofailstotakeintoaccountotherpotentialsourcesofrevenueorcosts.Forexample,insomemarkets,hydropowerandCSPwithstoragecouldearnsignificantrevenuefromprovidingancillarygridservices.Thisisnottypicallythecaseforstand-alonevariablerenewabletechnologies,howeverongoingtechnologyinnovationsforsolarandwindtechnologiesaremakingthesemoregridfriendly.Hybridpowerplants,withstorageorotherrenewablepowergenerationtechnologies,alongwiththecreationofvirtualpowerplantsthatmixgeneratingtechnologies,and/orotherenergysystemresources,canalltransformthenatureofvariablerenewabletechnologies.Thus,althoughLCOEisausefulmetricasastartingpointfordeepercomparison,itisnotasubstituteforelectricitysystemsimulations-andincreasingly,wholeenergysystemsimulations-thatcandeterminethelong-runmixofnewcapacitythatisoptimalinminimisingoverallsystemcosts,whilemeetingoveralldemand,minute-by-minute,overtheyear.Thisshouldbetakenintoaccountwheninterpretingthedatapresentedinthisreport.Otherkeypointsregardingthedatapresentedinthisreportthatshouldbeborneinmindare:•Allprojectdataarefortheyearofcommissioning,sometimesreferredtoasthecommercialoperationdate(COD).9Insomecasesthismeansaprojectconnectedtothegridmaynotqualifyforinclusionifnomeaningfulgenerationoccurs.10Leadtimesareimportant,withplanning,developmentandconstructionsometimestakingonetothreeyears,ormoreiflegalchallengesoccur,forsolarPVandonshorewindprojects;itcantakeuptofiveyearsormoreforCSP,fossilfuels,hydropowerandoffshorewindprojects.•Thecostmetricsexcludetheimpactofenergyfinancialsupporttorenewables.•LCOEresultsarecalculatedusingproject-leveltotalinstalledcostsandcapacityfactors.FortheWACC,technologyandcountry-specificWACCbenchmarkvaluesareusedfor100countriesfromIRENA’sWACCbenchmarktool.ThishasbeencalibratedwiththeresultsoftheIRENA,InternationalEnergyAgency(IEA)WindTask26andETHZurichcostoffinancesurvey.ForcountriesnotcoveredbytheWACCbenchmarktool,simplerassumptionsabouttherealcostofcapitalhavebeenmadefortheOrganisationofEconomicCo-operationandDevelopment(OECD)countriesandChinaontheonehand,andtherestoftheworldontheother.SeeAnnexIformoredetails.9Bottom-upbenchmarkanalysesundertakenbyotherorganisationsandinstitutions(e.g.BNEF,IEA,Lazrad,etc.)mayrefertocostsatthetimeafinancialinvestmentdecisionismade.ThereisthereforepotentiallyasignificanttimedifferencebetweenIRENAestimatesandothers.Forinstance,thecostofanonshorewindprojectforQ1ofayearbasedonafinancialinvestmentdecisionmightappearasacommissionedprojectcostpoint6-18monthslater,orevenlongerinsomecases.Itisofcoursemorecomplicatedthanthis,asactualcostsdependonwhenequipmentandengineering,procurementandconstruction(EPC)contractsaresigned.10Thisisoccasionallyanissuewherecontractrequirementsorsupportpoliciesusegridconnectiondatesasthebasisformeetingcontracttermsorqualifyingforsupport.31LATESTCOSTTRENDS•Capacityfactordataareprojectdevelopers’estimatesoftheaveragelifetimeyieldofprojects,orwherethesedataarenotavailable,estimatesbyIRENAbasedonthetechnologyandprojectlocation.Allcapacityfactorsinthisreportareforthenewlycommissionedprojectsinagivenyear,notthestockofinstalledcapacity.11•Allcostandcapacityfactordataareforthealternatingcurrent(AC)capacity,exceptforsolarPV.ForPV,totalinstalledcostsareindirectcurrent(DC)terms,andthecapacityfactoristhereforetheso-calledAC-DCcapacityfactortoensurethattheLCOEisthendirectlycomparablewithalltheothertechnologiesinthisreport(thatistosay,inACterms).•AlltotalinstalledcostdataandLCOEcalculationsexcludetheimpactofanyfinancialsupportavailabletothem.•O&Mcostdataareamixofcountry-specificdatafromavarietyofsourcesandregionalassumptions.TheO&Mcostsare“all-in”;thatistosay,theyincludecostslikeinsuranceandheadofficecostsharesthatarenotincludedinthird-partyO&Mcontracts.SeeAnnexIformoredetails.•Alldatacontainedwithinthisreportareforutility-scaleprojectsofatleast1MW,withtheexceptionofresidentialandsomecommercialsolarPV.•AllrenewablecapacitydataarefromIRENA’scapacitystatistics(IRENA,2023a)unlessotherwisenoted.•Dataforcostsandperformancefor2022arepreliminaryandsometimessubjecttorevision.•LCOEisastaticmeasureofcoststhatprovidesusefulinformationbuthasitslimits.11Thedataarethereforenotameasureofthespecificannualcapacityfactorofeachyearforeachproject,whichdependsontherelativewindresourceinagivenyear.Project-specificactualgenerationdatabyyearareavailableinsomecountriesbutarenotuniversallyavailableandthereforenotreportedbyIRENA.Globally,withsomeexceptions,thelast30yearshasbeenaperiodofrelativelylowinflationcomparedtothe1970sand1980swhichwereaffectedbythefirstandsecondoilshocks.Since1994inflationintheOECDhastypicallybeenintherange0.3%to4%,comparedto1971to1985,whereinflationdidnotdropbelow6%peryearandpeakedat16%in1974,thishasbeenaperiodofstability.Itmeantthatthedifferencebetween‘nominal’and‘real’pricesforthespanofafewyearshasnotbeenlargeandareasonableapproximationoftheactualvaluecouldbemade.Thisbreaksdownwheninflationishighandnominalvaluesfromevenfiveyearsago,ifnot‘deflated’intorealvaluescanbemisleading.Forinstance,usingtheUnitedStatesGDPdeflator,ifacanofdrinkcostUSD1in2001,inrealtermsthatwouldhavebeenUSD1.02in2002moneyduetoinflationreducingthevalueofmoneyastimepasses.Takingtoday’ssituation,ifthecanofdrinkcostUSD1in2021,itisworthUSD1.07in2022money.Thatdifferencemayseemsmall,butitisimportanttorealisethatifthecountry-levelweightedaveragetotalinstalledcostinrealterms(e.g.inUSD2022money)foraprojectcommissionedin2022isthesameasin2021,thatrepresentsa7%increaseinnominaltermsoccurredbetween2021and2022,apositivepercentageincreaseinrealtermscanthereforebeaverysignificantincreaseinnominalterms(e.g.thestickerpriceseenbythepurchaser).Wheninterpretingtheresultsinthefollowingsections,itisworthrememberingthispointwhentryingtoidentifyiftheresultsmakesensecomparedtothenominalvaluesthatmayhavebeenquotedinthemediaorareavailabletothereaderthroughothersources.Box1.1Theimportanceofunderstandingrealandnominalpricesinaperiodofhighinflation32RENEWABLEPOWERGENERATIONCOSTSIN2022Renewablepowergenerationscostsin2022Thesupplychainchallengesin2021,inpartstemmingfromtheCOVID-19pandemic,risingshippingcostsandcommoditypriceinflationin2022causedbythecrisisinUkrainehavebecomeapparentinincreasedcostsinanumberofmarkets.However,thecostinflationhasnotbeensystemicacrosstheboard,withdifferentmarketsbeingmore,orless,exposedtocostinflationbasedonprojectleadtimesandthesizeofthemarket.12Despitethis,theglobalweightedaverageLCOEsforsolarandwindtechnologieshavenotincreasedmateriallyin2022.ThisisdueprimarilytoChina’shighshareofdeploymentinsolarPVandonshoreandoffshorewind.InChina,thecostshaveeithernotincreasedsignificantly–asinthecaseofPV–orcontinuedtofallunderintensecompetition–asinthecasesofonshorewindandoffshorewind.In2022,theglobalweightedaverageLCOEofnewonshorewindprojectscommissionedfellby5%year‑on‑year(Figure1.1),fromUSD0.035/kilowatthour(kWh)in2021toUSD0.033/kWh.Chinawasonceagainthelargestmarketfornewonshorewindcapacityadditionsin2022,withitsshareofnewdeploymentrisingfrom41%in2021to50%in2022,resultinginmarketswithhigherinstalledcostsdecreasingtheirsharerelativeto2021.ExcludingChinawouldhaveseentheglobalweightedaverageLCOEforonshorewindflatfortheperiod2021to2022.InChina,over-capacityamongChinesewindturbinemanufacturersandtheendofsomesubsidiessawprojectdevelopersaggressivelynegotiatelowerturbineprices,incontrasttothetrendelsewhere.OutsideofChina,eightofthetop20windmarketssawtheirweightedaveragetotalinstalledcostsriseinrealtermsandafurtherfiveinnominalterms.However,withtheincreaseinChina’sshareofdeployment,theglobalweightedaveragecapacityfactorfornewprojectsdeclinedfrom39%in2021to37%in2022.Year-on-yearpercentagereduction-SolarphotovoltaicConcentratingsolarpowerOnshorewindOshorewind-3%+2%-5%-2%-13%-22%+18%BioenergyHydropowerGeothermalFigure1.1GlobalLCOEfromnewlycommissionedutility-scalerenewablepowertechnologies,2021-202212Smallermarketshavealwaysexperiencedsignificantyear-on-yearvolatility,giventhenatureofrenewablepowergenerationprojectsmeansthattheircostcanbeheavilyinfluencedbythesitelocation(e.g,accessandcivilworkscosts,gridconnection,etc.)andthesizeandexperienceofthedeveloper.33LATESTCOSTTRENDSForutility‑scalesolarPV,in2022,theglobalweightedaverageLCOEofnewlycommissionedprojectsdecreasedby3%year‑on‑yeartoUSD0.049/kWh.Thiswasdrivenbyadeclineintheglobalweightedaveragetotalinstalledcostforthistechnologyof4%,fromUSD917/kilowatt(kW)in2021toUSD876/kWfortheprojectscommissionedin2022.Thiswaslessthanthe13%declineexperiencedin2021,asrisingPVmoduleandcommoditypricesattheendof2021andinto2022havehadanimpactontotalcostsforasignificantnumberofprojects.In2022,elevenofthetoptwentymarketsforsolarPVsawtheirtotalinstalledcostincreaseyear-on-yearinrealterms(12innominalterms).Someoftheseincreases,notablyinEurope,weresubstantial(e.g.34%inFranceandGermanyandanestimated51%inGreece).Thereweresomenotableexceptions,however,perhapsduetolongerprojectdevelopmenttimelinesin,forexample,Türkiyesawa20%fall.Overall,theexperiencein2022wasmixed,withdifferentmarketsmovingindifferentdirections.Similartothesituationforonshorewind,Chinawasthelargestmarketfornewcapacityaddedinutility‑scalesolarPV,withitssharegrowingfrom38%in2021toanestimated45%oftheglobaltotalin2022,whichhelpedpushdowntheglobalweightedaveragetotalinstalledcost,despitea6%increaseintotalinstalledcostsinChinain2022year-on-year.Theoffshorewindmarketadded8.9GWin2022,whichwouldhavebeenanewrecordifnotfortheunprecedentedexpansionin2021of21GWglobally,drivenbyasurgeinChina.ThefallintheshareofChinaandthecommissioningofprojectsinnewmarketssawtheglobalweightedaveragecostofelectricityofnewprojectsincreaseby2%year‑on‑year,fromUSD0.079/kWhtoUSD0.081/kWh,despiteafallintheweightedaverageLCOEinChinaof7%in2022ThiswasdrivenbytheincreaseinglobalweightedaveragetotalinstalledcostsfromUSD3052/kWin2021toUSD3461/kWin2022.Duringthesameperiod,theglobalweightedaveragecapacityfactorincreasedfrom39%to42%,astheshareofChinaintotalnewdeploymentsdeclined,giventhatChineseprojectstendtobesitedinpoorerwindresourcelocationscomparedtothoseinEurope.LookingatthesituationinEurope,wherejust2.5GWofnewcapacitycameonline,theweightedaverageLCOEofnewlycommissionedprojectsincreasedfromUSD0.059/kWhin2021toUSD0.074/kWh,a32%increase.Thiswasdrivenbya32%increaseintotalinstalledcostsyear-on-yeartoUSD3907/kWin2022.Costswerehigherin2022,inpartbecauseofinflationpressures,butalsoduetoFrance’sfirstlarge-scaleprojectcomingonline,highercostprojectsintheUKandGermanyandonefloatingwindproject,the60MWHywindTampenproject.Theyear-on-yearvolatilityhasn’tchangedthebenefitsofeconomiesofscaleinlargeprojects,aswellassupplychainandO&Moptimisationoverthelasteightyears.However,withlongleadtimes,projectsaremoreexposedtocommoditypricefluctuations.13CSPcapacityexpandedby125MWin2022,continuingatrendofmodestnewcapacityadditions.OnlyoneCSPplantwascommissionedin2021andtwotheyearbefore.Withlimiteddeployment,year-to-yearcostchangesremainvolatile.Notingthiscaveat,theaveragecostofelectricityfromthe125MWaddedin2022wasaroundUSD0.118/kWh,or2%lowerthanin2021.13SeeChapter4foramoredetaileddiscussionthatpresentshowthecostandperformancemetricsforoffshorewindhaveevolvedinindividualmarketsinEurope,Chinaandelsewhere.34RENEWABLEPOWERGENERATIONCOSTSIN2022TheglobalweightedaverageLCOEofnewlycommissionedbioenergyforpowerprojectsfellby13%between2021and2022,fromUSD0.071/kWhtoUSD0.061/kWh.ThiswasdrivenbytheincreaseintheshareofnewprojectscommissionedinChinaandBrazilin2022.Withtenprojectscommissionedin2022,theglobalweightedaverageLCOEofgeothermalpowerprojectsfellby22%in2022toUSD0.056/kWh.Incontrast,theglobalweightedaverageLCOEofnewlycommissionedhydropowerprojectsincreasedby18%,fromUSD0.052/kWhtoUSD0.061/kWh.Anumberofprojectsthatexperiencedsignificantdelaysandlargecostoverrunswerecommissionedpartially,orinfull,in2022.Asaresult,theglobalweightedaveragetotalinstalledcostofnewhydropowerprojectsincreasedby26%,fromUSD2229/kWin2021toUSD2887/kWin2022.COSTTRENDS,2010‑2022Despitetheincreasecostsofequipmentandkeycommoditiessuchassteelandpolysiliconin2022,theperiod2010to2022representsaseismicshiftinthebalanceofcompetitivenessbetweenrenewablesandincumbentfossilfuelandnuclearoptions.Indeed,thechallengetodayinmostpartsoftheworldisidentifyinghowtointegratethemaximumamountofsolarandwindpowerpossibleintocurrentelectricitysystems.Meanwhile,effortsarebeingmadetoevolveregulatoryregimes,marketstructuresandrules,aswellasthephysicalinfrastructureofthegridtoensurethatgridconstraintsdonotslowtherateofdeployment.Thishasbecomenotonlyanenvironmentalimperative,butalsoaneconomicone.Althoughfossilfuelpriceshaveeasedsince2022,fossilfuelpricesarestillhighandthecrisiscontinues.Inthisrespect,policymakershaveatriumvirateofimmediatesolutionsinsolarpower,windpowerandenergyefficiency.Thesethreeoptions,withtheirrelativityshortprojectleadtimes,especiallyforsolarandwindpower,arevitalsolutionsincountries’effortstoreducetheirexposuretofossilfuelsandlimittheeconomicandsocialdamagethesefuelsarecausing.Thisisnottomentionrenewables’additionalenvironmentalbenefitsintermsofreducedlocalpollutantsandcarbondioxide(CO2)emissionsandtheirpreviouslyoverlooked,butnowreadilyapparent,energysecuritybenefits.Therateatwhichthecostofelectricityfromsolarandwindpowerhasfallenisquiteremarkable.In2010,theglobalweightedaverageLCOEofonshorewindwasUSD0.107/kWh,85%higherthanthelowestfossilfuelcostrangeofUSD0.058/kWh.By2022,theglobalweightedaverageLCOEofnewprojectswasUSD0.033/kWh,52%lowerthanthecheapestfossilfuel-firedoptionin2022.Thefallincostshasbeenmoresignificantforoffshorewind.TheglobalweightedaverageLCOEofoffshorewindfellfrombeing258%moreexpensivethanthecheapestfossilfueloptionin2010tobeingjust17%moreexpensivein2022,asthecostfellfromUSD0.197/kWhtoUSD0.081/kWh.CSPsawitsglobalweightedaverageLCOEfallfrom557%higherthanthecheapestfossilfueloptionin2010to71%higherin2022.However,eventhisimprovementissurpassedbythatofsolarPV,whoseglobalweightedaverageLCOEin2010wasUSD0.445/kWh,or670%moreexpensivethanthecheapestfossilfuel-firedoption.ThespectaculardeclineincoststoUSD0.05/kWhin2022wasthen28%lowerthancheapestfossilfuel-firedoption.35LATESTCOSTTRENDSThisanalysisexcludesanyfinancialsupportforrenewabletechnologies,sotheeconomiccasefortheownerorprojectdeveloperisoftenmorecompelling.Theexperienceofthelasttwoyearshaschangedstakeholders’understandingofpriceexpectationsinfossilfuelmarketsanddemonstratedthevulnerabilityofcountriesdependentonimportsoffossilfuelstosupplyanddemandimbalancesthatcansendpricessoaring.However,evenin2021,priortothefossilfuelpricecrisisin2022,therealitywasoneofrenewablesnotjustcompetingwithfossilfuels,butsignificantlyundercuttingthemwhennewelectricitygenerationcapacityisrequiredinmanypartsoftheworld.Indeed,inanincreasingnumberofmarkets,newrenewablecapacitycancostlessthaneventhemarginal(fuelandO&Mcosts)ofexistingfossilfuelplants.Since2010,solarPVhasexperiencedthemostrapidcostreductions,withtheglobalweightedaverageLCOEofnewlycommissionedutility‑scalesolarPVprojectsdecliningby89%between2010and2022fromUSD0.445/kWhtoUSD0.049/kWh(Figure1.2).ThiscostreductionoccurredasglobalcumulativeinstalledcapacityofallsolarPV(utilityscaleandrooftop)increasedfrom40GWin2010tosurpassoneTerrawatt(TW),reaching1047GWbytheendof2022.Thisveryrapidfallincosts,fromwelloutsidethefossilfuelcostrangein2010,sawtheglobalweightedaverageLCOEfromutility-scalesolarPVfallbelowthecheapestfossilfuelcostin2022byUSD0.019/kWh.ThisreductioninLCOEhasbeenprimarilydrivenbydeclinesinmodulepriceswhichhave–despitetheincreasein2022–fallenbyaround90%betweenDecember2009andDecember2022.Importantreductionshavealsooccurredinbalanceofplantcosts,O&Mandthecostofcapital.Themodulepricereductionsexperiencedbetween2010and2022weredrivenbymoduleefficiencyimprovements,increasedmanufacturingeconomiesofscaleandverticalintegrationinthesupplychain,manufacturingoptimisation,andreductionsinmaterialsintensity.Thetotalinstalledcostsofutility-scalesolarPVfellby82%between2010and2022,drivenbymoduleandbalanceofsystemcostsandstreamlinedandincreasinglyautomatedinstallation.Allofthiswashelpedbymoduleefficiencyimprovementsandahostofotherfactors,asdocumentedinChapter3.Theglobalweightedaveragetotalinstalledcostofutility-scalesolarPVdeclinedfromUSD4873/kWin2010tojustUSD876/kWin2022.Utility-scalesolarPVcapacityfactorshavealsorisenovertime.Initially,thiswasdrivenpredominantlybygrowthinnewmarketsthatsawashiftintheshareofdeploymenttoregionswithbettersolarresources.Technologyimprovementsthathavereducedsystemlosseshavealsoplayedasmallbutimportantroleinthis.Inrecentyears,however,ithasbeentheincreaseduseoftrackersandbifacialmodules–whichincreaseyieldsforagivenresource–thathasplayedamoresignificantrole.1414Unfortunately,project-leveldataontheuseoftrackersandmoduletypesarenotreadilyavailable,andwhatdataareavailableareoftennotcomprehensive.Itisthereforedifficulttoestimatetheoverallimpacttrackershaveplayedinincreasingcapacityfactorsglobally.36RENEWABLEPOWERGENERATIONCOSTSIN2022Between2010and2021,theglobalweightedaveragecostofelectricityforonshorewindprojectsfellby69%,fromUSD0.107/kWhtoUSD0.033/kWh.Thisdeclineoccurredascumulativeinstalledcapacitygrewfrom178GWto837GW.Costreductionsforonshorewindweredrivenbytwokeyfactors:windturbinecostreductionsandcapacityfactorincreasesfromturbinetechnologyimprovements.WindturbinepricesoutsideChinafellby49%to55%between2010and2022,dependingonthewindturbinepriceindex.However,inChina,thisreductionwasalmosttwo-thirds(64%).Inadditiontothis,declinesinbalanceofplantcostsastheindustryscaledup,aswellasincreasingaverageprojectsizes(notablyoutsideEurope),highlycompetitivesupplychainsandthefallingcostofcapital(includingthetechnologypremiumforonshorewind)alsocontributedtothefallingLCOE.ReductionsinO&McostshavealsooccurredasaresultofincreasedcompetitionamongO&Mserviceproviders,greaterwindfarmoperationalexperience,andimprovedpreventativemaintenanceprogrammes.Improvementsintechnologyhavealsoresultedinmorereliableturbines,withincreasedavailability.Atthesametime,highercapacityfactorsmeanthatthefixedO&McostsperunitofoutputhavefallenevenfasterthanthefixedO&McostsmeasuredasUSD/kW/year.USDkWhFossilfuelcostrangeBioenergyGeothermalHydropowerSolarphotovoltaicConcentratingsolarpowerOffshorewindOnshorewindthpercentilethpercentileCapacity(MW)≤≥Figure1.2GlobalweightedaverageLCOEfromnewlycommissioned,utility-scalerenewablepowergenerationtechnologies,2010-2022Note:Thesedataarefortheyearofcommissioning.ThethicklinesaretheglobalweightedaverageLCOEvaluederivedfromtheindividualplantscommissionedineachyear.TheLCOEiscalculatedwithproject-specificinstalledcostsandcapacityfactors,whiletheotherassumptions,includingWACC,aredetailedinAnnexI.Thegreybandrepresentsthefossilfuel-firedpowergenerationcostrange(USD0.069toUSD0.244/kWh),whilethebandsforeachtechnologyandyearrepresentthe5thand95thpercentilebandsforrenewableprojects.NuttawutUttamaharad©Shutterstock.com37LATESTCOSTTRENDSThecontinuedimprovementsinwindturbinetechnology,windfarmsitingandreliabilityhaveledtoanincreaseinaveragecapacityfactors,withtheglobalweightedaverageofnewlycommissionedprojectsincreasingfrom27%in2010to39%forthosecommissionedin2021.Theglobalweightedaveragefellbackto37%in2022astheshareoftheUnitedStates,whichcontinuestodeployprojectswith40%andhighercapacityfactors,declinedasdeploymentalmosthalvedfrom14.3GWin2021to7.8GWin2022.Technologyimprovements,suchashigherhubheightsandlargerturbinesandsweptbladeareas,meantoday’swindturbinescanachievehighercapacityfactorsfromthesamewindsitethantheirsmallerpredecessors.Thetechnologyimprovementsince2010isgreaterthanthatimpliedbytheincreaseintheglobalweightedaveragecapacityfactortoo,because,onaverage,majormarketsin2020–and,likely,since–weredeployinginareasofpoorerwindresourcesthanin2010(seeChapter2formoredetails).Previously,IRENAhascalculatedfossilfuelpowergenerationcostsforeachG20countryusingarangeofdatasources,but,withtheexceptionoftheUnitedStates,basedonsecondarydatasources.TheresultingrangeforcheapestandmostexpensivefossilfuelLCOEintheG20wasthenpresentedinIRENA’sRenewablepowergenerationcostreports.Forthisreport,IRENAhascollectedprimarydataonthecostofindividualcoal,gasandoil-firedelectricitygenerationprojectscommissionedbetween2000and2023.Projectcostdatawerefoundfor496gas/oilplantsaccountingfor200GWofcapacityfrom42countries.Datafor695coal-firedplantsin23countries,totalling685GW,werealsocompiled(seetheonlineannexformoredetail).Constructingatimeseriesforacountrydependsoncontinuousdeployment,andinsomecasesIRENAhadtointerpolatetotalinstalledcostdatabetweenyears,eitherbecausenoplantsofaparticulartechnologyweredeployedorbecausenocostdatacouldbefound.ThisdatasetallowsforamoreaccuratedevelopmentofanLCOEestimateforeachtechnologytype,basedoncountry-levelprojectdata.TocalculatetheLCOE,IRENAhasalsocompiledcountry-specificcoalandgasfuelcostsfromvarioussourcesfortheperiod2010to2022tomatchtheperiodofrenewablepowercostpresentationinthisreport.Inputassumptionsforoperatingplantefficiency,O&McostsandCO2pricing,whereapplicable,havebeencompiledfromvariousprimaryandsecondarysources.Wherenocountry-specificdatawereavailablefortheseinputassumptions,IRENAusedgenericvaluesfromtheliterature(seetheonlineannex).Aweightedaveragecostofcapitalof7.5%wasusedfortheOECDandChinaand10%usedelsewhere.Capacityfactorsareassumedtobeintherange40-75%fornewcombinedcyclegasturbine(CCGT)andcoal-firedprojects(withsomeexceptions)and10%foroilandopen-cyclegasturbine(OCGT)projects.FigureB1.2apresentstheresultsforcountrieswhereIRENAwasabletocollectrobusttimeseriesdata.Fossilfuelpricesarethosethatwererealisedintheyearofcommissioning.Thisisnotnecessarilywhatprojectdevelopershaveassessedtobetheaveragecostoveraplant’s30-to40-yearlife,butitprovidesanindicationofthetrendsincosts.Theonlineannexaccompanyingthisreportincludesacomparisonwiththeassumptionthatonly50%ofthe2022priceincreaseover2021isfactoredinandacomparisonwith2021.Realistically,however,itisstillprobablynotcleartowhatextentlong-termfossilfuelpriceexpectationshavechanged,andhowthisdiffersbetweenimportersandexportersoffossilfuels.Thehighersensitivityofanaturalgas-firedplant’sLCOEtofossilfuelpricesisclearintheperiod2010to2016andthenagainin2021and2022.Althoughcoalpricesalsoincreaseddramaticallyin2022,theimpactwasgenerallylesssignificantthanforgas-firedplants.Box1.2Fossilfuelpowergenerationcosts38RENEWABLEPOWERGENERATIONCOSTSIN2022PartofthelowersensitivityoftheLCOEfromcoal-firedpowerplantstocoalpricesstemsfromthehighercapitalcostsforcoal-firedpowerplantsinmanymarketscomparedtogasplants.FigureB1.2bpresentstheLCOEanditsbreakdownintothebasiccomponentsofLCOEin2010foraselectionof12countries.Ineverycountry,thecontributionoftotalinstalledcoststotheLCOEislargerforcoal-firedplantsthanforgas-firedCCGTplants.Conversely,thefuelcostshareofLCOEishigherforallcountries,giventheoftenlowertotalinstalledcosts,butespeciallyduetothehigherfuelcostevenafterallowingforthehigherefficiencyofCCGTscomparedtocoalplants.BrazilCanadaChinaAustraliaArgentinaFranceGermanyIndiaIndonesiaPhilippinesRepublicofKoreaMalaysiaItalyJapanMexicoSouthAfricaUnitedKingdomVietNamTürkiyeUnitedStatesUSDkWhUSDkWhCCGTCoalOCGTOil-ﬁredFigureB1.2aFossilfuel-firedLCOEbyfuel/technologyandyearfor20countries,2010-2022Source:IRENAFossilFuelPowerPlantDatabase(seetheonlineannex).THINKA©Shutterstock.com39LATESTCOSTTRENDSPartofthelowersensitivityoftheLCOEfromcoal-firedpowerplantstocoalpricesstemsfromthehighercapitalcostsforcoal-firedpowerplantsinmanymarketscomparedtogasplants.FigureB1.2bpresentstheLCOEanditsbreakdownintothebasiccomponentsofLCOEin2010foraselectionof12countries.Ineverycountry,thecontributionoftotalinstalledcoststotheLCOEislargerforcoal-firedplantsthanforgas-firedws.Conversely,thefuelcostshareofLCOEishigherforallcountries,giventheoftenlowertotalinstalledcosts,butespeciallyduetothehigherfuelcostevenafterallowingforthehigherefficiencyofCCGTscomparedtocoalplants.O&MTotalinstalledcostFuelCOGermanyAustraliaUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhCCGTCoalCCGTCoalCCGTCoalBrazilMalaysiaIndiaUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhCCGTCoalCCGTCoalCCGTCoalIndonesiaSouthAfricaPhilippinesUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhCCGTCoalCCGTCoalCCGTCoalRepublicofKoreaVietNamTürkiyeUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhUSDKWhCCGTCoalCCGTCoalCCGTCoalUnitedStatesFigureB1.2bFossilfuel-firedLCOEbyfuel/technologyandcostcomponentfor12countries,201040RENEWABLEPOWERGENERATIONCOSTSIN2022Aftertheunprecedented20GWofnewcapacityadditionsforoffshorewinddeploymentin2021,with17.4GWinChina,newcapacityadditionsin2022totalled9GW.However,the2022capacityadditionsarelarge,almost50%morethanwasaddedin2020,whichheldtherecordbefore2021.Between2010and2022,theglobalweightedaverageLCOEofnewlycommissionedoffshorewindprojectsdeclinedfromUSD0.197/kWhtoUSD0.081/kWh,areductionof59%.In2010,ChinaandEuropesawnewlycommissionedprojectswithaweightedaverageLCOEofUSD0.189/kWhandUSD0.198/kWh,respectively.TheweightedaverageLCOEsofthesetwogroupsthereafterdiverged,notablyin2021,whennewlycommissionedEuropeanprojectshadaweightedaveragecostofUSD0.056/kWh,lowerthantheUSD0.083/kWhinChinathatyear.In2022,theweightedaverageLCOEinEuropeincreasedto0.074/kWhasarangeofmoreexpensiveprojectswerecompleted,includinginnewmarkets.Europe’sLCOE,was,howeverstillaround4%lowerthanChineseprojectscompletedin2022,whichsawaweightedaverageofUSD0.077/kWh.Between2010and2022,theglobalweightedaveragetotalinstalledcostsofnewlycommissionedoffshorewindfarmsfell41%,fromUSD5217/kWin2010toUSD3052/kWin2021,beforeincreasingtoUSD3461/kWin2022.Theincreasein2022wasdrivenbythedeclineintheshareofChineseprojectsandtheincreaseinweightedaveragetotalinstalledcostsinEuropein2022.Withrelatively“lumpy”investmentsandsmallnumbersofprojectsbeingcommissionedineachyearinEurope,costtrendstendtobevolatile.Thehigherprojectcostsin2022areacaseinpoint:projectswithhighercapitalinvestmentswerecommissionedinFrance,GermanyandtheUnitedKingdom.TheresultforFranceisunsurprising,giventheSaintNazaireprojectwasthefirstofitskindinFrenchwaters.Thisgrowthinnewmarkets–bothwithinEurope,whereoffshorewindmarketsfirstdeveloped,andglobally–hasaddedmore“noise”totheglobalweightedaveragedata.Yet,inthelastthreeyears,withChinaaccountingfor50%ofnewcapacityadditionsin2020,82%in2021and48%in2022,theglobal-weightedaveragecostandperformancemetricshaveincreasinglyrepresentedChinesecircumstances.Thisisparticularlytruefortheevolutionoftheglobalweightedaveragecapacityfactorofnewlycommissionedoffshorewindfarmsin2022.ThefallinChina’sshareinnewdeploymentsawtheglobalweightedaveragecapacityfactorincreasefrom38.8%in2021to41.6%in2021.Ingeneral,thepoorercoastalwindresourcesandsmallerturbinesusedbyChinainitsnear-shoreandinter-tidaldevelopmentsalongthecountry’scoastalzonesmeancapacityfactorsarelowerthaninEurope.CSPdeploymentremainsdisappointing,withlessthan0.1GWaddedin2022andglobalcumulativecapacitystandingat6.5GWattheendof2022.Fortheperiod2010to2022,theglobalweightedaveragecostofnewlycommissionedprojectsfellfromUSD0.38/kWhtoUSD0.118/kWh–adeclineof69%.Despitethelowrateofdeployment,costreductionshadbeenclearlyvisiblebetween2010and2020,despitethevolatility.However,since2020,thecommissioningofprojectsthatwereeitherdelayedorincludednoveldesignshasseentheglobalweightedaveragecostofelectricitystagnate.41LATESTCOSTTRENDSNevertheless,theabovedeclineinthecostofelectricityfromCSP,whichhasplaceditinthemid-tolower-costrangeofnewcapacityfromfossilfuelsin2022dependingonthecountry,remainsaremarkableachievement.However,thecumulativeglobalcapacityofCSPis161timessmallerthanthecapacityofsolarPVinstalledattheendof2022.ThedeclineintheglobalweightedaverageLCOEofnewlycommissionedCSPprojectshasbeendrivenbyreductionsintotalinstalledcosts,technologyimprovements,morecompetitivesupplychainsandreducedO&Mcosts.Improvementsintechnologythathaveseentheeconomiclevelofstorageincreasesignificantlyhavealsoplayedaroleinincreasingcapacityfactors.Withonlyahandfulofprojectscommissionedeachyearinrecentyears,trendsintheglobalweightedaveragetotalinstalledcostofCSPprojectshavebeenvolatile.In2021,theChileanCSPplant,CerroDominador,waslongoverdueandhadtotalinstalledcostsofUSD9728/kW,whichplaceditmoreinlinewithprojectsdevelopedbetween2010and2015.Theavailabilityofcostdatafor2022isrelativelypoor,butoverall,theglobalweightedaveragetotalinstalledcostin2022wasestimatedtobeontheorderofUSD5836/kW,withahigherdegreeofuncertaintythannormal.Theglobalweightedaveragecapacityfactorofnewlycommissionedprojectsdeclinedfrom80%in2021,drivenbytheCerroDominadorproject’s17.5hoursofstorage,to51%in2022,inlinewithapoorerresourceandaround9hoursofstorageonaverage.Forbioenergy,geothermalandhydropower,installedcostsandcapacityfactorsarehighlyproject-andsite-specific.Asaresult,andduetodifferentcoststructuresindifferentmarkets,therecanbesignificantyear-to-yearvariabilityinglobalweightedaveragevalues,particularlywhendeploymentisrelativelythinandtheshareofdifferentcountries/regionsinnewdeploymentvariessignificantlyyeartoyear.Between2010and2022inclusive,89GWofnewbioenergyforpowercapacitywasadded,includingthe7.6GWaddedin2022.TheglobalweightedaverageLCOEofbioenergyforpowerprojectsexperiencedacertaindegreeofvolatilityduringthisperiod,butwithoutanotabletrendupwardsordownwardsformostoftheperiod.In2022,however,bioenergy’sglobalweightedaverageLCOEofUSD0.061/kWhwas13%lowerthanthe2021valueandone-quarterlowerthanthevaluein2010ofUSD0.082/kWh.Theglobalweightedaveragetotalinstalledcostsin2022wereUSD2162/kW,or13%lowerthanin2021givenalmostallnewcapacitywasaddedinnon-OECDcountrieswithlowercoststructures.Theglobalweightedaveragecapacityfactorofnewlyaddedcapacityin2022was72%,uponthefigureof68%in2021.TheglobalweightedaverageLCOEofgeothermalfell22%year-on-yeartoUSD0.056/kWhin2022.Thisis6%higherthanin2010,butwellwithintherangeseenbetween2013and2021ofUSD0.053/kWhtoUSD0.091/kWh.Annualnewcapacityadditionsremainmodest,allowingoneprojectwithanatypicallylowcapacityfactor–42%–todragdowntheglobalweightedaveragecapacityfactorofprojectscommissionedin2021to77%.Newprojectsaddedin2022totalled181MW,withamorecompetitivecoststructurethan2021.For2010to2022inclusive,hydropoweradded347GWofnewcapacity,with20GWcommissionedin2022.Overthesameperiod,theglobalweightedaverageLCOEroseby47%,fromUSD0.042/kWhtoUSD0.061/kWh.Thiswasstilllowerthanthecheapestnewfossilfuel-firedelectricityoptionin2022,despitethefactthatcostsincreasedby18%in2022,year-on-year.Thiswasdrivenbythecommissioningofanumberofprojectsthatexperiencedverysignificantcostsoverruns,notablyinCanada.42RENEWABLEPOWERGENERATIONCOSTSIN2022Withtheglobalweightedaveragecapacityfactorlargelyunchangedat44%to46%between2010and2022,thisLCOEincreasehasbeenpredominantlydrivenbythe109%increaseintotalinstalledcostsperkWoverthatperiod(26%year-on-yearin2022).Totalinstalledcostsarelikelytohavefallenin2022,asfewerlargeprojectsthathaveexperiencedsignificantcostoverrunsareexpectedtoachievecommercialoperationin2023.However,thiscannotbeguaranteed,givencommoditypriceinflationoverthelasttwoyears.Figure1.3presentstheresultsfortheglobalweightedaverageoftotalinstalledcosts,capacityfactorsandLCOEsforsolarPV,onshorewindpowerandoffshorewindpower.Globalweightedaveragetotalinstalledcostsforeachtechnologyhavefallenovertheperiod2010to2022,by83%forutility-scalesolarPV,42%foronshorewindand34%foroffshorewind.Globally,utility-scalesolarPVtotalinstalledcostsfellbelowthoseofonshorewindin2016.Butasthedataforcapacityfactorsshow,thetechnologyimprovementsmadebywindturbinemanufacturershaveseenthecapacityfactorsfornewonshorewindpowerprojectsriseovertime.Asaresult,atagloballevel,theLCOEofutility-scalesolarPV,althoughfallingby89%overtheperiod2010to2022,remainsaroundUSD0.027/kWhhigherthanthatofonshorewind,despitefallingbelowthecostofelectricityfromoffshorewindin2014.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFossilfuelcostrangeOshorewindOnshorewindSolarphotovoltaicFigure1.3Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEfromnewlycommissionedsolarPV,onshorewindpowerandoffshorewindpower,2010-202243LATESTCOSTTRENDSTHEFOSSILFUELPRICECRISISHASACCELERATEDTHECOMPETITIVENESSOFRENEWABLEPOWERThefossilfuelpricecrisisin2022wasdrivenbyagrowingimbalanceinsupplyanddemandastheglobaleconomyrecoveredfromtheCOVID-19pandemicandeconomicactivityaccelerated.TheslowreductioninRussiangasflows,whichaccelerateddramaticallywiththecrisisinUkraine,wasashocktheglobalenergysystemwasnotpreparedfor,andfossilfuelpricesskyrocketed.In2022,theEuropeanfossilgasmarkerprice–theDutchTitleTransferFacility(TTF)pricingnode–increasedby175%over2021,whichitselfhadalreadyincreasedby320%over2020.In2022,theDutchTTFpricewasthereforearound11.7timeshigherthanin2020,or8.2timeshigherthanthepre-COVIDpricein2019.Japaneseimportsofnaturalgasarecharacterisedbycontractsthataredesignedtoprovidegreaterpricecertainty.Historically,thiscertaintyhascomeatacost,withJapanesepricestypicallyhigherthaninothermarkets.However,in2022theyensuredtheJapanesemarketwasinsulatedfromthefullimpactofspotprices,andtheimportpriceincreasedby“only”25%in2021and59%in2022.AttheotherextremefromEuropeanpricing,growingfossilgasproductionintheUnitedStatesfromshalegasplaysmeanstheUnitedStatesmarketiswellsuppliedwithlower-costfossilgas.However,thegrowthinLNGexportsfromtheUnitedStatesisincreasingthelinkagestointernationalsupplyanddemandforfossilgas,ascanbeseenbythe11%increaseinpricesin2021and23%increasein2022,albeitfromverylowlevels.Coal,adirtierfuelinallaspectsthannaturalgas,tradesatlowercostsonanenergycontentbasis.Theeconomicgrowthin2022andthefuelswitchingfromveryexpensivegastocoalsawpricesriserapidlyinmostmarketswithsignificantimportsorexports.InEurope,theAmsterdam-Rotterdam-Antwerp(ARA)coalpricemarkerincreasedfromitsdecadallowin2020by129%in2021andanother126%in2022.Asaresult,thermalcoalpricesforpowergenerationin2022innorthwestEuropewerearound2.6timeshigherthanin2021,5.2timeshigherthanin2020,or4.2timeshigherthanthe2019pre-COVIDprice.TheUnitedStates,withdecliningcoal-firedpowergenerationandlargedomesticcoalreservesandproduction,15isagainanexception,withcoalpricesforcoaldeliveredtopowerstationsrisingbyjust12%in2021.Thisreflectsthelargeinlandproductionofcoalinthewesternstatesandthefactmostofthepowerplantshavecontractsforsupplythatprovidepriceandvolumecertaintytobuyerandseller(EIA,2023).Indeed,intheUnitedStates,inrealterms,pricesin2010werehigherthanin2022.InIndia,thermalcoalimportcostsrosesharplyin2021,by107%,butpowergeneratorseitherscaledbackgenerationorsourcedcheapercoalsources,moderatingthepriceincreasein2022to20%.15ThePowderRiverCoalbasin(locatedinnortheastWyomingandsoutheastMontana)andotherwesterncoalminesprovided62%ofthetotalcoalvolumesuppliedtopowerplantsin2022,butisnotalargeexporterduetoitsinlandlocation.Europeanfossilgaspricesin2022were175%higherthanin2021and320%higherthanin2020.44RENEWABLEPOWERGENERATIONCOSTSIN2022Asaresultoftheincreaseinfossilfuel-firedpowergenerationcosts,drivenprimarilybyfossilfuelpriceincreasesin2022(FigureB1.2aandFigure1.4),thecompetitivenessofrenewablepowergenerationimprovedconsiderablyin2022,despitetheincreaseinsolarPVandonshorewindcostsinmanymarkets.In2022,around86%(187GW)ofnewlycommissioned,utility-scale16renewablepowergenerationprojectshadcostsofelectricitylowerthantheweightedaveragefossilfuel-firedcostbycountry/region(Figure1.5).Thisis8%higherthanthe174GWestimatedtohavehadacostlowerthanthatofthefossilfuel-firedweightedaverageforthatyearandcountry/regionin2021.Thisanalysisdiffersfromthatpresentedlastyear.Thisyear’sanalysisincludestheweightedaverage(bynewfossilfuelcapacityadditions)fossilfuel-firedLCOEforthe20countrieshighlightedinBox1.1,withregionalaveragesfortheremainingcountries.Thefossilfuel-firedLCOEthereforevariesbyyear,dependingonchangesincapitalcostsandfuelcostsforthefossilfuelplant.Thisgivesamoreaccurateassessmentofthecompetitivenessofrenewablesduringthisperiod.Giventheuncertaintyabouthowfar2022fossilfuelpriceshavechangedexpectationsforthenext15to30years,thecomparisonforfossilfuelpricesismadebysetting2022valuestoavalueequaltowhatoccurredin2021,giventhatthe2022valueisassumedtobeanoutlierandnotreflectiveofthebenchmarkfossilfuelLCOEfornewinvestmentdecisions.Higherorlowerfossilfuelpriceout-turnsforthenext30yearswouldshiftthenumbersinthissectionupordown.16Thisincludesallprojectswithacapacityof1MWormoreandincludesIRENA’sassessmentof112GWofnewutility-scalesolarPVdeploymentin2022.USDMWhNaturalgaspricesDutchTTFpriceARApricesJapaneseimportpriceIndianimportpriceUS(avgcosttopower)US(avgcosttopower)CoalpricesFigure1.4Fossilgasandcoalpricemarkerorimportcostbycountry,2004to2022Source:Seetheonlineannex.Notes:TTF=TitleTransferFacility;ARA=Amsterdam-Rotterdam-Antwerp.45LATESTCOSTTRENDSThemostnotablechangeisintheemergenceofmodestamountsofcompetitivelypricedonshorewindintheperiod2011to2014inclusive,andlargervaluesfor2015and2016.However,theshiftsarenotallinfavourofrenewables.Inlastyear’sassessment,virtuallyalloftheonshorewinddeploymentin2021wascompetitive,whilethemorerobustanalysisinFigure1.5estimatesthat8.5GWwasinmarketsthathadhighercoststhantheaveragefossilfuel-firedLCOE.BiomassConcentratingsolarpowerSolarphotovoltaicHydropowerOshorewindOnshorewindGeothermalGWCompetitiveNeedssupportGWGWFigure1.5Annualnewutility-scalerenewablepowergenerationcapacityaddedatalowercostthanthecheapestfossilfuel-firedoption,2010-2022Note:Thisanalysisusescountry-levelweightedaveragefossilfuel-firedLCOEsforeachyearfor20countries(seeFigureB1.1)andataregionallevelfortheremainder.Thesevaluesarecomparedtotheproject-levelLCOEofrenewableprojectsdeployedineachyear.2022fossilfuelLCOEshavebeencalculatedconservativelyusingthe2021fossilfuelpricedata.46RENEWABLEPOWERGENERATIONCOSTSIN2022In2017,anestimated71GWofnewutility-scalePVwasdeployed,ofwhichjust9%hadlowercoststhantheweightedaveragefossilfuelLCOEforitscountryorregion.In2022–justfiveyearslater–totalnewutility-scalePVcapacityaddedhadleapedto112GW,andtheshareofcapacityfromprojectsthathadlowerLCOEshadrisento86%.ThecontinuedimprovementinthecostsofsolarPVinmanymarkets,aswellasthehigherfossilfuel-firedLCOEs,meantthatin2022arecord96GWofnewutility-scalePVdeploymenthadlowercoststhantheweightedaveragefossilfuel-firedLCOE,upfrom74GW(78%ofutility-scalePV)in2021and46GW(62%ofutility-scalePV)in2020.TheincreaseddeploymentofsolarPVhasalsomeantthatin2021and2022,moreutility-scalePVcapacityadditionswerecompetitivethanonshorewindforthefirsttime.In2022,59GW(87%)oftheonshorewindprojectscommissionedhadelectricitycoststhatwerelowerthantheweightedaveragefossilfuel-firedLCOEbycountry/region.Thiswasanamountlowerthanthefigureof89GWrecordedin2020,duetothelowernewcapacityadditionsinChinain2022.Theyear2018wasseminalforonshorewind:itwasthefirstyearwhenoverhalfofnewcapacityadditionsregisteredbelowthecostoftheweightedaveragefossilfuel-firedLCOE.Utility-scalesolarPVhadtowaitayear,until2019,toreachthismilestone.Foroffshorewind,around1GWofnewcapacityadditionshadLCOEslowerthanthecountry/regionweightedaveragefossilfuelLCOEin2018and2019,risingto2GWin2020.In2021,thisleapttoaround12GWonthebackofmuchhigherdeploymentin2021,with17.4GWaddedinChinaaloneinthatyear.In2022,around6GWhadlowerLCOEsthantheweightedaveragefossilfuel-firedvalue,whichrepresentedaround70%ofthetotalnewcapacityadditionstrackedintheIRENARenewableCostDatabase.Forhydropower,in2020,20GW(92%)oftheprojectscommissionedhadcoststhatwerelessthantheweightedaveragefossilfuel-firedLCOE.Bioenergyforpowersaw6.7GW(97%)ofnewcapacityadditionswithalowerLCOEthantheweightedaveragefossilfuel-firedLCOE.Overall,between2010and2022,1120GWofrenewablepowergenerationwithalowerLCOEthanthatoftheweightedaveragefossilfuel-firedLCOEbycountry/regionwasdeployed.Therapidlyimprovedeconomicsofonshorewindinrecentyearsmeanthatforcumulativeadditionssince2010,onshorewindsurpassedhydropowerin2021asthelargestsourceovertheperiodoflower-costelectricity,reachingacumulativetotalof396GWin2022.WithsolarPVcapacityadditionsincreasingfasterthanonshorewind,andtheircompetitivenessalsoaccelerating,utility-scalePVaddedanestimated316GWofprojectswithanLCOElowerthantheweightedaveragefossilfuel-firedLCOE.Innon-OECDeconomieswhereelectricitydemandisgrowingandnewcapacityisneeded,therenewablepowergenerationprojectswithLCOEslowerthantheweightedaveragefossilfuel-firedLCOEfortheircountry/regionwillsignificantlyreduceelectricitysystemcostsoverthelifeoftheiroperation.47LATESTCOSTTRENDSIn2022,innon-OECDcountries,the143GWofprojectswithcostslowerthantheweightedaveragefossilfuel-firedLCOEwillreducecostsintheelectricitysectorbyatleastUSD22.9billionannually.Thisassumesfossilfuelpricesat2021levels,withanallowanceofUSD5/megawatthour(MWh)forsystemcosts(Table1.1)relativetothelong-termcostofaddingthesameamountoffossilfuel-firedgeneration.Themajorityofthesesavings–atotalofUSD9.8billion–willcomefromonshorewind.Hydropower,withitshighercapacityfactors,contributesaroundUSD4.2billiontothesesavings.Withtheincreaseinfossilfuel-firedgenerationcosts,utility-scalesolarPVaccountsforUSD6.4billion.Overtheireconomiclives,thecumulativeundiscountedsavingsofthenewprojectsdeployedin2022could,dependingonfossilfuelprices,reachUSD580billion.Inadditiontothesedirectcostsavings,therewouldbesubstantialeconomicbenefitsfromreducingCO2emissionsandlocalairpollutants.Thesewouldalsoneedtobefactoredinwhenconsideringthetotalbenefits.CumulativetotalTWh(newcapacityadded)USDbillionBiomassSolarphotovoltaicHydropowerOshorewindOnshorewindGeothermalFigure1.6Renewablegenerationandnetsavingsinnon-OECDcountriesfromnewcompetitiverenewablegenerationcapacityaddedbyyear,2010-2022Note:TWh=terawatthour.48RENEWABLEPOWERGENERATIONCOSTSIN2022Overall,between2010and2022inclusive,globally,around928GWofrenewablepowergenerationcapacityhasbeenaddedinnon-OECDcountriesthathadcostslowerthantheweightedaveragefossilfuel-firedLCOEintheyearofcommissioning.Ofthistotal,333GWwashydropower(36%),289GWonshorewind(31%)and239GW(26%)utility-scalesolarPV.In2023,this928GWcouldreduceelectricitysystemcostsbyUSD104billion,oruptoasmuchasUSD180billion–iffossilfuelpricesaveragewhattheywerein2021ratherthanthoseapplicableintheyeartheprojectwascommissioned–comparedtowhatwouldhavebeenthecaseifthegenerationweretocomefromfossilfuels.FortheestimateofUSD104billioninsavings,itishydropowerthatdominatesthesavings,contributingUSD52.5billion,or50%ofthetotal.WithUSD31.9billioninsavingsannually,onshorewindisthesecondlargestcontributor(30%),followedbysolarPV,withUSD12.2billionannually(12%ofthetotal).ThecompetitivenessofsolarPVandwindpoweracceleratedin2021and2022Thefossilfuelpricecrisisin2022,drivenbyrecoveringeconomicactivityaftertheCOVID-19pandemicandthereducedgasflowstoEuropefromRussia,haschangednotonlytoday’senergylandscape,butalsotheoutlookforthefuture.Forthelast13to15years,renewablepowergenerationcostsfromsolarandwindpowerhavebeenfalling.Initiallythiswasfromhighlevelsthatledsometoquestionwhethersolarandwindcouldchallengethestatusquointheelectricitysystem.However,fromaround2013costsforonshorewindfellsignificantlyintothefossilfuel-firedcostrange,andPVwasrapidlyapproachingthislevel.Thiscoincidedwithaperiodoflowerfossilfuelprices(Figure1.4).Theimpactwasoneofdampeningthecompetitivenessimprovementsofrenewablepowergenerationandpotentiallyconcealingtheinevitabilityofwhatwastocome.Thisdynamicofdecliningrealfossilfuelpricescontinuedthroughinto2020,butsolarandwindpowercostswereundoubtedlynowcompetitive.metamorworks©Shutterstock.com49LATESTCOSTTRENDSThefossilfuelpricecrisishasreversedthisdynamic.Therisingfossilfuelpricetrend–andfutureexpectationsofhighpricesrelativetothelastdecade17–isnowamplifyingtheimprovementinthecompetitivenessofsolarandwindpowergeneration.Thismeansthatinmanymarkets,both2021and2022resultedinanimportantincreaseinthecompetitivenessofsolarandonshorewindpower.However,thescaleoftheimprovementincompetitivenessdiffersforthesetwotechnologies.FortheanalysispresentedinFigures1.7,1.8,1.9and1.10,theweightedaverageLCOEoffossilfuelsinagivenyear–weightedbydeploymentusingtheaveragerealisedfuelcostinthatyearfromFigure1.4andwithcountry-specificcostandcapacityfactorassumptionsasdetailedinBox1.1andtheonlineannex–issubtractedfromtheweightedaverageLCOEofsolarPV,onshorewindandoffshorewind.Thisisametricinthetrendincompetitivenessofrenewablepower.Thisiarelativelysimplemetrictounderstand,butconveysimportantinformationabouthowthecompetitivenessofrenewablepowerisinfluencednotjustbytrendsinitsownLCOE,butbythefluctuationsinfossilfuelpricesaswell.However,cautionshouldbetakenininterpretingtheabsolutelevelsandcomparisonsbetweencountriesusingthiscompetitivenessmetricforthereasonsalreadydiscussedabouttheappropriatenessoftheLCOEmetricindifferentcircumstancesand,especially,giventheuncertaintyaroundwhatarerealistic30-yearpriceprojectionsforfossilfuels.Thetrendsinthecompetitivenessofutility-scalesolarPVinFigure1.7highlighttherapidimprovementsintheperiod2010to2013asPVmodulepricesfellprecipitouslyandnaturalgaspriceswerehigh.Asmodulepricereductionslowedfromtheirbreakneckpaceover2010to2013andnaturalgaspriceseased,theimprovementsincompetitivenessslowedinanumberofmarkets.Somewhatsurprisingly,BrazilwasthefirstcountrytoseetheweightedaverageLCOEofnewutility-scalesolarPVfallbelowtheweightedaveragecostoffossilfuelcapacityadded,in2014.ItwasfollowedbyAustraliain2016,whereitsexcellentsolarresourcesandhighcostsfornewfossilfuel-firedpowergenerationcombinedtomakePVcompetitive.Italysawasimilartrendin2017.In2018,solarPVtotalinstalledcostshadstartedtoconvergeacrossmarketstoreachcompetitivebenchmarks.Thatyear,Argentina,China,France,Germany,India,theRepublicofKoreaandthePhilippinesallreachedthecrossoverpoint.In2019,SouthAfricaandVietNamalsoachievedthismilestone.In2021,Canada,Indonesia,Japan,Mexico,theUnitedKingdomandtheUnitedStatesallachievedthecrossoveraswell.WiththeexceptionofJapanandtheUnitedKingdom,thesearecountriesthathavehistoricallyhadverylowfossilfuelprices.Finally,forthe20countriesexamined,MalaysiaandTürkiyesawtheweightedaverageoftheirnewutility-scalesolarPVcapacityadditionsin2022fallbelowtheestimateoftheweightedaveragefossilLCOEofnewlyaddedcapacity.17FuturespricesforEuropeanfossilgasremainelevatedandgovernmentshaveadjustedtheirexpectationsaboutfuturepricestotakeintoaccountanincreasingrelianceonmoreexpensiveLNG.50RENEWABLEPOWERGENERATIONCOSTSIN2022PVmoreexpensivethanfossilfuelsPVlessexpensivethanfossilfuelsUSDkWh--ArgentinaAustraliaBrazilCanada--ChinaFranceGermanyIndia--IndonesiaItalyJapanRepublicofKorea--MalaysiaMexicoPhilippinesSouthAfrica--TürkiyeUnitedKingdomUnitedStatesVietNamFigure1.7Competitivenesstrendsforutility-scalesolarPVbycountryandyear,2010-2022Source:IRENARenewableCostDatabaseandtheonlineannex.Note:ThecompetitivenessmetricistheweightedaverageLCOEofrenewablepowerminustheweightedaverageLCOEoffossilfuelsinthatyear.chinasong©Shutterstock.com51LATESTCOSTTRENDSTheinteractionbetweenthefallingweightedaverageutility-scalesolarPVLCOEandchangesintheweightedaverageannualnewcapacityadditionsoffossilfuelcapacitybycountryandyearmeantrendsinthecompetitivenessmetriccandiffersignificantlybycountry.Figure1.8showsanotherwayoflookingatthesedata.Itshowstheabsoluteannualchangeinthecompetitivenessmetric(thedifferencebetweenthesolarPVandfossilfuelLCOE).Forinstance,Australiasawthelargestabsoluteimprovementinutility-scalecompetitivenessin2012,wheretheimprovementinthecompetitivenessmetricyear-on-yearbetweentheLCOEofsolarPVandfossilfuelswasaUSD0.12/kWhshift,whilein2017and2019veryslightdeteriorationsoccurred.TheyearwiththelargestabsoluteimprovementinthedifferencebetweentheweightedaverageLCOEofutility-scalesolarPVandfossilfuelstendedtobeintheperiod2010to2013,giventhedramaticfallinsolarPVmodulepricesbetween2010and2013.TheexceptionswereArgentina,thePhilippines,TürkiyeandVietNam,whichcommencedlarge-scaledeploymentonlyafterthisperiodhadpassed.Lookingatthechangeincompetitivenessin2021,wherefossilfuelpricesarelikelytobeclosertolong-termexpectations,9ofthe20countrieswithdatainFigure1.8sawanimprovementincompetitivenessinUSD/kWhyear-on-yearthatexceededtheweightedaverageLCOEofsolarPVin2021.Thisoccurredinawidevarietyofjurisdictions,includingAustralia,Brazil,China,France,Germany,India,theUnitedKingdomandVietNam.52RENEWABLEPOWERGENERATIONCOSTSIN2022Annualchangeincompetitivenessmetric(USDkWh)---ArgentinaAustraliaBrazilCanada---ChinaFranceGermanyIndia---IndonesiaItalyJapanRepublicofKorea---MalaysiaMexicoPhilippinesSouthAfrica---TürkiyeUnitedKingdomUnitedStatesVietNamFigure1.8Annualchangeincompetitivenessofnewutility-scalesolarPVcapacityaddedbycountryandyear,2010-2022Source:IRENARenewableCostDatabaseandtheonlineannex.Note:ThismetricistheannualchangeinthecompetitivenessmetricinFigure1.7.53LATESTCOSTTRENDSFigure1.9presentsthesamecompetitivenessmetricforonshorewindasinFigure1.7,withtheexceptiontheweightedaveragenewfossilfuel-firedLCOEbycountryissubtractedfromthatofonshorewind.GiventhattheglobalweightedaverageLCOEofonshorewindin2010wasUSD0.107/kWh,comparedtoUSD0.445/kWhforutility-scalesolarPV,thedifferencebetweenthetwoLCOEsismuchcloser.However,theimprovementinthecompetitivenessisstillevidentformanycountriesinthesample.Withcostsrapidlyfallingintoarangecompetitivewithfossilfuel-firedpowergenerationinmanycountries,theannualchangesincompetitivenesshavesometimesseencountriespassaboveandthenbelowthezerolineatdifferenttimes.Thistendsnottobethecaseforcountriesthatsustainedsignificantlevelsofdeploymentthroughouttheperiod,suchasAustralia,Brazil,China,Germany,India,Italy,Mexico,Türkiye,theUnitedStatesandtheUnitedKingdom.Anotherimpactoftheselowerstartingcostsanddeclinesovertimeforonshorewindcomparedtoutility-scalesolarPVisthat,asidefromIndia,Indonesia,Mexico,thePhilippines,SouthAfricaandTürkiye,allcountriesexperiencedperiods–oftensustained–ofcompetitivenessinthefirsthalfoftheperiod.Thehigherfossilfuelpricesin2021and2022thereforesawlargeimprovementsinthecompetitivenessofonshorewindusingthismetricincountries,notablyinEurope,wherefossilfuelpricessurgedin2022.ThiscanbeclearlyseeninFigure1.10,wheretheyearofgreatestimprovementincompetitivenessforonshorewindoccurredineverycountrytrackedinthefigure,exceptforCanadaandJapan.18Lookingonlyatcountriesthathadthelargestcompetitivenessimprovementin2022(Australia,Germany,RepublicofKorea,SouthAfrica,Türkiye,theUnitedStatesandVietNam),theimprovementincompetitivenessin2021–ayearpotentiallymoreinlinewithlong-termfossilfuelpriceexpectationsnow–wasalsosignificant,ifnotanewrecord.Mexico,SouthAfricaandTürkiyewereexceptionstothisrule.Evenso,for12ofthe19countrieswithdatainFigure1.10,theimprovementincompetitivenessinUSD/kWhinthatoneyearexceededtheweightedaverageLCOEofonshorewindin2021.ThisoccurredevenintheUnitedStates,whichwasinsulatedfromtheworstofthefossilfuelpriceincreasesduetoitsdomesticproductionofgasandcoal.18InIndonesiaandthePhilippines,deploymenthasbeenmodestandsporadic.Therefore,acontinuoustimeseriesdoesnotexist,makingtheyearofgreatestimprovementdependentonasmallsubsetofyears.Jenson©Shutterstock.com54RENEWABLEPOWERGENERATIONCOSTSIN2022OnshorewindLCOEhigherthanfossilfuelsOnshorewindLCOElowerthanfossilfuelsUSDkWh--ArgentinaAustraliaBrazilCanada--ChinaFranceGermanyIndia--IndonesiaItalyJapanRepublicofKorea--MalaysiaMexicoPhilippinesSouthAfrica--TürkiyeUnitedKingdomUnitedStatesVietNamFigure1.9Competitivenesstrendsforonshorewindbycountryandyear,2010-2022Source:IRENARenewableCostDatabaseandtheonlineannex.Note:ThecompetitivenessmetricistheweightedaverageLCOEofrenewablepowerminustheweightedaverageLCOEoffossilfuelsinthatyear.55LATESTCOSTTRENDSAnnualchangeincompetitivenessmetric(USDkWh)---------------ArgentinaAustraliaBrazilCanadaFranceChinaGermanyIndiaIndonesiaItalyJapanRepublicofKoreaMalaysiaMexicoPhilippinesSouthAfricaTürkiyeUnitedKingdomUnitedStatesVietNamFigure1.10Annualchangeincompetitivenessofnewonshorewindcapacityaddedbycountryandyear,2010-2022Source:IRENARenewableCostDatabaseandtheonlineannex.Note:ThismetricistheannualchangeinthecompetitivenessmetricinFigure1.9.56RENEWABLEPOWERGENERATIONCOSTSIN2022LEARNINGCURVESFORSOLARANDWINDPOWERTECHNOLOGIESThecostdeclinesexperiencedbywindandsolarpowerfrom2010to2022representaremarkablerateofcostdeflationthatisunusualoutsideofconsumerproductsbasedondigitaltechnologies(e.g.computers,digitalcameras,etc.).Theimplicationsofthisexperiencewithsmall19modulartechnologies,withrelativelylowerbarrierstoentryinmanufacturing,fortheenergytransitionaremany.Itsuggestsatemplateexistsforaddressingthesectorsandtechnologiesneededtoacceleratetheenergytransitionbeyondthepowersector.Theyprovideinsightsintothecharacteristicsoftechnologiesthatareamenabletorapidscaleupandcostreductiontoensuredecarbonisationofend‑usesectors,fromelectrolyserstoelectricvehicles,heatpumpsandstationarybatterystorage.Thecostdeclineshave,ofcourse,significantimplicationsforthecompetitivenessofrenewablepowergenerationtechnologiesoverthemediumterm.Whatisnowclearisthatthesecostdeclineshavemadesolarandwindpowertechnologiestheeconomicbackboneoftheenergytransition.Figure1.11showstheglobalweighted‑averagetotalinstalledcosttrendsforutility‑scalesolarPV,CSP,andonshoreandoffshorewindfrom2010to2020,plottedagainstdeployment.Thischartputsboththesevariablesonalogarithmicscale(log‑log).Theslopeofastraightlineonalog-logchartthereforerepresentsthelearningrateforthesetechnologies.The“learningrate”or“learningcurve”istheaveragecostreduction(inpercentageterms)experiencedforeverydoublingofcumulativeinstalledcapacity.Utility‑scalesolarPVhasthehighestestimatedlearningratefortheglobalweighted‑averagetotalinstalledcostfortheperiod2010to2022,at33.1%.Thisisavaluethatexceedsvirtuallyallpreviouslearningrateanalysesbasedondatafortheearlierperiodofdeployment(Grubbetal.,2021),whenlearningratesmighthavebeenexpectedtobehigherthaninlaterperiods.Theperiod2010to2022isshort,butitsawthedeploymentof98%ofglobalcumulativeinstalledsolarPVcapacityandvirtuallyalloftheutility‑scaledeploymentincapacityterms.Overtheperiod2010to2022,thelearningrateforthetotalinstalledcostsofCSPwas18.1%,with88%oftotalcumulativeinstalledCSPcapacityaddedduringthisperiod.Thetotalinstalledcostlearningrateforoffshorewindfortheperiod2010to2022isestimatedtohavebeen12.4%,withnewcapacityadditionsoverthisperiodestimatedtobe97%ofthecumulativeinstalledoffshorewindcapacity.Foronshorewind,thetotalinstalledcostlearningratefortheperiod2010to2022isestimatedtobe20.6%.Thedeclineinwindturbinepricesandbalanceofplantcostshavebeendrivenbygreaterregionalsupplychainmaturity,innovationinmanufacturingandthecompetitiveprocurementofprojects.IRENA’sdataforonshorewindrunfrom1984,thelearningratefortheperiod1984to2022isestimatedtobe8.6%,butanapparentstructuralbreakinthedataposesinterestingquestionsabouttherelativecontributionmadebyearlymarketresearchanddevelopment(R&D)learning–comparedtoongoinginnovationandindustrialscaleup–indrivingdowncosts.19Smallinthiscontextreferstotheabilitytomanufacturelargequantities.ThisisclearlytrueforsolarPVpanels,butalsotrueforlarge,multi-MWwindturbineswhencomparedtofossilfuelplantsandtoday'snuclear.57LATESTCOSTTRENDSThelearningratefortheLCOEisafunctionofhowallofthecomponentsintheLCOEcalculationchangeovertime,notjustthetrendintotalinstalledcosts.Alltechnologieshavebenefittedfromsignificanttechnologyimprovementsthroughtime,aswellaslowerO&Mcostsand,inmanycountries,WACC.However,theimpactoftechnologyimprovementsactssomewhatdifferentlyforsolarPV.ForsolarPV,theincreaseinthemoduleefficiencyhasbeenakeytechnologymetricthatdriveslowerinstalledcosts,becausehigherefficienciesreducethesurfaceareaforthesamepowercapacity.Thisreducesthematerialscostperwattformodules,butalsoreducesthebalanceofplantcosts,asthesystemareaforthesamepoweroutputissmaller.ThisdynamicisuniquetosolarPV;CSP,onshorewindandoffshorewindallhaveseentechnologyimprovementsalsocontributetoimprovedperformance,andhencehighercapacityfactors.Asaresult,theLCOElearningrateforsolarPVisestimatedtohavebeen38.2%between2010and2022.Thisisaroundfivepercentagepointshigherthanthelearningratefortotalinstalledcosts.Incontrast,theLCOElearningrateforoffshorewindoverthesameperiodwas21.2%.Atalmostafulltenpercentagepointshigher,thiswasalmosttwicethelearningrateforthetotalinstalledcostsalone.ForCSP,theLCOElearningratewasestimatedtobe36.7%,twicethelearningratefortotalinstalledcostsgiventhetechnologyimprovementsthatsawthermalenergystoragecostsfallandresultin9-15hoursnowbeingtheeconomicoptimum,dependingonresourcequalityandmarketcircumstances,thathasraisedcapacityfactors(seeChapter5).ConcentratingsolarpowerOshorewindOnshorewindSolarphotovoltaicUSDkWCumulativedeployment(MW)Figure1.11TheglobalweightedaveragetotalinstalledcostlearningcurvetrendsforsolarPV,CSP,andonshoreandoffshorewind,2010-202258RENEWABLEPOWERGENERATIONCOSTSIN2022However,therecentLCOEreductionsforonshorewindandrelativeslowingofcumulativecapacitygrowth(inpercentageterms)haveseentheLCOElearningratefortheperiod2010to2022leapfrogthatofsolarPV(previouslyreportedfortheperiod2010to2020[IRENA,2021])toaremarkable43.4%fortheperiod2010to2022.ThisisinpartdrivenbythebettercharacterisationoftheWACCfortechnologiesbymarket,aswellastheremarkablecostreductionsinChinaandthecontinuedimprovementinturbinetechnology.Fortheperiod1984to2022,thelearningratewas14%,butagain,thereappearstobeastructuralbreak,withtwoperiodsofverydifferentlearningrates.Theimplicationsofthesehighlearningratesforsolarandwindpowerbetween2010and2020shouldnotbeunderestimated.Inthepowergenerationsectoritself,theysuggestthataccelerateddeploymentwillreducethecostofthetransition.Buttheyhaveawiderimplicationaswell.Theysuggest,wherethesamecharacteristicsareatworkthatsupportedthelearningratesforsolarandwind(e.g.smallmodulartechnologies,withabilitytorapidlyscalemanufacturingandlikelytohaveabreadthofcompetitivesuppliers)thattheemergingsolutionsfortheenergytransitioncanbeassessedagainstthesecriteria(andothers).Wheresimilarpossibilitiesforthescale-upexist,policymakerscanhavegreaterconfidencethatcostswillfallrapidlyandcanbemoreambitiousintheirpolicymaking.ConcentratingsolarpowerOshorewindOnshorewindSolarphotovoltaicUSDkWhCumulativedeployment(MW)FossilfuelcostrangeFigure1.12TheglobalweightedaverageLCOElearningcurvetrendsforsolarPV,CSP,andonshoreandoffshorewind,2010-202259LATESTCOSTTRENDSLessonslearntfromthefossilfuelpricecrisisof2022Fossilfuelpriceshavealwaysbeenvolatile,assupplyanddemandimbalancesandtheconcentrationofresourcesinthehandsofarelativelyfewmajorexportersmeanmarketvolatilityisagiven.Thecentralroleofenergyintheeconomyforcomfort,leisureand–aboveall–economicactivityhasmeanttheglobaleconomyhasbeenvulnerabletofossilfuelpriceshockssincethefirstoilembargo.The2022crisiswasdifferent.ThisisbecauseitwasarguablythefirstmajorsupplydisruptionsincethegrowthofLNGimportmarketsaroundtheworldcreatedastrongpricepath,throughwhichimbalancesinregionalnaturalgasmarketscouldbetranslatedintoglobalpriceincreases.2022waspossiblythemostseverefossilfuelpriceshockofthelast80yearsAsaresultoftheinterconnectednatureoftoday’sregionalfossilgasmarketsduetothegrowthinLNG,theseverityofthefossilfuelpriceincreasesin2020to2022maybethelargestglobalfossilfuelpriceshockexperiencedsofar,surpassingeventhe1970’soilshocks.Figure1.13presentsthepercentagepriceincreasesforfossilfuelsovertwoyearsforthefirst/secondoilshocksandforthe2020to2022period.ThedataontheleftsideofFigure1.13forthefirstandsecondoilshocksarefortheUnitedStates.20IntheUnitedStates,theperiod1973to1975sawthelargesttwo-yearpriceincrease,of34%forfossilgasand89%forcoalasfuelswitchingoccurred,notablyinthepowersectorandindustry,pushingupprices.However,forcrudeoil,itwasthesecondoilshockthatsawthelargesttwo-yearincreaseinthepriceofcrudeoilpurchasesover1979to198121intheUnitedStates,whenpricesincreasedby111%.Weightingbytheglobaltotalprimaryenergysupply(TPES)ofeachfuelin1981resultsinacompositeindexoftheincreaseoffossilfuelpricesintheoilshocksintheworsttwo-yearperiodsof88%.TakingthecoalandfossilgaspriceindicespresentedinFigure1.4andlookingattheincreasefor2020-2022,basedonasimpleaverage22oftheindicesinFigure1.4,yieldstheresultsinthemiddlepartofFigure1.13.Here,threesalientpointsareabundantlyclear:•Theoverallpriceincreasesovertheperiod2020to2022forcoal(245%)andfossilgas(350%)werelikelymuchmoreseverethantheglobaleconomyexperiencedinthefirstandsecondoilshocks.Forcrudeoilpricesitwasalsohigher,at128%.20Reliabledataforthisperiodacrossfuelsandcountriesarenotreadilyavailable,andcareshouldbetakenininterpretingthesedata.Experiencesinotherpartsoftheworldwouldhavebeendifferent,atleasttosomeextent,becausetheUnitedStateswasandisamajorproducerofallthreefossilfuels.21Giventhenatureoftheoilshocksinthe1970s,thetwoworstperiodsforpriceincreasesforcoalandfossilgaswerecombinedwiththeworstperiodforcrudeoiltoensurethattheseverityofthisperiod’spriceshockswasnotunderestimated.22Intheory,amorerobustnumbercanbecalculatedbyweightingthepriceindicesbyTPESofeachfuelindexforeachcountry.However,thiswouldrequireadditionaldatatoimprovethecoverageoffossilfuelpriceindicesbycountryandfuel,andideally,toend-userprices,ratherthanwholesaleprices.Thatlevelofanalysisisbeyondthescopeofthisreport.Itshouldthereforebenotedthatcountry-levelexperiencewilldifferfromwhatispresentedhere,andtheseaveragevaluesareanindicative,notprecise,viewoftheglobalexperience.60RENEWABLEPOWERGENERATIONCOSTSIN2022•Theorderofmagnitudeoffossilfuelpriceincreasesbyfuelwasreversedin2020-2022,withfossilgashavingthelargestincreaseandcrudeoilthesmallest,althoughinbothcasestheincreasewaswellabovethatofthefirstandsecondoilshocks.Coalremainedinbetweenthetwo.•Theoverallincreaseinthecompositeindex,of350%between2020and2022,isaroundfourtimeshigherthanforthefirstandsecondoilshocks.Fossilgas’shareoftotalfossilfuelsinTPESin2021was7percentagepointshigherthanin1981,whileitspriceincreasewasmorethantentimeshigherthanduringthefirstandsecondoilshocks,contributingtothis.However,thissimpleanalysisdoesnotconsiderthefactthatsincetheoilshocks,theglobaleconomyhasbecomemorefuelefficient,reducingitssensitivitytofossilfuelpriceshocks.Indeed,between1981and2021,theenergyintensityoftheglobaleconomydeclinedbyaround34%.Tocorrectforthisfactor,therightsideofFigure1.13showsthepriceincreasesafterbeingadjustedforthechangeintheenergyintensityoftheglobaleconomy(thatistosay,TPESdividedbyrealglobalGDP)between1981and2021.Thisisanimperfectmeasureofthereductioninthesensitivityoftheglobaleconomytofossilfuelpriceshocks,butitatleastallowsforatheoreticallybettercomparison.Withthischangeimplemented,itappearsthatthefossilfuelpriceshockof2022isstillsignificantlylargerthanthatexperiencedintheperiodoftheoilshocks,atleastwhenlookingataperiodoftwoyears.Isitpossibletobecertain,however,thatthisfossilfuelpriceshockwaslargerthantheoilshocks?Probablynot,becausemanyuncertaintiesremainaboutwhetherthisrepresentsafairimpactonconsumersofthepriceshocksof2021and2022todateonend-usersrelativetothefirstandsecondoilshocks,giventhatinEurope,governmentssteppedintoshieldhouseholdsandindustrialconsumersfromfullpriceimpacts(Sgaravattietal.,2021),whilemanyindustrialconsumersmayhavehadfixed-pricecontractsorfinancialhedgestomanagepricerisks.Atthesametime,itisnotclearinmanycaseshowhedgedsupplierswereandforwhatduration.Importpricedataareareliablemeasureforimportingnations,butthesearereportedwithalagandarealsooftenopentointerpretation.Whathasbecomeclearwiththecrisisisthatmanyenergymarketsarenottransparent,andtheincidenceofwherecostsandbenefitsfallisopaque,tosaytheleast.Giventhesecaveats,andthefactthatwehavenotyetseenallofthecostsfromthefossilfuelcrisispassthoughintotherealeconomy,theoverallmacroeconomicimpactofthecurrentpriceshockremainstobeseen.Theoilshocksofthe1970sandearly1980swereaprolongedperiodofelevatedpricesand,asnoted,constitutedtwoseparateshocksoneaftertheother.Iffossilfuelpricesreturn,andstayat,lowerlevelsoverthenextfewyears,theworldmaywellavoidscenariosthathavesimilarharmfuleconomiceffectstotheoilshocks.However,withtheincreasingchallengesthatacceleratingclimatechangeiscreatingforinfrastructure,agricultureandsupplychains,thepotentialremainsforthistobepartofaseriesofmoreorlessseveremacroeconomicchallengesstemmingfromtheinteractionofclimatechangeandtherealeconomy.61LATESTCOSTTRENDSRenewablesrepresentenergysecurityThefocusofpolicymakersinearly2022,asthefossilfuelpricecrisisburstontotheworldstage,wasinsecuringeverincreasinglyexpensivesuppliesoffossilfuels.However,astheworldhasbecomepainfullyaware,energysecuritymeetsitslimitswhenitfocusespredominantlyondiversifyingsourcesoffossilfuelsandnotinreducingtheworld’seconomiesexposuretofossilfuels.Intheshort-tomedium-term(onetofiveyears)onlyenergyefficiencyandrenewableenergyprovideaguaranteedhedgeagainstfossilfuelpriceshocks.Renewablepowergenerationandenergyefficiencyaretwooptionsthatareguaranteedtoprotectconsumersfromfossilfuelpriceshocks.Diversifiedfossilfuelsupplysourcesandindigenousproductiondonotprotectconsumersfromtheimpactofpriceshocksperse,buttheycanreducetherisksofphysicalshortageandprovidesuper-profitstofossilfuelcompanies.Geothermal,hydropower,andsolarandwindpowerhavenofuelcostsandreducefossilfuelimportsinimportingcountries,improvingthebalanceofpaymentssituationandshieldingtheeconomyfromfossilfuelpriceshocks.Theyalsosupportlocaljobsandvaluecreation,evenifmajorcomponents(e.g.PVmodules)areimported.Thisisinadditiontotheirnormaleconomiccontributiontoelectricitysupplyandthebenefitsoflowerhealthandclimatechangecosts.Theyear2022sawnationsdependentonfossilfuelimportsrediscovertheimportanceofenergysecurityafteradecadeormoreofcomplacency.Whathasnotbeenfullyappreciatedisthatwithouttheprogressinrenewableenergydeploymentandenergyefficiencyoverthelastdecadeandmore,Europewouldhavefacedanevenmoreseverecrisis.Suchacrisiswouldprobablyhaveleftgovernmentswithoutthefinancialresourcestosoftentheblowfortheircitizenstothesameextentthatoccurredin2022.GasCoalOilCompositeindexGasCoalOilCompositeindexGasCoalOilCompositeindexFirstsecondoilshocksSimpleaverageincreaseinfuelpricesCorrectedforenergyintensity--TwoyearpriceincreaseFigure1.13Largesttwo-yearfossilfuelpriceincreasesduringthefirstandsecondoilshockcomparedto2020to2022Source:U.S.EnergyInformationAdministration(2012,n.d.);andtheonlineannex.Note:DataforthefirstandsecondoilshockperiodarefortheUnitedStatesonly,whilethedatafor2020-2022areasimpleaverageofthetwo-yearpriceincreasesforallthepriceindicespresentedinFigure1.4.CirclesizeistheglobalTPESofthatfuelfor1981and2021,respectively,forthetwoperiods.ThecompositeindexisthepercentagepriceincreaseforafuelweightedbyitsTPESinthatyear.Allpriceswereinreal,accountingforinflation,terms.62RENEWABLEPOWERGENERATIONCOSTSIN2022Renewablepowergenerationdeployedsince2000globally,reducedelectricitysectorfuelcostsbyanestimatedUSD521billion23in2022(Figure1.14),assumingmarginalsupplieswouldhavebeensourcedatspotmarketprices.24ThefuelcostreductionwasalmostUSD200billioninAsia.Itwasalmostashigh,atUSD176billion,inEurope,wherenaturalgaspriceswereamongthehighestintheworldin2022.SouthAmericaalsobenefitted,potentiallyontheorderofUSD71billion.Europe,givenitsveryhighfuelcostsin2022,accountsforUSD95billion(57%)ofthenetsavingsandUSD176billionofthefuelsavings.Asia,withitslargeelectricityconsumptionandcloserrangebetweenrenewableandfossilfuelcostsovertheperiod,accountsforamuchsmallershareofthenetfuelsavings.LookingjustatEurope,renewablecapacityaddedsince2010savedanestimatedUSD176billioninfossilfuelimportsin2022,asfossilgasandcoalpricessoared.Thelargestcontributionswerefromonshorewind(USD80billion),bioenergy25(USD36billion)andoffshorewind(USD28billion).EuropeUSD521billionUSD176billionWorldElectricitysectorfuelsavings(generatedinMWh)OnshorewindUSDbillionSolarphotovoltaicUSDbillionOshorewindUSDbillionBiomassUSDbillionAisaUSDbillionEuropeUSDbillionSouthAmericaUSDbillionNorthAmericaUSDbillionEurasiaUSDbillionUSDbillionUSDbillionAfricaUSDbillionHydropowerGeothermalMiddleEastOceaniaCentralAmericaandtheCaribeanFigure1.14GlobalandEuropeanannualfuelsavingsintheelectricitysectorfromrenewablepowergenerationdeploymentsince2000in2022Basedon:project-levelLCOEdataforrenewablesandgeneratedfossilfuelcostsbasedontheonlineannex.23ThisexcludestheLCOEoftherenewabletechnologies,thatistosaythecostofunlockingthosefuelsavings.Subtractingtherenewableprojects’LCOEfromthefuelsavingswouldnotyieldthetrue“netsavings’,however.ThisisbecauseitexcludesthereducedO&Mandcapitalcostsfromreducedfossilfueluse,whichareincludedforinstanceinFigure1.6.Thisanalysisissolelytounderstandthefossilfuelcostreduction,henceimportsinimportingcountriesandregions.24Thisestimateisdesignedtogiveanorderofmagnitudeofthebenefitsofrenewablepowergenerationin2022.Theadditionalfossilfueldemandin2022wouldhavebeenverysignificantandtheimpactofthecrisisinthathypotheticalworldcannotbeknownwithanycertainty.25TheheatcreditfromCHPplantsfiredonbioenergyarepartofthereasonwhythefuelsavingsfrombioenergyaresosignificant.63LATESTCOSTTRENDSYetthebenefitsofthesesavingsarenotreadilyapparenttoconsumers,inparticular.Thisinpartstemsfromtheslowprogressthatisbeingmadeinreformingelectricitymarketsatboththewholesaleandretaillevel.IRENAhasdiscussedtheimportanceofensuringthatpolicyreformsforelectricitymarketstructuresandorganisationmoveinlock-step,notlaggingtheenergytransitionintheelectricitysectorforanumberofyears(IRENA,2017,2022).Currentlyinmanymarkets,duringaperiodofspikingfossilfuelprices,themarginalcostsoffossilgeneratorsincreaseandtheythenbidthesehighercostsintothewholesalemarket.Withmarginalcostpricing,theclearingpricethenbecomeshighlyelevated,andthosegeneratorswithoutfixedcontractsandlowermarginalcostswillseewindfallprofits(Garcia-CasalsandBianco,2022).Thoseutilitiesandelectricityretailerswhoarenoteitherfinanciallyhedgedorhaveanaturalhedge(intermsoflow-costgeneratorsintheirfleet)willhavetoraisepricesforconsumers.Atthispoint,electricitypricingforconsumerscanbecomehighlydisconnectedfromactualsystemgenerationcosts.Thereasonforthisisthatwiththeriseofrenewablepowerproductionandexistingnucleargeneration,theoverallcashcoststothesystemoffossilfuelpriceincreasesaremuchlowerthanthecostsbasedonmarginalcostpricing.InEuropein2022,fossilgasaccountedforaround26%oftotalgenerationandcoalaccountedforafurther16%;55%camefromrenewablesandnuclear.ThisisillustratedinFigure1.15,whichshowsthatinEurope,theaverageincreaseinwholesaleelectricitypricesbetween2019(pre-pandemiclevels)and2022wasUSD0.176/kWh.However,averagingtheincreaseingeneratedfossilfuelcostsacrosstheentireproductionofelectricityin2022(Ember,2023),theincreaseincashcoststothesystemwasintheorderofUSD0.05/kWh.Thiscalculationisbasedonthemarkerpricesforfossilfuelspreviouslypresented,buttheactualcostincreasemayhavebeenlower.TakingintoaccounttheincreaseinEuropeanimportcosts(Eurostat,n.d.)suggeststhatsomehedgingwasstillbenefittingpurchasersoffossilgasin2022.Takingtheoverallincreaseinnaturalgaspricestobuyersimpliedbytheincreaseinimportcosts,ratherthanmarkerprices,reducestheoverallincreaseincashcoststoaroundUSD0.04/kWh.Overall,itwouldappearthatconsumers,withdataavailableonlyuptothesecondhalfof2022,areseeinganincreasesomewherebetweenthesetwovalues.DatafromEurostatsuggestthatpricesforlargeconsumersincreasedbybetweenUSD0.121/kWhandUSD0.137/kWhbetweenthesecondhalfof2019andthesecondhalfof2022.26Forhouseholds,theincreasehasbeenveryheterogeneous,dependingontheregulatorysystemandelectricitysectorstructure,aswellasgovernmentinterventionstoshieldconsumersfrompriceincreases.Theincreaseshaverangedfromaslightfall(inrealterms)toanincreaseofUSD0.26/kWhinDenmark,withtheEuropeanUnionaverageincreasebeingUSD0.115/kWh.Withgovernmentinterventionswindingdownin2023,itispossiblethatsomemarketshavenotseenthefinalincreaseinpricesfromlastyear’spricesshocks.However,tounderstandtowhatextentthismaybetrue,dataforthefirsthalfof2023needtobeavailable.26Thisprobablyoverestimatestheoverallincrease,asmanylargerusersmaystillhavehadhedgingstrategiesinplacethatinsulatedthemfromthefullcostincreaseover2021tracked-intariffs.64RENEWABLEPOWERGENERATIONCOSTSIN2022WhatseemstobeclearisthatgiventhestructureofmostEuropeanelectricitymarketsandtheregulationsgoverningpricingtoend-users,consumershaveseenpriceincreasesfarbeyondtheaveragecostincreaseingenerationacrossEuropeintheperiod2019to2022.Thefactthatreformofelectricitymarkets,bothatthewholesaleandretaillevel,haslaggedbehindthechangeintheelectricitymixasrenewables’shareincreasedwasnotanobviousissueintheperiod2013-2020,giventhelowfossilfuelprices.However,asIRENAhaspreviouslynoted,delayingthisreformhasnotbeenwithoutrisk.Thefossilfuelpricecrisisof2022hashighlightedtheinadequacyofcurrentarrangements,andthecoststhishashadforend-usershavebeensignificant.Theeconomiccostshavebeenpartlybornebygovernmentssofar,butconsumershavealsopaidasignificantcost.Theirshareoftheburdenislikelytobelargerin2023aspricereliefmeasureslapseorbecomelessgenerous.WholesalepricesLargeconsumerpricesHouseholdpricesWholesalepricesHosueholdCashcosts(pricemarkers)Cashcosts(importpricing)BandIAMWhBandIB-MWhBandIC-MWhBandID-MWhBandIE-MWhBandIF-MWhBandIGMWhHHChange-(USDMWh)Figure1.15IncreasesinEuropeanwholesaleelectricityprices,andpricestolargeconsumersandhouseholds,2019-2022Source:Ember(2023);Eurostat(2023a,2023b,n.d.).65LATESTCOSTTRENDSCompoundingthisimpactonconsumershasbeensomethingofa‘lostdecade’inEuropewhen,justassolarandwindpowercostswerefalling,newcapacityadditionsinthemajorEuropeaneconomiesslowedorsawonlybriefspurtsingrowth.ThisisillustratedinFigure1.16,whichshowsthetrendinpercapitaadditionsofsolarPV(leftside)andonshorewind(rightside)plottedagainsttheutility-scaleweightedaveragecountryLCOE,withthepaththetrendbetween2010and2022.Whatisapparent,apartfromthesignificantvariationinpercapitaadditionsbetweencountries,isthatinFrance,Germany,ItalyandSpain,solarPVdeploymentdroppedorstagnatedbetweenaround2012and2019,withsignificantreductionsfrompeakadditions.TheUnitedKingdomfollowedaverydifferentpattern,withapeakin2015butlittledeploymentoneithersideofthatyear.DeploymentofsolarPVhasrespondedtohigherfossilfuelprices,withdeploymentgrowinginthemajorEuropeaneconomies,butonlySpainhasapproachedthepercapitaadditionsofGermany(andevenGermanyremainsbelowtherecorditsetofover10MWaddedper100000populationin2012).Thesituationforonshorewinddeploymentismoreheterogeneous,withnocleartrendintakingadvantageofthefallinelectricitycostsfromonshorewind,withtherecentexceptionofSpain.TheonshorewindsectorinEuropefacessignificantchallengestoscalingupdeployment,notablyduetostumblingblocksaroundpermittingandenvironmentalapprovals(GWEC,2023).Havingsaidthis,thesectordidmanagetoincreasedeploymentin2022to16.7GWofnewcapacityadded,around2.6GWmorethanin2021.Withsomenotableexceptions,mostofthelargerEuropeancountriesappeartohavelargelynotcapitalisedonthelearninginvestmentstheyhelpedcontributetothatdrovedownthecostofelectricityfromutility-scalesolarPVbyaround89%,globally,between2010and2022.TheslowingdeploymentofsolarPVascostsfell,inparticular,resultedinEuropeaneconomiesbeingmorevulnerabletothecostsof2022’sfossilfuelpriceshock.ThisalsohighlightsthemissedopportunitiesfortheclimateandEuropeaneconomiesthatresultedfromlacklustresolarPVdeploymentaftercostshadfallenrapidly.Foronshorewind,themodestnewcapacityadditionsacrossthecontinentinrecentyearswasalsocostlyforconsumersandindustryin2021and2022.AnumberofEuropeancountriesfailedtofullycapitaliseonthefallingcostsofrenewablesinthelastdecade,costingconsumersin202266RENEWABLEPOWERGENERATIONCOSTSIN2022Akeypointthathasnot,probably,hadenoughweightinthediscussionoftheroleofrenewablepowerinprovidingenergysecurityisthatitoffersafundamentallydifferenthedgetorisingfuelcosts.Hedgingfossilfuelpricescomesatacost,becausefossilfuelpricesareinherentlyvolatileandsomeonemustbecompensatedfortakingontherisk.Hedginganelectricitysystembasedonfossilfuelsisthereforeinherentlycostly,albeitlikelytobedesirablefromacustomer’sperspective(dependingonthecost).Withrenewablepower,theexactoppositeistrue.Becauserenewablepowerisnotexposedtofuelpricerisk,butrevenuerisk,thecheapestrenewableelectricitycomeswhentheproject’slifetimevolumeofgenerationiscontractedfor.Thisreducesprojectriskandensuresthelowestcostofcapital,andhencecostofelectricitytocustomers.Thecostofhedgingtheelectricitysupplysystemwithrenewablesthereforecomesatadiscount,notacostaddition.AustraliaMWpeopleUSDkWhIncreasingdeploymentpercapitaLowerLCOEandhigherdeploymentFallingLCOEHowtoreadthischartGreeceGermanyJapanUnitedKingdomUnitedStatesIndiaChinaItalyTheNetherlandsBrazilFigure1.16ChangesinannualnewsolarPVcapacityadditionspercapitacomparedtoLCOEtrendsbycountry,2010-2022Source:IRENARenewableCostDatabase;WorldBank(2023).DanielBalakov©Gettyimages.comhuangyifei©Shutterstock.com02ONSHOREWIND69HIGHLIGHTS•Between2010and2022,onshorewind’sglobalweightedaveragelevelisedcostofelectricity(LCOE)fell69%,fromUSD0.107/kilowatthour(kWh)toUSD0.033/kWh.In2022,theLCOEfell5%,year-on-year.•In2022,around59gigawatts(GW)ofthenewonshorewindprojectscommissionedhadanLCOElowerthantheweightedaveragecostofnewfossilfuel-firedpowerbycountry/region.Thiswas87%ofthenewonshorewindcapacityadditionsin2022.•Theglobalcumulativecapacityofonshorewindincreasedalmostfivefoldduringthe2010to2022period,from178GWto837GW.•Theglobalweightedaveragetotalinstalledcostofonshorewindfell42%between2010and2022,fromUSD2179/kilowatt(kW)toUSD1274/kW.In2022,itwasdown10%onits2021value,drivenbythecontinuedcostdeclinesinChina.•However,manymarketssawcostincreasesin2022,ashigherturbineprices(outsideofChina)impactedprojectcosts,includingthoseinCanada,France,Germany,India,Japan,Türkiyeandahostofsmallermarkets.•In2022,thecountryweightedaverageforthe15marketsIRENAhaslong-termdataforsawthetotalinstalledcostforonshorewindrangefromaroundUSD1052/kWtoUSD1918/kW,withJapananoutlieratUSD3521/kW.Brazil,China,India,SwedenandtheUnitedStatesallhaveinstalledcostslowerthantheglobalaverage.•In2022,averageonshorewindturbineprices(excludingChina)rangedbetweenUSD870/kWandUSD1066/kW,materiallyhigherthanin2021.Despitethisincrease,by2022,pricesinmostregions(excludingChina)hadfallenbybetween49%and64%fromtheirpeaksin2008/2009.InChina,by2022,windturbinepriceshadfallen89%sincetheir1998peakofUSD2800/kWtoaveragejustUSD320/kW.•Technologyimprovementshaveresultedinamorethanone-thirdimprovementintheglobalweightedaveragecapacityfactorofonshorewind,from27%in2010to37%in2022.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure2.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforonshorewind,2010-202270RENEWABLEPOWERGENERATIONCOSTSIN2022INTRODUCTIONOnshorewindturbinetechnologyhasadvancedsignificantlyoverthepastdecade.Largerandmorereliableturbines,alongwithhigherhubheightsandlargerrotordiameters,havecombinedtoincreasecapacityfactors.Inadditiontothesetechnologyimprovements,totalinstalledcosts,operationandmaintenance(O&M)costs,andLCOEshavebeenfallingasaresultofeconomiesofscale,increasedcompetitivenessandthegrowingmaturityofthesector.In2022,theextentofonshorewinddeploymentwassecondonlytothatofsolarphotovoltaic(PV),whileChinawasstillthelargestmarket,albeitwithalowersharethanin2020.Thelargestshareofthetotalinstalledcostofanonshorewindprojectisrelatedtothewindturbines,whichtodaymakeupbetween64%and84%ofthetotalcost(IRENA,2018).Virtuallyallonshorewindturbinestodayarehorizontalaxis,predominantlyusingthreebladesandwiththebladesupwind.27Contractsfortheseprojectstypicallyincludethetowers,installationand,exceptinChina,delivery.Theothermajorcostcategoriesincludeinstallation,gridconnectionanddevelopmentcosts.Thelatterincludesenvironmentalimpactassessmentandotherplanningrequirementcosts,projectcosts,andlandcosts,withtheserepresentingthesmallestshareoftotalinstalledcost.WINDTURBINECHARACTERISTICSANDCOSTSWindturbineoriginalequipmentmanufacturers(OEMs)offerawiderangeofdesigns,cateringfordifferentsitecharacteristics,28gridaccessibilityandpolicyrequirementsindistinctlocations.Thesevariationsmayalsoincludedifferentland-useandtransportationrequirements,andtheparticulartechnicalandcommercialrequirementsofthedeveloper.ThisusebytheOEMsofaseriesofplatformsthatofferdifferentconfigurationssuitedtoindividualsiteshasalsobeenanimportantdriverofcostreductions.Theplatformsdothisbyamortisingproductdevelopmentcostsoveralargernumberofturbines,whilealsooptimisingturbineselectionforaparticularsite,furtherreducingtheLCOE.Turbineswithlargerrotordiametersincreaseenergycapture29atsiteswiththesamewindspeed.Thisisespeciallyusefulinexploitingmarginallocations.Inaddition,thehigherhubheightsthathavebecomecommonenablehigherwindspeedstobeaccessedatthesamelocation,whilealsoincreasingtherangeofsuitablelocationsforwindturbines.Forexample,atallerhubheightmeansanincreaseddistancebetweenthebladetipsandtheground,enablinginstallationincertainforestedareas.Thesedevelopmentscanyieldmateriallyhighercapacityfactors,giventhatpoweroutputincreasesasacubicfunctionofwindspeed.Thehigherturbinecapacityalsoenableslargerprojectstobedeployedandreducesthetotalinstalledcostperunitforsomecostcomponents,expressedinmegawatts(MW).3027Meaningthattherotorbladesarefacingthewind.28Suchasdifferentwindspeeds,areasforadequatespacingtoreducewaketurbulenceandturbulenceinducingterrainfeatures.29Energyoutputincreases,asafunctionofthesweptareaofthebladesasasquaredfunctionofthesurfacearea,whichisakeyvariableinthepoweroutputofawindturbine.30Increasingturbinesizedoesnotleadtoaproportionalincreaseinthecostofotherturbinecomponents,e.g.towers,bearingsnacelle,etc.Thus,theincreaseincostonaperunitbasisisnotassignificantasmightbeexpected.71ONSHOREWINDFigure2.2illustratestheevolutioninaverageturbineratingandrotordiameterbetween2010and2022insomemajoronshorewindmarkets.Brazil,Canada,China,Germany,IndiaandSwedenstandout,withincreasesofgreaterthan60%inaveragerotordiameteroftheircommissionedprojectsovertheperiod.Inpercentageterms,thelargestincreaseinturbinecapacitywasobservedinChina(190%),followedbyBrazil(129%),Sweden(118%),Germany(116%)andCanada(118%).ThelargestincreaseinrotordiameteralsooccurredinChina(118%),Brazil(72%),India(69%)andCanada.OfthecountriescoveredinFigure2.2,in2022,TürkiyesurpassedCanadatohavethelargestturbinerating,whileforthedataavailableChinahadthelargestturbinerotordiameters,at161metres(m)onaverage.In2022,Indiahadthelowestturbineratingat2.6watts(W),whileJapanhadthelowestaveragerotordiameteratanaverageof105m.Overall,in2022,thecountry-levelaverageturbinecapacityrangedfrom2.6MWto4.8MW,substantiallyhigheratbothendscomparedtothe2.0MWto4.3MWin2021.In2022,thecountryweightedaveragerotordiameterrangedfrom105mto163m;again,thiswasmateriallygreaterthanthe99mto147mrecordedin2021.Windturbinepricesreachedtheirpreviouslowbetween2000and2002,withthisfollowedbyasharpincreaseinprices.Thiswasattributedtoincreasesincommodityprices(particularlycement,copper,ironandsteel),supplychainbottlenecksandimprovementsinturbinedesign,withlargerandmoreefficientmodelsintroducedtothemarket.Duetoincreasedgovernmentrenewableenergypolicysupportforwinddeployment,however,thisperiodalsocoincidedwithasignificantmismatchbetweenhighdemandandtightsupply,whichenabledsignificantlyhighermarginsforOEMsduringthistime.Yet,asthesupplychainbecamedeeperandmorecompetitiveandmanufacturingcapacitygrew,thesesupplyconstraintseasedandwindturbinepricespeaked.Mostmarketsexperiencedthatpeakbetween2007and2010,withannualaveragepricesfallingbybetween49%and64%between2009and2022.In2022,quarterlypriceswereintherangeofUSD840/kWtoUSD1175/kWinmostmajormarketsafterrisingfromlowsin2020,excludingChina(Figure2.3).InChina,wherewindturbinepriceshavefallendramaticallyfromtheirpeakofaroundUSD2800/kWin1998,thedeclinehasbeeninanirregular,step-wisefashion.China’sturbinemarketcontinuestomoveatitsownrhythm,defyingthecostpressuresfeltintherestoftheworldoverthelasttwoyears.JapanFranceGermanyBrazilCanadaChinaIndiaSwedenTürkiyeUnitedKingdomUnitedStatesVietNamRotordiameter(m)Nameplatecapacity(MW)Figure2.2Weightedaverageonshorewindrotordiameterandnameplatecapacityevolution,2010-2022Note:DataforVietNamareonlyavailablefor2021and2022.72RENEWABLEPOWERGENERATIONCOSTSIN2022In2022,contrarytotheexperienceelsewhere,averageChinesewindturbinepricesfelltoaroundUSD310/kW,ascontinuedpressuresfromdeveloperssawpricesfallagain,despiteanupturninQ3.Globally,withgreatercompetitionamongmanufacturers,marginshavecomeunderincreasingpressure.Manufacturers’turbinesalesmarginshavefallenovertimeand,withincreasedcommoditycostsin2021and2022,probablyneedtorisetoreturntosustainablelevels(Blackburne,2022).Increasedcompetitionisbeingreinforcedbytheincreaseduseofcompetitiveprocurementprocessesforrenewableenergyinagrowingnumberofcountries.Increasedcompetitionhasalsoledtoacquisitionsintheturbineandbalance-of-plantsectorsandatrendofproductionmovingtocountrieswithlowermanufacturingcosts(WoodMacKenzie,2020).Thisincreasedcompetitiondoesnotmakethesectorimmunefromtheimpactofsupplyanddemandimbalances,however.Significantgrowthinthemarketin2020andsupplychainconstraintsduetoCOVID-19sawwindturbinepricinginlate2020andearly2021tickup,withelevatedpricescontinuinginto2022.QuarterlyturbinepricingrangedfromUSD840/kWtoUSD1089/kWfororders(excludingChina)receivedin2021(BNEF,2023;Vestas,2023).Thisrangewidenedsomewhatin2022,fromUSD840/kWtoUSD1175/kW,butthiscorrespondedwithVestas’ssellingpricedroppinginQ12023asthemixofordersbygeographiclocationchanged(Vestas,2023).Itistooearlytotellifpriceswillcontinuetoeasein2023.Thedeclineinturbinepricesgloballyoverthelastdecadeoccurreddespitetheincreaseinrotordiameters,hubheightsandnameplatecapacities.Inaddition,pricedifferencesbetweenturbineswithdifferingrotordiametersnarrowedsignificantlyin2019.However,inlate2020,thegapbetweenClassIandbothClassIIandClassIII31windturbinesstartedtowidenandhaspersistedinto2022(BNEF,2023).31ThisreferstotheInternationalElectricalCommission’swindturbineclassification.Broadlyspeaking,ClassIwindturbinesaredesignedforthebestwindspeedsitesandtypicallyhaveshorterrotors,andClassIIIturbinesaredesignedforpoorerwindconditionswherelargerrotordiametersandlowerspecificpower(W/sweptsquaremetre[m2])areusedtoharvestthemaximumenergy.ChineseturbinepricesVestasaveragesellingpriceUnitedStates-MWUnitedStatesMWUnitedStatesMWBNEFWTPImØBNEFClassIIBNEFWTPImØBNEFClassIIIBNEFWTPIBNEFClassIUSDkWFigure2.3Windturbinepriceindicesandpricetrends,1997-2023Source:BNEF(2023);VestasWindSystemsA/S(2023);Wiseretal.(2022);andIRENARenewableCostDatabase.73ONSHOREWINDTOTALINSTALLEDCOSTSBetween1984and2022,theglobalweightedaveragetotalinstalledcostofonshorewindprojectsfellby74%,fromUSD5496/kWtoUSD1274/kW,accordingtodatafromtheIRENARenewableCostDatabase(Figure2.4).Overthisperiod,globalaveragetotalinstalledcostsfellbyaround9%foreverydoublingincumulativeonshorewindcapacitydeployedglobally.Thisdeclinewasdrivenbywindturbinepriceandbalance-of-plantcostreductions.Between2010and2022,theglobalweightedaveragetotalinstalledcostofonshorewindfellby42%,fromUSD2179/kWtoUSD1274/kW,witha10%declineyear-on-yearin2022.Figure2.5showsthetrendincountry-specificweightedaveragetotalinstalledcostsfor15countriesthataremajorwindmarketsandhavesignificanttimeseriesdata.Individualcountriessawarangeofcostreductions–from78%intheUnitedStatestojust14%inTürkiye–butthesecomparisonsneedtobetreatedwithcaution,giventhedifferingstartdatesforthefirstavailabledata.Japan,forexample,sawa34%increaseovertheperiodshown,withthefirstcostdatapointin2000.Themorecompetitive,establishedmarketsshowlargerreductionsintotalinstalledcostsoverlongertimeperiodsthannewermarkets.TheUnitedStates(a78%reduction),followedbyBrazil,IndiaandSweden(allwitha72%reduction)hadthehighestdecreaseintotalinstalledcostsovertheirrespectivetimeframes.Spainsawareductionof70%andChinasawareductionof64%.Inaddition,thereisawiderangeofindividualprojectinstalledcostswithinacountryandregion.Thisisduetothedifferentcountry-andsite-specificrequirements,e.g.logisticslimitationsfortransportation,localcontentpolicies,land-uselimitations,labourcostsandotherfactors.USDkWCapacity(MW)≤≥Figure2.4Totalinstalledcostsofonshorewindprojectsandglobalweightedaverage,1984-202274RENEWABLEPOWERGENERATIONCOSTSIN2022DenmarkBrazilJapanGermanyChinaSwedenIndiaUnitedStatesItalyTürkiyeUnitedKingdomSpainMexicoCanadaFranceJapanUSDkWFigure2.5Totalinstalledcostsofonshorewindprojectsin15countries,1984-202275ONSHOREWINDDataataregionallevel(Table2.1)showthattheregionswiththehighestweightedaveragetotalinstalledcostsin2022were(indescendingorder):“OtherAsia”(excludingChinaandIndia),CentralAmericaandtheCaribbean,Africa,Eurasia,Europe,Oceania,andOtherSouthAmerica(excludingBrazil).Therehasbeensignificantconvergenceinweightedaverageinstalledcostsbyregionintotwodistinctgroups,withonearoundUSD1625/kWtoUSD1715/kWandtheotherbetweenUSD1285/kWandUSD1315/kW.Brazil,ChinaandIndiahavemorematuremarketsandtypicallylowercoststructuresthantheirneighbours.Thiscanbeseenintheirloweraverageinstalledcostsforonshorewindin2022.Forthefirsttime,Brazilhadthemostcompetitiveweightedaveragetotalinstalledcoststhatyear,atUSD1052/kW,despiteseeinga6%realincreaseininstalledcostsyear-on-year.Overall,Brazil’sweightedaveragetotalinstalledcostofnewcapacityadditionshasfallenby72%since2010.Brazil,ChinaandIndiaallhadrelativelysimilarweightedaveragetotalinstalledcostsin2022:USD1052/kWandUSD1122/kW.Meanwhile,Sweden(USD1237/kW),theUnitedStates(USD1219/kW)andSpainallhadverycompetitiveweightedaveragenewcapacityadditionsin2022.Table2.1Totalinstalledcostrangesandweightedaveragesforonshorewindprojectsbycountry/region,2010and2022201020225thpercentileWeightedaverage95thpercentile5thpercentileWeightedaverage95thpercentile(2022USD/kW)Africa153017282260152516852110CentralAmericaandtheCaribbean280129703127169416941694Eurasia271127112711134316502398Europe19602693392999016261998NorthAmerica20992743356298712851907Oceania333939034291106913611893OtherAsia205527893061121617153389OtherSouthAmerica25132739286389213051504Brazil26332926321967710521960China14031663194690211031534India9961537179095011221246Note:“OtherAsia”isAsiaexcludingChinaandIndia;“OtherSouthAmerica”isSouthAmericaexcludingBrazil.Datafor2021.76RENEWABLEPOWERGENERATIONCOSTSIN2022FinlandPeruPhilippinesPolandPortugalRepublicofKoreaCostaRicaCroatiaCyprusDominicanRepublicEgyptEthiopiaChileArgentinaAustraliaAustriaRussianFederationSouthAfricaUkraineUruguayVietNamUSDkWGreeceIndonesiaIrelandMoroccoNetherlandsNewZelandNorwayPakistanPanamaFigure2.6Onshorewindweightedaveragetotalinstalledcostsinsmallermarketsbycountry,2010-2022nitpicker©Shutterstock.com77ONSHOREWINDCAPACITYFACTORSThecapacityfactorrepresentstheannualenergyoutputfromawindfarm,expressedasapercentageofthefarm’smaximumoutput.Itispredominantlydeterminedbytwofactors:thequalityofthewindresourcewherethewindfarmissitedandtheturbineandbalance-of-planttechnologyused.Thetrendtowardsmoreadvancedandmoreefficientturbinetechnologieswithlargerrotordiametersandhubheightshasseenenergyoutputsandcapacityfactorsriseinmostmarketsoverthelasttenyears.Indeed,theglobalweightedaveragecapacityfactorforonshorewindincreasedby93%between1984and2022,fromaround19%intheformeryearto37%inthelatter.Thisupwardtrendwasalsoobservedduringthe2010to2022period.Duringthisperiod,theglobalweightedaveragecapacityfactorofonshorewindincreasedby35%from27%to37%.Theglobalweightedaveragecapacityfactorfornewlycommissionedcapacityofonshorewindwaslowerin2022than2021,asarangeofmarketssawslightlylowercapacityfactors.Thiswasnotunexpectedafter2021,ayearthatbenefittedfromincreaseddeploymentincountriesandregionswithexcellentwindresources,notablytheUnitedStatesandLatinAmerica.AlongsidethiswasasignificantdeclineinChina’sshareofglobaldeploymentthatyear.WithChina’sshareofnewcapacityaddedincreasingin2022,andprojectsmoreevenlydistributedacrossexcellentandaveragewindresourcelocations,theglobalweightedaveragecapacityfactordeclinedfromitshighin2021.AsFigure2.2highlights,theimpactofcontinuedtechnologyimprovements,largerturbines,higherhubheightsandlargersweptareascontinues.Thebalanceofdeploymentacrosstheglobeanditsresourcequality,however,isalwaysgoingtohaveasignificantimpactontheglobalweightedaveragecapacityfactor,eventhoughtechnologyimprovementshaveraisedoutputacrosstheboardovertime.Widevariationthereforeremainsinthecapacityfactoracrossmarkets.Whilethisispredominantlyduetodifferingwindresourcequalities,itisalso,toalesserextent,duetothedifferenttechnologiesusedanddifferentsiteconfigurations.Notallcapacityfactorimprovementsaretheresultofturbinetechnologyimprovements,either.Thisisbecauseadvancesinremotesensingandcomputinghavefacilitatedimprovementsinwindresourcecharacterisationandthesitingofturbinestominimisewakelosses.Theseadvanceshaveenabledtheselectionofbetterwindsitesandbetterwindfarmlayoutsforoptimalenergyoutput.78RENEWABLEPOWERGENERATIONCOSTSIN2022DenmarkBrazilGermanyChinaSwedenIndiaUnitedStatesItalyTürkiyeUnitedKingdomSpainMexicoJapanCanadaFranceCapacityfactorFigure2.7Onshorewindweightedaveragecapacityfactorsfornewcapacityin15countries,1984-202279ONSHOREWINDFigure2.7depictsthehistoricalevolutionofonshorewindcapacityfactorsfornewlycommissionedprojects32ineachyearacrossthe15marketswhereIRENAhasthelongesttimeseriesdata.Thefigureshowsthataveragecapacityfactorsincreasedbyjustoverhalfforthe15countriesexamined.Granted,therearevaryingstartdatesforcommerciallydeployedprojects,butnonetheless,thisshowsthescaleofcapacityfactorimprovements.IntheUnitedStates,forexample,between1984–whentheearliestprojectwascommissioned–and2022,capacityfactorsincreased131%.Elsewhere,inCanada,China,DenmarkandtheUnitedKingdom,capacityfactorsincreasedbymorethan70%betweentheirearliestdeploymentdatesand2022.Brazil,liketheUnitedStates,hasexcellentonshorewindresources.In2021and2022,newlycommissionedprojectsinBrazilhadthehighestweightedaveragecapacityfactoramongthe15countriesexamined,at52%and50%,respectively.Table2.2showsmorerecentchangesincapacityfactorsforprojectscommissionedinthesame15countriesforthe2010to2022period.WiththeexceptionofMexico,allthecountriesexperiencedimprovementsintheirweightedaveragecapacityfactors.CanadaandTürkiyeexperiencedthelargestincreasesincapacityfactorsfornewlyinstalledprojects,increasingby47%and46%,respectively,overtheperiod2010to2022.Intotal,7ofthe15countriesshownsawanimprovementofatleast32%and10ofthe15showeda21%ormoreimprovement.Table2.2Country-specificaveragecapacityfactorsfornewonshorewind,2010,2021and2022201020212022%Brazil365250Canada324547China253635Denmark273939France263432Germany242828India253533Italy253333Japan242425Mexico403733Spain274332Sweden293735Türkiye263938UnitedKingdom304138UnitedStates334544Countrieswithdataonlyavailableforprojectscommissionedin2020.32Thecapacityfactorsfornewlycommissionedprojectsaretheex-antereportedlifetimecapacityfactorsexpectedbytheprojectdeveloper.Actualoutputwillvaryeachyeargiventherelativewindconditions,andtheoveralllifetimecapacityfactormaydifferfromtheanticipatedvalue.80RENEWABLEPOWERGENERATIONCOSTSIN2022Figure2.8showstheincreaseintheweightedaveragecapacityfactorofnewlycommissionedonshorewindfarmsinsmallermarkets,wheredeploymentisthinner.AlmostallcountriesinFigure2.8thathavereasonabletimeseriesdatashowedanincreasingtrendincapacityfactors,althoughthereareexceptionstothis(e.g.Australia,Ethiopia,GreeceandMorocco).However,theoverallcontributiontocapacityfactorincreasesoftechnologyimprovementsislikelytobeunderestimatedinmanycountries.ThetrendsincapacityfactorsinFigures2.7and2.8maskthefactthatmanymarketssawnewprojectssitedatlocationswithlower,poorerwindresourcesovertime.Figure2.9highlightsthesetrends,wheresufficientdatacouldbereliablycollected,byshowingthechangeintheweightedaveragecapacityfactorandestimatedwindresourceforindividualprojectsin2010and2020.Thefigureshowsthatthecountriesexaminedexperiencedanincreaseintheirweightedaveragecapacityfactorsfornewprojectscommissionedin2020comparedtothosein2010,despiteadeclineintheweightedaveragewindspeedoftheprojectsforwhichIRENAhasdata.33Thelatterdeclineinwindspeedfornewprojectscouldbeduetolessaccesstobetterwindresourcesinsomecountries.Insomemarkets,thedeclinemightalsobetheresultoftheimprovedeconomicsofonshorewindallowingforprojectsinareaswithlowerwindspeedsthatwerepreviouslyconsidereduneconomic.Theoveralltrendacrossthesemarketsconfirmsthattechnologyimprovements,includinglargerturbinesandlongerbladeswithhigherhubheights,contributedgreatlytoanincreaseintheglobalweightedaveragecapacityfactor.FinlandPeruPhilippinesPolandPortugalRepublicofKoreaCostaRicaCroatiaCyprusDominicanRepublicEgyptEthiopiaChileArgentinaAustraliaAustriaRussianFederationSouthAfricaUkraineUruguayVietNamCapacityfactorGreeceIndonesiaIrelandMoroccoNetherlandsNewZelandNorwayPakistanPanamaFigure2.8Onshorewindweightedaveragecapacityfactorsfornewprojectsinsmallermarketsbycountryandyear,2010-202233Theanalysisisbasedonthemeanwindspeedoftheprojectsite,takingintoaccounthubheights,fornewlycommissionedprojectsinthespecifiedyear.Itisnotananalysisofhowwindspeedsatagivenprojectsitehavechangedovertime.81ONSHOREWINDAmongtheninecountriesexaminedbelow,thehighestweightedaveragecapacityfactorincreasewasintheNetherlands,at73%,followedbyTürkiyeandJapan,whichsawincreasesof45%and44%,respectively.FranceandtheUnitedKingdombothshowedanincreaseof22%intheirweightedaveragecapacityfactors,whileCanadahadthelowestweightedaveragecapacityfactorincrease,atonly18%.Theresults,despitebeingforasubsetofnewprojects,suggestthattheincreaseincapacityfactorbetween2010and2020underestimatesthecontributionoftechnologyinnovationandimprovementsinincreasingwindfarmyields(IRENA,2022b).GermanySwedenUnitedKingdomCanadaFranceNetherlandsBrazilJapanTürkiye--------CapacityfactorWindspeedFigure2.9Changeintheweightedaveragecapacityfactorandwindspeedfornewprojectsbycountrybetween2010and2020Note:ThenumberofprojectsforwhichIRENAhassufficientdatatoperformtheanalysiscontainedinthisfigureisasubsetofthetotalprojectdata.Theresultsarethereforeindicative,andthepercentagechangesincapacityfactorinthisfigurearenotthesameastheannualweightedaveragecapacityfactorasreportedinFigure2.8.82RENEWABLEPOWERGENERATIONCOSTSIN2022OPERATIONANDMAINTENANCECOSTSO&Mcostsforonshorewindoftenmakeupasmuchas30%oftheLCOEforthistechnology(IRENA,2018).Technologyimprovements,greatercompetitionamongserviceproviders,andincreasedoperatorandserviceproviderexperienceare,however,drivingdownO&Mcosts.ThistrendisbeingsupportedbyincreasedeffortsbyturbineOEMstosecureservicecontracts,assuchagreementscanprovidehigherprofitmarginsthanthosefromturbinesupplyalone(BNEF,2020c;WoodMacKenzie,2019).Nonetheless,theshareoftheO&MmarketcoveredbyturbineOEMscontinuestoshrink,withassetownersincreasinglyinternalisingmajornumbersofO&Mservicesorusingindependentserviceproviderstoreducecosts.Figure2.10showsO&Mcostsinselectedcountries,alongwithBloombergNewEnergyFinance(BNEF)O&Mpriceindexes.Thelatterarerepresentedaseitherinitialfull-servicecontractsorfull-servicecontractsforalreadyestablishedwindfarms.Thelatteraremoreexpensivebecausetheyfactorintheageingofturbines.ThedatashowanobservabledownwardtrendinO&Mcoststhatreflectsthematurityandcompetitivenessofthemarket.Initialfull-servicecontractsfell75%between2010and2022,whilefull-servicerenewalcontractsdeclinedby38%between2011and2022.Atthecountrylevel,in2021,O&McostsforonshorewindrangedfromUSD30/kWperyearinDenmarktoUSD81/kWperyearinJapan,withGermany–acountryknownforhavinghigherthanaverageonshorewindO&McostsinEurope–ataroundUSD41/kWperyear.ThedifferencebetweenthecontractpricesandobservedcountryO&Mcostsisexplainedbytheadditional,predominantlyoperational,expensesnotcoveredbyservicecontracts(e.g.insurance,landleasepayments,localtaxesandotherfactors).Full-servicerenewalcontractsInitialfull-servicecontractsIrelandDenmarkBazilSwedenGermanyNorwayJapanUnitedStatesUSDkWyearFigure2.10Full-service(initialandrenewal)O&MpricingindexesandweightedaverageO&McostsinBrazil,Denmark,Germany,Ireland,Japan,Norway,SwedenandtheUnitedStates,2008-2022Source:BNEF,2020andIEAWind,2023.83ONSHOREWINDLEVELISEDCOSTOFELECTRICITYTheLCOEofanonshorewindfarmisdeterminedbythetotalinstalledcosts,lifetimecapacityfactor,O&Mcosts,theeconomiclifetimeoftheprojectandthecostofcapital.WhileallofthesefactorsareimportantindeterminingtheLCOEofaproject,somecomponentshavealargerimpactthanothers.Forinstance,thecostoftheturbine(includingthetowers)makesupthemostsignificantcomponentoftotalinstalledcostsinanonshorewindpowerproject.Withnofuelcosts,thecapacityfactorandcostofcapitalalsohaveasignificantimpactonLCOE.In2022,theO&Mcosts,comprisingfixedandvariablecomponents,typicallymadeupbetween10%and30%oftheLCOEforthemajorityofprojects.ReductionsinO&McostshavebeenincreasinglyimportantindrivingdownLCOEs,asturbinepricereductionsarecontributinglessinabsolutetermstocostreductions,giventheircurrentlowlevels.Figure2.11presentstheevolutionoftheLCOE(globalweightedaverageandprojectlevel)ofonshorewindbetween1984and2022.Overthatperiod,theglobalweightedaverageLCOEdeclinedby90%,fromUSD0.339/kWhtoUSD0.033/kWh.In2010,theLCOEwasUSD0.107/kWh,meaningtherewasa69%declineoverthedecadeto2022.Consequently,onshorewindnowincreasinglycompeteswithutility-scalesolarPVasthemostcompetitiverenewabletechnologywithoutfinancialsupport,dethroningthemorematurerenewablesourcesofbioenergy,geothermalandhydropower.FactorsbehindthedeclineintheglobalweightedaverageLCOEinclude:•Turbinetechnologyimprovements:Withtheincreaseinturbinesizesandsweptareas,theprocessofoptimisingtherotordiameterandturbineratings,i.e.thespecificpower,hasledtoincreasedenergyyieldandthusprojectviabilityfortheassetowner,dependingonsitecharacteristics.Inaddition,thepracticeofoptimisingthesiteconfigurationtobetterexploitwindresourcesandreduceoutputlossesduetoturbulencehasbecomemorecommonwithimprovedwindresourcecharacterisationandprojectdesignsoftware.Consequently,thishasincreasedenergyyields,reducedO&McostsperunitofcapacityanddrivendownLCOEs(Lantzetal.,2020).•Economiesofscale:Economiesofscalehavebeenactingintwodimensionsinonshorewind.Thefirsthasbeentoenablelargerproductionvolumesandregionalmanufacturinghubs,reducingcosts.Theyhavealsobeenworkingattheturbineandprojectscale.LargerprojectshelptoamortiseprojectdevelopmentcostsandO&Mcostswhilecreatinggreaterpurchasingpowerforallaspectsoftheproject.Meanwhile,largerturbineshelpreduceinstallation,giventhereductioninthenumberofturbinesrequiredforaprojectduetohigherturbineratings.•O&Mcosts:Digitaltechnologieshaveallowedforimproveddataanalyticsandautonomousinspections.Thishasbeenjoinedbyimprovementsinthereliabilityanddurabilityofnewturbines,whilelargerturbineshavereducedthenumberofturbinesforagivencapacity.ImprovedO&MpracticeshavealsocontributedtolowerO&Mcosts.Inaddition,moreplayershavebeenenteringtheO&Mservicingsectorforonshorewind,whichisincreasingcompetitionanddrivingdowncosts(BNEF,2019,2020a).84RENEWABLEPOWERGENERATIONCOSTSIN2022•Competitiveprocurement:Theshiftfromfeed-in-tariffsupportschemestocompetitiveauctionsisleadingtofurthercostreductions.Thisisbecausethisshiftdrivescompetitivenessacrossthesupplychain,fromdevelopmenttoO&Mandonbothalocalandglobalscale.Forturbinemanufacturers,thesupplychainhasalsomovedtosupportregionalhubsandcountries,minimisinglabouranddeliverycostsandfurtherimprovingcompetitiveness.Thegrowingmaturityoftheonshorewindmarket(cumulativedeploymentgrewby759GWbetween2000and2022)shouldalsonotbeoverlooked.Increasedoperationalexperienceandfavourablegovernmentregulationsandpolicieshavereducedprojectdevelopmentandoperationalrisksforonshorewind,especiallyinestablishedmarkets.Theserisksarenowbetterunderstood,withadequatemitigationmeasuresinplace.However,inmanymarkets,newchallengeshaveemergedthathavesloweddeploymentandraisedcostsabovewhattheyotherwisewouldhavebeen.InEurope,inparticular,permittingandenvironmentalapprovalsprocessesactasabreakontheaccelerationofdeploymentofonshorewind.WelcomeeffortstoaddresstheseissueshavebeensignalledinanumberofmarketsandbytheEuropeanCommission,butlittlehassofarbeenachieved.USDkWhCapacity(MW)≤≥Figure2.11LCOEofonshorewindprojectsandglobalweightedaverage,1984-202285ONSHOREWINDFigure2.12presentsthehistoricalevolutionoftheLCOEofonshorewindin15countrieswhereIRENAhasthelongesttimeseriesdata.Thesedatashouldbeinterpretedwithcare,however,ascross-countrycomparisonsareproblematicgiventhevariationinbaseyearsforeachcountryandfluctuationsinexchangerates.Havingnotedthis,amongthe15countriesanalysed,thebiggestLCOEreduction(92%)wasintheUnitedStates,whichalsohadthelargestreduction(78%)inaveragetotalinstalledcosts,whileitalsosawa131%improvementinitsaveragecapacityfactor.Swedenhadthenextlargestreductionat86%,followedbyIndia(85%),CanadaandtheUnitedKingdom(84%),andDenmark(83%).In2022,withtheexceptionofJapan,allthe15countriesanalysedinFigure2.12hadweightedaverageLCOEsbelowUSD0.055/kWh–wellbelowthelowerrangeforfossilfuel-firedpowergenerationatUSD0.069/kWh.BrazilChinaCanadaDenmarkGermanyFranceIndiaJapanItalyMexicoSwedenSpainTürkiyeUnitedStatesUnitedKingdomUSDkWhFigure2.12WeightedaverageLCOEofcommissionedonshorewindprojectsin15countries,1984-202286RENEWABLEPOWERGENERATIONCOSTSIN2022Table2.3showsthecountry/regionweightedaverageLCOEand5thand95thpercentilerangesbyregionin2010and2022.AllcountriesandregionsinTable2.3sawanincreaseintheircountry/regionweightedaverageLCOEofnewlycommissionedprojectsexceptAfrica,Brazil,China,NorthAmericaandOceania.In2022,thehighestweightedaverageLCOEforcommissionedprojectsbyregionwasUSD0.055/kWhintheOtherAsiacategory(e.g.excludingChinaandIndia),whileprojectscommissionedinBrazilandChinasawthelowestweightedaverageLCOEs,atUSD0.024/kWhandUSD0.027/kWh,respectively.ThehighestLCOEreductionsbetween2010and2022wereinBrazil,whichsawthemfallby79%(USD0.116/kWhtoUSD0.024/kWh).Oceaniahadthesecond-highestLCOEreductionforthesameperiod,at76%;NorthAmericahada73%reduction;andEuropehadareductionof67%.WindpowerprojectsareincreasinglyachievingLCOEsoflessthanUSD0.040/kWh,andinsomecases,aslowasUSD0.024/kWh.ThemostcompetitiveweightedaverageLCOEsbelowUSD0.050/kWhwereobservedacrossdifferentregions:inAsia(ChinaandIndia),Europe(SpainandSweden),Africa(Egypt),NorthAmerica(theUnitedStates)andSouthAmerica(ArgentinaandBrazil).ConsideringLCOErangesregionally,in2022,the5thand95thpercentilerangefortheglobalweightedaverageLCOEwasbetweenUSD0.017/kWhinBrazilandUSD0.145/kWhinOtherAsia,whichsawanalmostdoublinginits95thpercentilevaluebetween2021and2022.Table2.3RegionalweightedaverageLCOEandrangesforonshorewindin2010and2022201020225thpercentileWeightedaverage95thpercentile5thpercentileWeightedaverage95thpercentile(2022USD/kW)Africa0.0700.0730.0960.0440.0460.051CentralAmericaandtheCaribbean0.0960.0960.096Eurasia0.1350.1350.1350.0420.0520.071Europe0.0900.1370.2060.0290.0450.059NorthAmerica0.0700.1090.1480.0250.0290.047Oceania0.1210.1360.1480.0270.0330.042OtherAsia0.1130.1550.1690.0380.0550.145OtherSouthAmerica0.0960.1120.1450.0340.0530.063Brazil0.1160.1160.1160.0170.0240.030China0.0710.0870.1100.0240.0270.035India0.0600.0960.1190.0320.0370.04287ONSHOREWINDCostaRicaCroatiaCyprusDominicanRepublicEgyptEthiopiaChileArgentinaAustraliaAustriaPeruPhilippinesPolandPortugalRepublicofKoreaRussianFederationSouthAfricaUkraineUruguayVietNamUSDkWhFinlandGreeceIndonesiaIrelandMoroccoNetherlandsNewZelandNorwayPakistanPanamaFigure2.13OnshorewindweightedaverageLCOEinsmallermarketsbycountryandyear,2010-2022thelamephotographer©Shutterstock.comYANYINFUNG©Shutterstock.com03SOLARPHOTOVOLTAICS89HIGHLIGHTS•Theglobalweightedaveragelevelisedcostofelectricity(LCOE)ofutility-scalephotovoltaic(PV)plantsdeclinedby89%between2010and2022,fromUSD0.445/kilowatthour(kWh)toUSD0.049/kWh.In2022,theyear-on-yearreductionwas3%.•Atanindividualcountrylevel,theweightedaverageLCOEofutility-scalesolarPVdeclinedbybetween76%and89%between2010and2022.•ThecostofcrystallinesolarPVmodulessoldinEuropedeclinedby91%betweenDecember2009andDecember2022.•Theglobalcapacityweightedaveragetotalinstalledcostofprojectscommissionedin2022wasUSD876/kilowatt(kW),83%lowerthanin2010and4%lowerthanin2021.•SolarPVcapacitygrew26-foldbetween2010and2022,withover1047gigawatts(GW)installedbytheendof2022.•Onaverage,in2022,balanceofsystem(BoS)costs(excludinginverters)madeupabout62%oftotalinstalledcosts.•Theglobalweightedaveragecapacityfactorfornew,utility-scalesolarPVincreasedfrom13.8%in2010to16.9%in2022.Thischangeresultsfromthecombinedeffectofevolvinginverterloadratios,ashiftinaveragemarketirradianceandtheexpandeduseoftrackers–drivenlargelybyincreasedadoptionofbifacialtechnologies–thatunlocksolarPV’suseinmorelatitudes.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure3.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforPV,2010-202290RENEWABLEPOWERGENERATIONCOSTSIN2022RECENTMARKETTRENDSBytheendof2022,over1047GWofsolarPVsystemshadbeeninstalledglobally.Thisrepresentedalmost26-foldgrowthforthetechnologysince2010.Newlyinstalledsystemstotallingabout191GWwerecommissionedduring2022alone.Thisvalueis36%morethanin2021andrepresentsthegreatestyear-on-yearincreaseinyearlycommissionedcapacitysincethetechnologygrew50%between2015and2016.Thesenewcapacityadditionswerethehighestamongallrenewableenergytechnologiesthatyear.ThishasbeenthecaseforsolarPVsince2016.AsiahasbeentheleaderininstallingnewsolarPVsince2013.Followingthattrend,growthin2022wasdrivenbycontinuednewcapacityadditionsintheregion,whenAsiacontributedabout59%ofallnewinstallations.TheshareofnewinstallationsinAsiawas53%during2021and60%in2020.In2022,Chinadrovegrowthintheregion,accountingforaround77%ofallnewAsian(andabouta45%ofallglobal)installations.TotalexpansioninAsiawas112GWin2022(comparedto75GWin2021),andmajorcapacityincreasesoccurredinChina(86GW)andIndia(13.5GW).Japanalsoadded4.6GW,slightlymorethanin2021.HistoricalmarketsoutsideAsiaalsocontinuedtogainscale.TheUnitedStatesadded17.6GWofsolarcapacityin2022,Braziladded9.9GWandtheNetherlandsandGermanyadded7.7GWand7.2GW,respectively(IRENA,2023a).TOTALINSTALLEDCOSTSSolarPVmodulecosttrendsThedownwardtrendinsolarPVmodulecostshasbeenanimportantdriverofimprovedcompetitivenesshistorically–andthistechnologyhasshownthehighestlearningratesofallrenewableenergytechnologies.BetweenDecember2009andDecember2022,crystallinesiliconmodulepricesdeclinedbetween88%and94%formodulessoldinEurope,dependingonthetype.Theweightedaveragecostreductionwasontheorderof91%duringthatperiod.DuringDecember2022,mainstreammodulessoldforUSD0.33/watt(W).Awiderangeofcostsexists,however,dependingonthemoduletechnologyconsidered.CostsvariedfromaslowasUSD0.22/Wforthelower-costmodulestoashighasbetweenUSD0.43/WandUSD0.44/Wforhigh-efficiencymodules.Thelowerboundofthatcostrangeis2%higherthanitwasduringDecember2021,whiletheupperboundis8%lowerthanwhatitwasinDecember2021(Figure3.2).Accountingforabout5%ofthemarketin2022,thinfilmofferingssoldforUSD0.23/WduringDecember2022,afteracostdeclineof11%betweenDecember2021andDecember2022.Thecostofcrystallinebifacialmodulesincreased5%duringthesameperiod.Salesofbifacialcrystallinemoduleswere39%higherthanmainstreammonofacialmodulesduringDecember2020.ThiscostpremiumremainedunchangedduringDecember2021butfellto23%duringDecember2022.Thispointstobifacialmodulecostsbeingdrivenmorebythecostofthecellarchitecturetypesusedtobuildthemratherthanbythebifacialdesignitself.Drivenbythisnarrowingcostgapanditspotentialforincreasedyieldperwattwhencomparedtomonofacialtechnologies,bifacialmodulescontinuetogrowtheirmarketshare.During2019,themarketshareforthesewasabout8%.Thissharegrewtoaround27%during2020,to28%during2021andto30%during2022(ITRPV,2022,2023).91SOLARPHOTOVOLTAICSBetweenDecember2009andDecember2022,crystallinesiliconmodulepricesdeclinedbybetween88%and94%Afterseveralyearsofadownwardpricetrend,crystallinemodules’yearlyaveragepricebetween2020and2021increasedbetween4%and6%.However,between2021and2022,theincreasingtrendintheyearlyaveragemodulepricestartedtoreverse,withpricesforallblackandlow-costmodulesdecliningbetween3%and4%duringthatperiod.Bifacialmodulepricesfellbyatenthbetween2021and2022(afterhavingincreased4%thepreviousyear).High-efficiencymodulesexperienceda1%increasebetween2021and2022(afterhavingincreasedabout6%between2020and2021).Themainstreamcategoryincreased6%between2021and2022.Thiswassimilartotheincreaseexperiencedbetween2020and2021,indicatingthatthiscategorywasseeminglystillaffectedbysupplychaindisruptionsthatstartedduring2021andtheeffectsofhighermaterialcostsorloweravailabilitythathadpushedupprices.However,preliminarydataforthefirstquarterof2023showdeclinesinallmodulecategoriesthatrangebetween7%and9%,indicatingareturntoasustaineddownwardtrendformodulepricesacrosscategories(Box3.1).Thinﬁlma-Siu-SiorGlobalIndex(fromQ)ThinﬁlmCdsCdTeThinﬁlma-SiBifacialLowcostMainstreamHigheciencyAllblackCrystallineEurope(Germany)CrystallineChinaCrystallineJapanJanJanJanJanJanJanJanJanJanJanJanJanJanJanUSDWFigure3.2AveragemonthlysolarPVmodulepricesbytechnologyandmanufacturingcountrysoldinEurope,2010to2022Source:GlobalData(2023);pvXchange(2023);PhotonConsulting(2017);IRENARenewableCostDatabase.92RENEWABLEPOWERGENERATIONCOSTSIN2022Afteradecadeofcontinuousdecline,in2021,solarPVmodulepricesclimbedassupplychaindisruptionsledtohighermaterialcostsorloweravailability.TakingmodulessoldinEuropeasareference,thesedevelopmentsmeantthatthepriceofcrystallinesolarPVmodulesincreasedbetween4%and7%in2021comparedto2020,fromarangeofbetweenUSD0.20/Wand0.44/WtobetweenUSD0.22/WandUSD0.46/W.During2022thistrendstartedtoreverse.However,pricesformainstreammodulesaccountingforabout55%ofthemarketthatyear,climbedatparwiththeirincreaseinthepreviousyeartoreachUSD0.34/Wduring2022.Preliminarydataforthefirstquarterof2023showitreachingUSD0.31,avalueresemblingthepre-supplychaindisruptionseraof2022.Thereasonsforthepriceuptickthatstartedin2021arevaried,butasystemiccontributortothisincreasewastherisingpriceofpolysilicon.ChallengesrelatedtoavailablepolysiliconcapacityinChinapushedpolysiliconpricesfromaroundUSD12/kilogram(kg)atthebeginningof2021tooverUSD33/kgtowardstheendofthatyear,ascellmanufacturersracedtosecuresupplies,biddingupprices.Box3.1RecentuptickinsolarPVmodulecostsBifacialLowcostMainstreamHigheciencyAllblack(Q)------(Q)USDW-----USDW--------------------AveragePercentageincreaseFigureB3.1aAverageyearlysolarPVmodulepricesbytechnologysoldinEurope,2010to2021and2022Q1;average(left)andpercentageincrease(right)Source:GlobalData(2023);pvXchange(2023);PhotonConsulting(2017);WoodMackenzie2023,IRENARenewableCostDatabase.93SOLARPHOTOVOLTAICSPolysiliconpricesstartedstabilising,however,as2022progressed.Thishappenedduetoindustry-wideeffortstoscale-upproductionthroughmanufacturingcapacityexpansions.Furthertechnologyimprovementsinmanufacturinghavealsostartedtopayoff.Preliminarydataforthefirsthalfof2023showpolysiliconpricestradingatUSD23/kg(adeclineof35%comparedtotheaveragepriceofpolysiliconin2022).Thisseemsindicativeofareturntoalastingdownwardtrendinpricingthathasusuallymatchedanincreasingtrendinexcessmanufacturingcapacity(FigureB3.1b).USDkgDifferenceinUSDkgMovingaverageofexcesscapacity-H---USDkgDierenceinUSDkgfrompreviousyearyearmovingavergareofexcesscapacityFigureB3.1bPolysiliconpricingperkilogramme,percentchangeperyearandthree-yearmovingaverageofpolysiliconexcessmanufacturingcapacity,2003-H12023Basedon:Bernreuter(2022);PVInfoLink(2022);EnergyTrend(2022).VariousfactorsareexpectedtocontinuetocontributetoincreasingsolarPVtechnology’scompetitivenessinthelonger-term,thecontinuedimprovementofefficiency,manufacturingoptimisationanddesigninnovationareexpectedtomorethanoffsettherecenttemporarycostincrease.Anexampleofthisisthefurtheradoptionofbifacialtechnologiesbuiltfromincreasinglyefficientcells,whichisexpectedtocontinue.Theaveragemoduleefficiencyofcrystallinemodulesincreasedfrom14.7%in2010to20.9%in2021.During2022averagemoduleefficiencyofthattechnologyhasbeenreportedat21.1%(ITRPV,2023).Thatrisewasdrivenbyamarketshiftfrommulti-crystallinetomoreefficientmonocrystallineproducts,whilepassivatedemitterandrearcell(PERC)architecturesbecamestate-of-the-artmoduletechnology.94RENEWABLEPOWERGENERATIONCOSTSIN2022TheefficiencyofPERCmodules,however,isexpectedtogrowtowards22%inthenextfewyears,approachingitslimits.IntermsofcellarchitecturebeyondPERC,likelycandidatestodriveefficiencieshighertaketwomainapproaches:first,afocusonreducinglossesatcontacts(e.g.heterojunction[HJT]andtunneloxidepassivatedcontact[TOPCon]technology);orsecond,byfocusingonmovingmetallisationtotherearofthecelltoreducefront-sideshading(e.g.interdigitatedbackcontact[IBC]orcells).Yet,atthemoduledesignlevel–independentfromthecell–recentdevelopmentsintechnologyhavecontributedtoincreasingmodulepoweroutputs.Half-cutcells,multi-busbarsandhigh-densitycellpackingpathways,suchasshinglingandothers,areclearexamplesofthis.Thesetechnologiesarealsoexpectedtobeincreasinglyutilisedinthefuture.Untilrecently,theprevalentmoduledesignhasbeenbasedonsquare,orpseudo-square,crystallinesiliconcells.Thesehaveanapproximatesidelengthfrom156millimetres(mm)to159mmandarebasedonwaferformatsknownasM2andG1.Cellsaretypicallyconnectedinseriesusingmetallicribbon,solderedtothefrontbusbarsofonecellandtherearbusbars/solderingpadsoftheadjacentcells.Ascellshaveevolved,busbarshaveincreasedinnumberfrom2percellto4-8percellinmainstreamproduction.Withtheaimofmaximisingpoweroutput,thistypicalmoduledesignischangingrapidly.Alternativedesignswithvariantssuchashalf-cellmodules,shingledcellmodulesandmulti-busbarcells/modules(withasmanyas12thinnerbusbars)continuetomature.Newermodulesareincreasinglybasedonlargerwaferformats,andcurrentwafersizesarelikelytorapidlygivewaytolargerformatsof182mm(M10)to210mm(G12)insidelength.Thesetechnologicalchangeshavemeantthatthepoweroutputofmoduleshasseenimportantgrowthinrecentyears.Forexample,in2017,typicalmodulepoweroutputfortopmoduleswas350W,whilecurrently,500Wisthenewnorm,thoughmoduleswithoutputbeyond600Warealsoalreadycommercial.Giventhediversificationofmoduledesigns,however,apurecomparisonofmodulepowerratingaslabelledmaybemisleading,withtheefficiencyofthemodulesremainingthemostimportantperformancemetric(TaiyangNews2020,2021;ITRPV2022;Lin,2019).ThesustainabilityofthematerialsusedinsolarPVmodulesisgaininginimportanceasthemarketcontinuestogrowglobally.Technologicaldevelopmentsrelatedtothisarebecomingthefocusofmanyindustryefforts,particularlyinlieuofthe2021supplychainconstraintsandtherelatedsupply/demandimbalancesaffectingmanufacturingandshippingofsolarPVmodulesandothersystemcomponents.Polysiliconconsumptionreductionremainsasrelevantaseverinthiscontext,andindustryeffortscontinueinthisregard.Forexample,improvedwafersawingtechnologies,notablydiamondwiresawing(DWS),havetakenoverfromearlierslurry-basedwafersawing,contributingtoreducedpolysiliconuseinthewaferingstep.Theamountofpolysiliconlostduringcuttingthewafers(kerfloss)hasalsodeclined.During2021,kerflossvaluesof60micrometers(μm)werealreadytypical(adeclineofmorethan62%from2010).During2022theyhavebeenreportedbelowthatat57μm(adeclineofabout64%since2010).95SOLARPHOTOVOLTAICSBesidesthewaferitself,metallisationpastesthatcontainsilverhavebeenanimportantcostcomponentinthewafer-to-cellprocess.Giventherelativelyhighcostofsilverrecently,theindustryhasplacedsignificantfocusondifferentwaystoreducemetalconsumptionincells.Formono-facialp-typecells,totalsilverremaininginthecellsdeclinedfrom400milligrammes(mg)percellin2009to90mg/cellin2020–adeclineof80%.In2020,bifacialp-typecellshadslightlyhigherconsumption,at98mg/cell.Inn-typecells(HJTandTOPCon),silverisusedforfrontandfullrearsidemetallisation,leadingtosignificantlyhighersilverconsumptionthanintheirp-typecounterparts.Inmulti-busbardesigns,cellsgofromhaving3-5busbarstohavingtypically12muchthinnerbusbars.Inaddition,theflatribbontraditionallyusedforcellinterconnectionisreplacedbyroundwirewithanarrowerdiameter.Thisallowsreducedfingerwidth,potentiallyreducingsilverusage.During2021,totalsilverremaininginthecellsinabsolutemg/celltermsstayedflatcomparedto2020values.Suchconsumptiontranslatestoabout13.2mgofsilver/Watthecelllevel,assumingstandardPERCarchitecture.Industryexpectationsareforthisvaluetoreach7.5mg/Wwithinthenextdecade,whichcorrespondstoabout60mg/cell.Someprogresswasmadeduring2022.Themedian2022valuewasreportedat10mg/W(ITRPV,2023).Copperisstillenvisionedasametallisationsubstituteforsilver,buttechnicalchallengesremain.Thesearerelatedtoadhesion,withrapidadoptionnotexpected.Despitethis,newcopper-basedconceptskeepdeveloping(Zhanetal.,2021).Inaddition,increasedadoptionofbifacialtechnologyisanimportantdriverforsolarPVcompetitiveness,givenitspotentialtoprovidehigheryieldperwattthanmonofacialtechnologies.Bifacialcellsallowlighttoenterfromtherearofthecell,aswellasthefront.Therear-sideofbifacialcellsfeaturesmetallisationinagrid,similartothetraditionalfront-sidecellmetallisation.Bifacialcellsaretypicallyemployedinabifacialmodule,34inwhichtheopaquerearbacksheetisusuallyreplacedbyglass,toallowlighttoenterthemodulefromtherear.Lightenteringtherearofabifacialmodulecancontributetopowergenerationinmuchthesamewayaslightenteringthefront,althoughthebifacialityfactorformostmodules(theratioofrear-sideefficiencytofront-sideefficiency)hasbeenreportedintherangeof65%to95%(TaiyangNews,2018).Bifacialityisacharacteristicthatdependsonthestructureofcellsandmodules.The‘bifacialgain’,oroutputgainfromabifacialmodulecomparedtoamonofacialmodule,however,doesnotdependonlyonthebifacialityfactor.Italsodependsontheadditional,externalconditionsofthesysteminstallationtypeanditslocation,withthesefactorsaffectingtheangulardistributionoflightreachingtherearside.Amongthemostimportantfactorsare:moduleorientationandtiltangle;groundalbedo(theratiooflightreflected);moduleelevationrelativetotheground(alsoknownas‘levelaboveground’);moduleheight;thediffuseirradiancefractionandself-shading.Bifacialmodulesarebeingincreasinglyappliedinutility-scaleplantsthatusesingle-axistracking.TheirenergyyieldadvantageisbroadeningthelatituderangeofcompetitivetrackingPVplants.Themarketshareofbifacialmoduleswas30%during2022(ITRPV,2022,2023).34However,itisalsopossibletousebifacialcellsinconventionalopaque-backsheetedmonofacialpanels.96RENEWABLEPOWERGENERATIONCOSTSIN2022TotalinstalledcostsTheglobalcapacityweightedaveragetotalinstalledcostofutility-scaleprojectscommissionedin2022wasUSD876/kW(4%lowerthanin2021and83%lowerthanin2010).During2022,the5thand95thpercentilerangeforallprojectsfellwithinarangeofUSD569/kWtoUSD1878/kW.The95thpercentilevaluewas10%lowerthanin2021,whilethe5thpercentilevaluedeclinedby8%between2021and2022.Thelong-termreductiontrendinthiscostrangepointstowardscontinuedcoststructureimprovementsinanincreasingnumberofmarkets.Comparedto2010,the5thand95thpercentilevalueswere85%and77%lower,respectively(Figure3.3).Capacity(MW)≤≥USDkWthpercentilethpercentileweightedaverageFigure3.3TotalinstalledPVsystemcostbyprojectandweightedaverageforutility-scalesystems,2010-2022naraichal©Shutterstock.com97SOLARPHOTOVOLTAICSSolarPVtotalinstalledcostreductionsarerelatedtovariousfactors.Globally,modulecostsaccountedfor51%ofthetotalinstalledcostsreductionbetween2010and2022,whileinverterscontributedanother10%(FigureB3.2a).Asprojectdevelopersgainmoreexperienceandsupplychainstructurescontinuetodevelopinmoreandmoremarkets,decliningBoS35costshavefollowed.ThishasledtoanincreasednumberofmarketswherePVsystemsareachievingcompetitivecoststructures,withfallingglobalweightedaveragetotalinstalledcosts.Thisismoreevidentwhenlookingatthechangingdriversofcostreductionfortheperiodsof2010-2016and2016-2022separately(FigureB3.2b).Box3.2Driversofthedeclineinutility-scalesolarPVtotalinstalledcostsUSDkWShareofcostdecline------ModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOtherBoShardwareFigureB3.2aGlobalweightedaveragetotalinstalledcostsofutility-scalesolarPVsystemsandcostreductionsbysource,2010-2022USDkW------------ModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOhterBoShardwareModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOtherBoShardwareShareofcostdeclineFigureB3.2bGlobalweightedaveragetotalinstalledcostsofutility-scalesolarPVsystemsandcostreductionsbysource,2010-2016and2016-2022Note:Percentagefiguresmaynottotal100duetorounding.Note:Percentagefiguresmaynottotal100duetoroundingup.35SeeAnnexIforadescriptionofalltheBoScategoriesthataretrackedbyIRENA.98RENEWABLEPOWERGENERATIONCOSTSIN2022Overtheperiod2010-2022,costreductionsinthecountriesinFigure3.4forwhichdatastartin2010,rangedbetween76%(inGermany)toashighas89%(inIndia).TürkiyeUnitedKingdomUnitedStatesSpainItalyJapanFranceGermanyIndiaAustraliaChileChinaUSDkW-------Mexico--Netherlands--RepublicofKorea----Figure3.4Utility-scalesolarPVtotalinstalledcosttrendsinselectedcountries,2010-2022Whilemodulesandinverterstogetherwerebehind67%ofthetotalinstalledcostsreductionbetween2010and2016,theircontributionwaslesspronouncedbetween2016-2022,with37%ofthecostreductionbeingattributabletothesecategories.Inthefirstperiod,the‘otherBoShardware’categoryincreasedslightly(3%)asthiswasatimewheremarketsstartedtoexpandtonewgeographiesbeyondthehistoricalmarketsandsupplychainsforthiswerestilldeveloping.Inthesecondperiodofanalysis,however,itcontributedaboutaquarterofthetotalinstalledcostsreduction.Therestofthecategoriescontributed36%tothereductionbetween2016-2022together,jumpingto40%inthe2016-2022period.ThishighlightstheincreasingrelevanceofbalanceofsystemcostsinthecompetitivenessofsolarPVutility-scaleprojects.99SOLARPHOTOVOLTAICSBetween2021and2022,a41%solarPVmarketgrowthinChilecamewiththebythebiggestdecline(22%)outofthe15marketsdisplayed,astheChileanmarketsurpassedthe1GWnewcapacityadditionsforasecondyearinarow.SomethingverysimilaroccurredinTürkiye,with40%growthinnewsolarPVcapacityyear-on-yearconcurringatotalinstalledcostsbyafifthbetween2021and2022,afterthecountryalsosurpassedthe1GWofnetadditionsforthesecondconsecutiveyear.Mexico,JapanandChinasawtheirtotalinstalledcostincreasebetween3%and6%year-on-yearin2022,whileNetherlandssawanincreaseof12%asthesolarPVmarketdoubledin2022comparedtothepreviousyear.FranceGermanyandRepublicofKoreaallexperiencedtotalinstalledcostshikeofaboutathirdbetween2021and2022.ProjectswithverycompetitivecostsinIndialedtoweightedaveragetotalinstalledcostsofUSD640/kWin2022,avalue12%lowerthaninChina.Thisdifferentialwas7%during2021,9%during2020and28%during2019.ThisresultsfromChinesecostshavingdeclined19%between2019and2020andanother7%in2021,comparedto5%inIndiainboth2020and2021.Chinesetotalinstalledcostsincreased6%during2022comparedtoaslowercostupswingof2%inIndia.Japanesecostsremainthehighestamidstanenvironmentof5%marketgrowth.Themarket’ssupplychaindisruptionsduring2021,however,meantthattheyearlycostreductionrhythmsloweddown,comparedtopreviousyears.Despitethis,totalinstalledcostreductionsofbetween4%and11%stilloccurredin2021acrossallthemajorhistoricalmarkets,suchasChina,India,Japan,Korea,theUnitedStatesandGermany.Thiscomparestoabroader2020year-on-yeartotalinstalledcostdeclineofbetween5%and25%amongthesehistoricalmarkets.However,during2022theimpactofthesedisruptionwasmorenoticeableinsomemarkets.Thisledtoincreasedtotalinstalledcostsintherangeof2%to34%in8outofthe15marketsshowninFigure3.4.Despitethis,6ofthesemarketssawtheircostsdeclineinarangeofbetween4%and22%,whilecostsintheUKremainedflatyear-on-year.AlyoshinE©Shutterstock.com100RENEWABLEPOWERGENERATIONCOSTSIN2022Figure3.5expandstheanalysisoftheevolutionofthetotalinstalledcosttocoverthelargest20globalmarketsmeasurebytheirnewlyinstalledutility-scalecapacityduring2022.Itfocusesonthechangebetween2021and2022.Becauseitgroupsthosemarketsbytheirregion,itmakesitmorevisiblethatapartfromSpain,allmajorEuropeanmarketshaveexperiencedtotalinstalledcostssurgesrangingfrombetween12%intheNetherlandstoashighas51%inGreece.AtthesametimemajorAsianmarketssawtheirtotalinstalledcostincreasebybetween2%and6%,exceptforRepublicofKoreawherethecostincreasewasmoreatparwiththeEuropeanmarkets.Intotal11outofthe20toputility-scalemarketsin2022sawtheirtotalinstalledcostsrise.MajorPVmarketsintheMiddleEastsawthegreatestcostreductions.IntheUnitedArabEmirates,a62%reductionyear-on-yearonthebackofverycompetitiveprojectscomingonline,ledtoweightedaveragetotalinstalledcostsofUSD578/kWin2022,avalue10%lowerthaninIndia.Costsinothermajorglobalmarketsacrosstheotherregionsdeclinedaswell.WhilesolarPVhasbecomeamaturetechnology,regionalcostvariationsdopersist(Figure3.6).Thesedifferencesremainnotonlyforthemoduleandinvertercostcomponents,butalsofortheBoS.36ThereasonsforBoScostreductionsrelatetocompetitivepressuresandincreasedinstallerexperience,whichhasledtoimprovedinstallationprocessesandsoftdevelopmentcosts.BoScoststhatdeclineproportionallywiththeareaoftheplanthavealsodeclinedasmoduleefficiencieshaveincreased.36BoScostsinthischapterdonotincludeinvertercosts,whicharetreatedseparately.USDkW----------AsiaChinaIndiaJapanRepublicofKoreaTürkiyeGermanyDenmarkSpainFranceGreeceNetherlandsPolandUnitedArabEmiratesSaudiArabiaCanadaMexicoUnitedStatesAustraliaBrazilChileEurasiaEuropeMiddleEastNorthAmericaOceaniaSouthAmericaFigure3.5Utility-scalesolarPVtotalinstalledcosttrendsintop20utility-scalemarkets,2021-2022101SOLARPHOTOVOLTAICSIn2022,thecountryaverageforthetotalinstalledcostsofutility-scalesolarPVforthecountriesreportedinFigure3.5rangedfromalowofUSD640/kWinIndiatoahighofUSD1905/kWinJapan.During2019,thehighestcostaveragewasabout3.5timesmorethanthelowest,whereasin2020thisratiodeclinedtoabout3.2.Thisdownwardtrendcontinuedin2021,reaching2.9.Theratiowas3.0in2022.Thispointstotherecentconvergenceofinstalledcostsinmajormarkets.ModulesHardwareInstallationSoftcostsInvertersRackingandmountingGridconnectionCabling/wiringSafetyandsecurityMonitoringandcontrolMarginFinancingcostsSystemdesignPermittingIncentiveapplicationCustomeracquisitionMechanicalinstallationElectricalinstallationInspectionRussianFederationJapanIndonesiaSouthAfricaCyprusCroatiaCanadaPolandSloveniaArgentinaPortugalHungaryNetherlandsIrelandChileEstoniaBrazilUnitedKingdomMexicoAustraliaUnitedStatesSaudiArabiaFranceTürkiyeGermanyAustriaRomaniaGreeceBulgariaSpainItalyDenmarkChinaIndiaUSDkWFigure3.6Detailedbreakdownofutility-scalesolarPVtotalinstalledcostsbycountry,2022102RENEWABLEPOWERGENERATIONCOSTSIN2022During2016,BoScosts(excludinginverters)madeupabouthalfofthetotalsystemcost.Thisvaluehastendedtoincreaseinrecentyears,highlightingtheincreasingimportanceofBoScostsasmoduleandinvertercostscontinuedtofall.Between2018and2020,theBoSsharehoveredbetween62%and64%,onaverage,inthemarketsassessedinFigure3.5.Alsoonaverage,in2021,BoScosts(excludinginverters)madeupabout57%oftotalsystemcostsinthecountriesinFigure3.5inlastyear’seditionofthisreport.Thislowervaluewasdrivenbyincreasingsolarmodulecosts.In2021,totalBoScostsrangedfromalowof42%inAustriatoahighof76%intheRussianFederation.Overall,softcostcategoriesforthecountriesevaluatedmadeup30%oftotalBoScostsand,onaverage,17%ofthetotalinstalledcostsduring2021.In2022,theBoSshareoftotalinstalledcostsrangedbetween53%inEstoniato75%inIreland.Onaverage,thecountriesdepictedinFigure3.6hadaBoSshareof63%.37Conversely,inFigure3.6,modulesandinverterstogether(non-BoScosts)rangedfromUSD226/kWtoUSD713/kW,withtheirsharerangingfrom25%and47%.Theaverageshareforthatcategorywas37%.BoShardwarecomponentsmadeupbetween11%and32%oftotalinstalledcostsduring2022,withanaverageshareof23%(equivalenttoUSD236/kW).Therangeofinstallationcostsisthebroadestamongallcostcategories,constitutingbetween8%and47%ofcostsand19%onaverage(USD205/kW).Abetterunderstandingofcostcomponentdifferencesamongindividualmarketsiscrucialtounderstandinghowtounlockfurthercostreductionpotential.Obtainingcomparablecostbreakdowndata,however,isoftenchallenging.Thedifficultiesrelatetodifferencesinthescale,activityanddataavailabilityofmarkets.Despitethis,IRENAhasexpandeditscoverageofthistypeofdata,collectingprimarycostbreakdowninformationforadditionalutility-scalemarkets.AdoptingpoliciesthatcanbringdownBoS,andsoftcostsinparticular,providesanopportunitytoimprovecoststructurestowardsbestpracticelevels.Reducingtheadministrativehurdlesassociatedwiththepermitorconnectionapplicationprocessisagoodexampleofapolicythatcanunlockcostreductionopportunities.Asmarketscontinuetomature,itisexpectedthatsomeofthecostdifferencesamongthemwilltendtodecline.Totrackthesemarkets’development–andtobeabletodevisetargetedpolicychangesthataddressoutstandingissuesproperly–adetailedunderstandingofindividualcostcomponentsremainsessential,however.37IRENAestimatesaglobalcapacityweightedaverageBoSshareof62%fortheutility-scalesolarPVmarketduring2022.Between2018and2022countriessawanaveragereductionof43%insoftcosts,a36%reductioninmoduleandinvertercosts,a28%reductioninBoShardwarecostsanda7%fallininstallationcosts.103SOLARPHOTOVOLTAICSRussianFederationIndonesiaSouthAfricaCanadaArgentinaBrazilUnitedKingdomMexicoJapanAustraliaUnitedStatesSaudiArabiaFranceTürkiyeGermanyItalyChinaIndiaModuleandinverterBoShardwareInstallationSoftcostsUSDkWUSDkW≥ModuleandinverterModuleandinverterBoShardwareBoShardwareInstallationInstallationSoftcostsSoftcostsFigure3.7Breakdownofutility-scalesolarPVtotalinstalledcostsbycountry,2018and2022AnanalysisofthetimeseriesforhistoricalmarketshighlightstheBoScosttrendbycategorybetween2018and2022(Figure3.7).Between2018and2022,thecountriesinFigure3.7experiencedanaveragereductionof36%forthemoduleandinvertercategory,shiftingfrombetweenUSD378/kWandUSD1010/kWtoarangeofbetweenUSD226/kWandUSD713/kW.TheBoShardwarecostsdeclined28%onaverageduringthatperiod,withtherangeofcostsdecliningfrombetweenUSD139/kWandUSD417/kWin2018toarangeofbetweenUSD117/kWandUSD417/kW.Installationcostsdeclinedthelowest,withanaveragereductionof7%,withtherangemovingfrombetweenUSD43/kWandUSD794/kWin2018toUSD86/kWandUSD890/kWin2022,as6outof18marketsexperiencedincreasinginstallationcosts.Softcosts,ontheotherhand,declinedthemost.TheirrangefellfrombetweenUSD208/kWandUSD867/kWin2018tobetweenUSD99/kWandUSD450/kWin2022.TheaveragesoftcostreductionforthemarketsinFigure3.6was43%.During2018,theBoSshareinthemarketsinFigure3.7rangedbetween47%and75%,whileitrangedbetween54%and75%in2022.TheaverageBoSshareinthosemarketsincreasedslightlyfrom62%in2018to63%in2022.104RENEWABLEPOWERGENERATIONCOSTSIN2022CAPACITYFACTORSByyearcommissioned,theglobalweightedaveragecapacityfactor38fornewutility-scalesolarPVincreasedfrom13.8%in2010to17.2%in2021.In2022thatvaluewas16.9%(a2%relativedecline).Between2010and2018,thecapacityfactorshowedanincreasingtrend,reachingitshighestvaluesofarat17.9%.Thiswaspredominantlydrivenbytheincreasedshareofdeploymentinsunnierlocations.Afterthat,thegrowthtrendthenreversed.ThiswasinturnfollowedbyarecentupticklikelyrelatedtoevolutioninthetechnologythathasunlockedwaysofharnessingmoresolarPVpowerfromagivensolarresource.Inthisregard,therehasbeenanotabletrendtowardshigheradoptionofbifacialtechnologyandincreaseduseoftrackersinutility-scalesolarplants.Thedevelopmentoftheglobalweightedaveragecapacityfactorisaresultofmultipleelementsworkingatthesametime,however.Highercapacityfactorsinpreviousyearshavebeendrivenbyelementssuchastheshiftindeploymenttoregionswithhigherirradiation,theincreaseduseoftrackingdevicesintheutility-scalesegmentinlargemarkets,andarangeofotherfactorsthathavemadeasmallercontribution(e.g.areductioninsystemlosses).From2018to2020,the95thpercentilevalueofthecapacityfactordeclinedsignificantly,from26.9%to20.8%,beforeincreasingto21.3%in2021.Itagaindeclinedto20.5%in2022(avaluesimilarto2020).The5thpercentilevaluedeclinedlessstarkly,from12.4%in2018to9.9%in2020,beforegrowingto10.8%in2021–aFigureveryclosetoits2019value.Itdeclinedslightlyin2022to10.3%(Table3.1).38ThecapacityfactorforPVinthischapterisreportedasanAC/DCvalue.Forothertechnologiesinthisreport,thecapacityfactorsareexpressedinAC-to-ACterms.MoredetailedexplanationsofthiscanbefoundinBolingerandWeaver(2014)andBolingeretal.(2015).Table3.1Globalweightedaveragecapacityfactorsforutility-scalePVsystemsbyyearofcommissioning,2010-2022Year5thpercentileWeightedaverage95thpercentile201011.0%13.8%23.0%201110.1%15.3%26.0%201210.5%15.1%25.6%201311.9%16.4%23.0%201410.8%16.6%24.4%201510.8%16.5%29.0%201610.7%16.7%25.9%201711.5%17.6%27.0%201812.4%17.9%26.9%201910.7%17.5%23.9%20209.9%16.1%20.8%202110.8%17.2%21.3%202210.3%16.9%20.5%Note:Thesecapacityfactorsarethealternatingcurrent(AC)-to-directcurrent(DC)capacityfactors,giventhatinstalledcostdatainthisreportforsolarPV(only)areexpressedasperkilowattDC.105SOLARPHOTOVOLTAICS39SeeAnnexIformoredetailonO&Mcostassumptions.Theglobalweightedaveragecapacityfactortrendisaresultofvariousconcurringandoftencompetingdrivers.Theseincludetheincreaseduseoftracking,projectlocation,thesolarresourceandtheincreasedmarketpresenceofbifacialmodules,aswellastheevolutionoftheinverterloadingratio(ILR).Theseconcurringfactors,however,oftendevelopdifferentlybymarketandcanthereforehaveavaryingimpactontheweightedaveragecapacityfactor(IRENA,2022).OPERATIONANDMAINTENANCECOSTSTheoperationandmaintenance(O&M)costsofutility-scalesolarPVplantshavedeclinedinthelastdecade,drivenbymoduleefficiencyimprovementsthathavereducedthesurfacearearequiredforeveryMWofcapacity.Atthesametime,competitivepressuresandimprovementsinthereliabilityofthetechnologyhaveresultedinsystemdesignsthatareoptimisedtoreduceO&Mcosts.Inaddition,improvedstrategiesthattakeadvantageofarangeofinnovationshavealsodrivendownO&Mcostsandreduceddowntime.Suchinnovationsstretchfromroboticcleaningtobigdataanalysisofperformancetoidentifyissuesandinitiatepreventativeinterventionsaheadoffailures.IntheUnitedStates,thecumulativeO&Mcostsofafleetof90projectstotalling3964MWacdeclined58%between2011and2021,fromUSD31/kW/yeartoUSD13/kW/year(Bolingeretal.,2022).Fortheperiod2018to2020,O&Mcostestimatesforutility-scaleplantsintheUnitedStateshavebeenreportedatbetweenUSD11/kW/yearandUSD20/kW/year(Bolingeretal.,2022).RecentcostsintheUnitedStatesaredominatedbypreventivemaintenanceandmodulecleaning,withthesemakingup75%to90%ofthetotal,dependingonthesystemtypeandconfiguration.TherestoftheO&Mcostscanbeattributedtounscheduledmaintenance,landleasecostsandothercomponentreplacementcosts.Recently,averageutility-scaleO&McostsinEuropehavebeenreportedatUSD10/kWperyear(Steffenetal.,2020;Vartiainenetal.,2019),withhistoricaldataforGermanysuggestingO&Mcostscamedown85%between2005and2017toUSD9/kWperyear.Thisresultsuggeststherehasbeenareductionofbetween15.7%and18.2%witheverydoublingofthesolarPVcumulativeinstalledcapacity.For2021,projectsintheIRENARenewableCostDatabasehadacapacityweightedaverageutility-scaleO&McostofUSD14.1/kWperyear(adeclineof48%from2010).During2022,thecapacityweightedaverageutility-scaleO&Mcostdeclined6%year-on-yeartoreachUSD13.2/kWperyear(adeclineof51%from2010).39Thesearetheestimatedtotalall-inO&Mcosts,includingitemssuchasinsuranceandassetmanagementthataresometimesnotreportedinallO&Msurveys.106RENEWABLEPOWERGENERATIONCOSTSIN2022GiventheescalatingimportanceofO&Mcosts,increasingthecountrygranularityofthesemetricsinthecalculationoftheLCOE40canbebeneficialformoreatimelyandpreciseinformingofmarkets.Challengesinobtainingtotalall-inO&Mcostsdata(anditsbreakdownbymaincostcategories)remainprevalent.However,IRENAhasmovedastepinthisdirectionbysurveyingasampleof110utility-scaleprojectscommissionedbetween2020and2022totallingabout7.5GWofcapacity.Apreliminaryanalysisoftheseisincludedhereforinformation;however,theresultsdidnotarriveintimetobeintegratedintotheO&Mdatabase.Thedatadoes,however,provideinterestinginsightsbyhighlightingthedifferencesbycountryinthesample(Figures3.8).MedianUSDkWyearTechnicaloperationInsurancePreventivemaintenanceCommercialoperationCorrectivemaintenanceGreenkeepingSecurityPanelcleaningOtherTotalO&McostFigure3.8Surveyresultsforthemedianall-inO&Mcostsforutility-scalesolarPVbycostcategoryandcountry,2020-2022ThepreliminaryresultsshowaninnerfencerangeofbetweenUSD6.3/kWperyearandUSD9.2/kWperyear.ThemedianforthesampleaggregatingallcountriesisUSD7.7/kW.Asisthecaseforthetotalinstalledcostsmetric,O&Mcostsshowawidespanacrossmarkets.InthesamplethisrangespansfromUSD3.4/kWperyearinChinatoUSD13.4/kWperyearinJapan.40Inthisreport,IRENAhasassumedUSD18.2/kWperyear(forOECDcountries)andUSD9.2/kWperyear(fornon-OECD)asaninputfortheLCOEcalculationofprojectscommissionedin2022.107SOLARPHOTOVOLTAICSLookingattheindividualcostcategories,technicaloperation,insurancesandpreventivemaintenancemakeupabout83%ofthetotalO&Mcosts.AregionalperspectiverevealsthatthelowestO&McostscanbefoundinAsia,withasurveymedianvalueofUSD3.6/kWperyearintheregion(Figure3.9).NorthAmericashowsthehighestO&Mcostsinthesurvey,atUSD9.1/kWperyear.ThesurveymedianvaluesforEuropewereUSD8.4/kWperyear.CostsinEurasiawereUSD6.6/kWperyear(avalue27%lower).SurveyresultsforSouthAmericaandOceaniaareveryclosetothemedianregionalvalueofUSD7.4/kWperyear.FutureeditionsofthisreportwillaimtoincludemoregranularityintotheLCOEcalculationofutility-scalesolarPVprojectsasdataavailabilitypermits.MedianUSDkWyearTechnicaloperationInsurancePreventivemaintenanceCommercialoperationCorrectivemaintenanceGreenkeepingSecurityPanelcleaningOtherTotalO&McostEurasiaEuropeAsiaNorthAmericaOceaniaSouthAmericaFigure3.9Surveyresultsforthemedianall-inO&Mcostsforutility-scalesolarPVbycostcategoryandregion,2020-2022108RENEWABLEPOWERGENERATIONCOSTSIN2022LEVELISEDCOSTOFELECTRICITYTheglobalweightedaverageLCOEofutility-scalePVplantsdeclinedby89%between2010and2022fromUSD0.445/kWhtoUSD0.049/kWh.This2022estimatealsorepresentsa3%year-on-yeardeclinefrom2021(thedeclinebetween2020and2021was13%).Globally,too,therangeofLCOEcostscontinuestonarrow.In2021,the5thand95thpercentileofprojectsrangedfromUSD0.031/kWhtoUSD0.127/kWh.In2022,therangeforthismetricwasbetweenUSD0.030/kWhtoUSD0.120/kWh,representing87%and78%declinesonthe5thand95thpercentilevalues,respectively,in2010.TheLCOErangein2022(thegapbetweenthe5thandthe95thpercentilevalues)reacheditslowestvalueinsince2010,afterdeclining6%since2021.Afterremainingflatduring2018and2019,the5thpercentilevaluedeclined17%between2019and2020toreachUSD0.040/kWh.Between2020and2021,thedeclinewasmuchstarker,at24%.Itdeclined3%during2022.In2020,the95thpercentilevalueremainedflatinrelationtoitsvaluein2019butdeclined26%between2020and2021.The95thpercentilevaluedeclined6%between2020and2021(Figure3.10).Therapiddeclineintotalinstalledcosts,increasingcapacityfactorsandfallingO&McosthavecontributedtoaremarkablereductioninthecostofelectricityfromsolarPVanditsimprovingeconomiccompetitiveness(seeBox3.3).Capacity(MW)≥weightedaverageUSDkWhthpercentilethpercentileFigure3.10Globalutility-scalesolarPVprojectLCOEandrange,2010-2022109SOLARPHOTOVOLTAICSTheremarkable,sustainedanddramaticdeclineinthecostofelectricityfromutility-scalesolarPVisoneofthemorecompellingstoriesinthepowergenerationsector’sevolutionoverthepastdecade.Since2010,thesolarPVindustryhasseenavarietyoftechnologicaldevelopmentsthathavecontributedtoimprovementsinthecompetitivenessofthetechnology.ThesehaveoccurredalongthewholesolarPVvaluechain.Fromtheincreaseddeploymentoflargerpolysiliconfactoriesandimprovedingotgrowthmethodstotheincreasedascendancyofdiamondwaferingmethodsandtheemergenceanddominanceofnewercellarchitecturesandlargerwafersizes,thePVindustryisconstantlyseeinginnovationsthatunlockLCOEreductions.TherapiddeclineinsolarPVmodulecostshasledtotheemergenceofnewPVmarketsaroundtheglobe.Between2010and2022,thecostdeclinesduetothemodulesalonecontributed45%totheLCOEreductionofutility-scalePV,whileinverterscontributedanother9%(FigureB3.3a).Thecostsofotherhardwarecomponentshavealsodeclinedduringtheperiod.Indeed,takentogether,rackingandmountingandotherBoShardwarecontributedanother10%totheLCOEreductionduringthe2010to2022period.AssolarPVtechnologyhasmatured,therelevanceofBoScostshasalsoincreased.Thisisbecausemoduleandinvertercostshavehistoricallydecreasedatahigherratethannon-modulecosts,increasingtheshareoftotalinstalledcoststakenbyBoS(IRENA,2018).Engineering,procurementandconstruction(EPC),installation,anddevelopmentcosts,whencombinedwithothersoftcosts,wereresponsiblefor26%oftheLCOEdeclineoverthe2010to2022period.Therestofthereductioncanbeattributedtoimprovedfinancingconditionsasmarketshavematured,reducedO&Mcosts,andanincreasedglobalweightedaveragecapacityfactor,drivenbyashifttosunniermarkets,between2010and2013.Therestofthereductioncanbeattributedtoimprovedfinancingconditionsasmarketshavematured,reducedO&Mcostsandanincreasedglobalweightedaveragecapacityfactor,drivenbyashifttosunniermarkets,between2010and2013.LookingattwoperiodsseparatelyillustratesthedynamicnatureofthedriversfortheLCOEofutility-scalesolarPV.TheglobalweightedaverageLCOEofutility-scalePVplantsdeclinedby75%between2010and2016,fromUSD0.445/kWhtoUSD0.113/kWh.Box3.3Unpackingthedeclineinutility-scalesolarPV'sLCOEfrom2010to2022USDkWh---------ModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOtherBoShardwareWACCAll-inO&MCapacityfactorShareofcostdeclineFigureB3.3aDriversofthedeclineoftheglobalweightedaverageLCOEofutility-scalesolarPV,2010-2022Note:Percentagefiguresmaynottotal100duetoroundingup.WACC=weightedaveragecostofcapital.110RENEWABLEPOWERGENERATIONCOSTSIN2022Thisfallwasdrivenheavilybymoduleandinvertercosts,whichtogetherwereresponsiblefor55%ofthedecline(FigureB3.3b).Between2010and2013,BoScosts(excludingtheinverter)accountedfor26%ofthereduction.Therestofthereductionforthatperiodcamefrombetterfinancingconditionsasthetechnologyriskperceptionstartedtodeclineinmajormarkets,O&Mcostsbecamemorecompetitiveandglobalweighted-capacityfactorsincreasedasprojectswereincreasinglybeingbuiltinmarketswithimprovingsolarresources.Between2016and2022,thechangingdynamicsintheglobalmarketscausedaverydifferentpicturetoemergewhenanalysingthesamedrivers.ModulecostscontinuedtodeclineduringthisperiodandremainedthesinglehighestcontributortotheLCOEdecline.However,moduleandinvertercoststogetheraccountedfor31%ofthetotalLCOEdeclinebetween2016-2022(comparedto55%between2010and2016).ThesecondmajorsinglecontributioninthesecondperiodcamefromotherBoShardware,whichaccountedforafifthoftheLCOEfall.Thiscategoryhadincreasedslightly(3%)inthefirstperiodofanalysis.TherestoftheBoScategoriesaccountedforanotherthirdoftheLCOEreductionbetween2016and2022.Intotalforthatperiod,BoScosts(excludingtheinverter)accountedfor53%oftheLCOEdecline(abouttwiceasmuchasbetween2010and2016).Between2016and2022,thecapacityfactor’sroledeclinedto1%(inspiteofsometechnologicalshifts)becausetheavailablesolarresourcestoprojectsdidnotchangeasdrasticallyasbetween2010and2016.However,theincreasingroleoftheweightedaveragecostofcapitalasadriverofLCOEreductionsisveryvisibleinthissecondperiod.Between2016and2022,improvedfinancingconditionswereresponsibleforabout13%oftheLCOEdeclineduringthatperiod(adoublingofthatcontributionfromthefirstperiodofanalysis).Thecostofcapital(CoC)forrenewablepowergenerationtechnologiesisamajordeterminantofthecostofelectricityfromrenewablepowergenerationtechnologies.BothreliabledataandadeepunderstandingofthecompositionoftheCoCanditsdriversarethereforecriticalinformation.Forinstance,forarepresentativesolarPVprojectoronshorewindproject,thetotalcostofelectricityincreasesby80%iftheCoCis10%ratherthan2%.IRENAhasrecognisedtheneedforimprovedCoCdataforsometime,givenfallingborrowingcostsandthegrowingmaturityofsolarandwindpowertechnologies.IRENA’srecentreport,Thecostoffinancingforrenewablepower,presentsnewCoCdataobtainedfromanexpertsurveyandinterviewscoveringallmajorregionsforonshorewind,offshorewindandsolarPV.Thecoverageofthissurveyisrichingeographicalandtechnologicalbreadth;assuch,theresultsmayrepresentthemostwide-rangingdatabaseonrenewableenergyfinancingavailabletoday(IRENA,2023b).--------------ModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOtherBoShardwareAll-inO&MCapacityfactorAll-inO&MWACCWACCCapacityfactorModuleOthersoftcostInstallationEPCdevelopmentInverterRackingandmountingOtherBoShardwareUSDkWh-----ShareofcostdeclineFigureB3.3bSourceofthedeclineintheglobalweightedaverageLCOEofutility-scalesolarPVintwoperiods,2010-2016and2016-2022Note:Percentagefiguresmaynottotal100duetoroundingup.111SOLARPHOTOVOLTAICSThedownwardtrendintheLCOEofutility-scalesolarPVbycountryispresentedinFigure3.11.Init,analysisofmarketswherehistoricaldataareavailablefrom2010showsthatbetween2010and2022,theweightedaverageLCOEofutility-scalesolarPVdeclinedbybetween75%and91%,dependingonthecountry.AmongthehistoricalmarketsshowninFigure3.11,thelowestweightedaverageLCOEintheutility-scalesectorin2022couldbeobservedinChinaandIndia.Between2010and2022,costsinChinadeclinedby89%,whileinIndiatheydeclinedby90%toreachUSD0.037/kWhinbothmarkets–avalueone-quarterlowerthantheglobalweightedaverageforthatyear,asreportedinFigure3.10.---Netherlands-RepublicofKorea----Mexico-------TürkiyeUnitedKingdomUnitedStatesUnitedStatesItalyJapanFranceGermanyIndiaAustraliaChileChinaUSDkWhFigure3.11Utility-scalesolarPVweightedaveragecostofelectricityinselectedcountries,2010-2022112RENEWABLEPOWERGENERATIONCOSTSIN2022Figure3.11alsoshowsthatcostsinAustraliawerethethirdmostcompetitiveamonghistoricalmarkets,atUSD0.041/kWh(9%aboveChina),aftera9%year-on-yeardecline.TheLCOEofprojectsinChilealsodeclined9%year-on-year,withprojectsreachingUSD0.042/kWhin2022.Spainreachedasimilarlycompetitivelevel,atUSD0.046/kWh,afteran8%increaseintheLCOEestimatebetween2021and2022.ThissetstheSpanishmarketbacktothereductionrhythmithadbetween2019and2020(afterhavingexperienceda4%hikeinLCOEbetween2020and2021).TheLCOEofutility-scalePVintheUnitedStatesdeclined1%year-on-yeartoreachUSD0.058/kWhduring2022(17%abovetheglobalweightedaverage).During2021,theLCOEvalueinJapandeclined17%comparedto2020toreachUSD0.092/kWh.However,theLCOEvalueincreased5%between2021and2022,andtheLCOEofutility-scalesolarPVinJapanwasaround2.6timesthatofChina(aratiothatremainedalmostunchangedfrom2019).Figure3.12examinestheweightedaverageLCOEtrendforthetop20utility-scalemarketsbetween2021and2022.Itshowsthatin8ofthese20markets,costsdeclined.MajorLCOEreductionsoccurredinthetopmarketsintheMiddleEast,wheretheimpactoflowertotalinstalledcostsisamplifiedbytheexcellentsolarresources.ThishasledtheregiontohavethemostcompetitivesolarPVcostsglobally,with2022LCOEvaluesintheUnitedArabEmiratesandSaudiArabiathatare63%and30%,respectively,lowerthanin2021.During2022,theLCOEofprojectsintheUnitedArabEmiratesdeclined63%year-on-yeartoreachUSD0.026/kWh.InSaudiArabia,itfell30%fromitsvaluein2021toreachUSD0.036/kWhin2022.Thesevaluesare31%and3%lower,respectively,thantheLCOE2022valueinChina.Meanwhile,sixoftheeighttopEuropeanmarketssawutility-scalesolarPVelectricitycostsrisebetween9%(Netherlands)and45%(Denmark).USDkWh------AsiaChinaIndiaJapanRepublicofKoreaTürkiyeCanadaMexicoUnitedStatesAustraliaBrazilChileEurasiaEuropeMiddleEastNorthAmericaOceaniaSouthAmericaDenmarkFranceNetherlandsGermany-SpainGreecePoland-UnitedArabEmirates-SaudiArabiaFigure3.12Utility-scalesolarPVweightedaverageLCOEtrendsintop20utility-scalemarkets,2021-2022CapixDenan©Shutterstock.comkimson©Shutterstock.com04OFFSHOREWIND115HIGHLIGHTS•Theglobalweightedaveragelevelisedcostofelectricity(LCOE)ofoffshorewinddeclinedby59%between2010and2022,fromUSD0.197/kilowatthour(kWh)toUSD0.081/kWh.However,in2022,therewasa2%increase,year-on-year.•InEurope,theweightedaverageLCOEofnewlycommissionedprojectswentup18%between2021and2022,fromUSD0.056/kWhtoUSD0.066/kWh.Totalinstalledcostsrose32%year-on-year,andtheweightedaveragecapacityfactorofnewprojectsincreasedfrom48%to49%in2022.•Between2010and2022,globalweightedaveragetotalinstalledcostsfell34%,fromUSD5217/kilowatt(kW)toUSD3461/kW.Atitspeak–in2011–theglobalweightedaveragetotalinstalledcostwasUSD5975/kW,1.7timeshigherthanits2022value.•Globalcumulativeinstalledcapacityofoffshorewindincreasedmorethantwenty-foldbetween2010and2022,from3.1gigawatts(GW)to63.2GW.ThiswasdrivenalmostequallybyinstallationsinChinaandEurope.Year-on-year,in2022,theglobalcumulativeinstalledcapacityofoffshorewindincreasedby16%.Newoffshorewindcapacitywas8.9GW,ofwhich4.1GWwasaddedinChinaand4.3GWinEurope.•Improvementsintechnology–includinglargerturbinesandlongerbladeswithhigherhubheights–alongwithaccesstobetterwindresourcesasfixed-bottomfoundationsimprovedandwindfarmsmovedfurtherfromshore,resultedinanincreaseintheglobalweightedaveragecapacityfactor.Thisincreasedfrom38%in2010to45%in2017,andin2022reached42%.•Overall,totalinstalledcostandLCOEreductionshavebeendrivenbybothtechnologyimprovementsandthegrowingmaturityoftheindustry.Indeed,growingdeveloperexperience,greaterproductstandardisation,manufacturingindustrialisation,regionalmanufacturingandservicehubs,andeconomiesofscalehaveallcontributedtocostdeclines.Thesedecreaseshavealsobeenfacilitatedbyclearpoliciesondeploymentand,insomecases,manufacturing,thathavefurthersupportedgrowth.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure4.1Globalweightedaverageandrangeoftotalinstalledcosts,capacityfactorsandLCOEforoffshorewind,2010-2022116RENEWABLEPOWERGENERATIONCOSTSIN2022INTRODUCTIONOffshorewindtechnologyhasmaturedrapidlysince2010.Indeed,therewasatwenty-foldincreaseincumulativedeployedcapacitybetween2010and2022,from3.1GWto63.2GW(IRENA,2023a).Floatingoffshorewindhasenteredtheearlycommercialstage,withthefirstplantsalreadydemonstratingthepotentialtoexploitthevastwindpotentialindeeperwaters.Currently,however,offshorewindstillonlymakesupunder7%ofthetotalcumulativeonshoreandoffshoreglobalwindcapacity.Yet,plansandtargetsforfuturedeploymenthavebeenexpanding,ascostshavedecreasedandthetechnologymatured.Forinstance,Belgium,Denmark,GermanyandtheNetherlandsannouncedinMay2022atargetofaddingenoughnewcapacitytoreachacombinedtotalof150GWofoffshorewindby2050.41Globalannualcapacityadditionsaveragedover4.5GWbetween2017and2020,whilein2021,theaddedoffshorewindcapacitywas19.9GW,droppingto8.9GWin2022.Unlikeonshorewindprojects,offshorewindfarmsmustcontendwithinstallation,andoperationandmaintenance(O&M),inharshmarineenvironments,makingtheseprojectscostlierandgivingthemsignificantlylongerleadtimes.Theplanningandprojectdevelopmentrequiredforoffshorewindfarmsisthereforemorecomplexthanthatforonshorewindprojects.Constructionisevenmorecomplexagain,increasingtotalinstalledcostsstillfurther.Giventheiroffshorelocation,theseprojectsalsohavehighergridconnectioncosts.Asprojectsbecamesitedfartherfromshore,indeeperwaters,andusedmoreadvancedtechnology,offshorewindinstalledcostspeakedaroundtheperiod2011-2015.Withtherecentincreaseindeployment,technologyimprovements,economiesofscale,andincreasesindeveloperandturbinemanufacturerexperience,however,costreductionshavebeenunlocked,particularlyforfixed-bottominstallations.Theincreasingmaturityoftheindustryhasalsobeenreflectedincost-savingprogrammes,suchasthestandardisationofturbineandfoundationdesigns,theindustrialisationofmanufacturingforoffshorewindcomponentsinregionalhubs,andtheincreasingsophisticationandspeedofinstallationpractices.Indeed,installationtimesandcostsperunitofcapacityhavebeenfallingwithdeveloperexperience,theuseofspecialisedshipsdesignedforoffshorewindworkandincreasesinturbinesizethatamortiseinstallationeffortsforoneturbineoverever-largercapacities.TheintroductionofspecialisedshipsformaintenancehasalsohelpedlowerO&Mcosts,ashavethescaleandoptimisationbenefitsofservicingoffshorewindfarmzones,ratherthanindividualwindfarms.Increasedwindturbineavailability,asmanufacturersareconstantlylearningfromrecentexperienceandincorporatingimprovementsintonewerproducts,hasalsohelpedlowercosts.Animportantareaofimprovementisalsolinkedtotheongoingdigitisationoftheenergysector.Theincreasinglysophisticateduseofthemassofinformationbeinggeneratedfromturbineperformancedataallowspredictivemaintenanceprogrammesthataredesignedtointervenebeforecostlyfailuresoccur,therebycontributingtolowerO&Mcostsandimprovedavailability.41Seewww.dr.dk/nyheder/viden/klima/danmark-spiller-afgoerende-rolle-i-storstilet-klimaplan-halvdelen-af-eus-havvindaccessed18May2022.117OFFSHOREWINDFigure4.2presentsthetrendthatoccurredbetween2000and2022inEurope,comparedwithChinaandtherestoftheworld,inwhichoffshorewindfarmsmovedtodeeperwatersandfartherfromshore.ThehandfulofoffshorewindfarmscommissionedinEuropein2000averaged25megawatts(MW)insizeandwerelocatedinawaterdepthof7metres(m),roughly5kilometres(km)fromshore.Thesefigureshavesignificantlyincreasedsincethen.In2022,theaverageoffshorewindfarmsizeinEuropewas468MW,withaweightedaveragewaterdepthof32mandadistancetoshoreof35km.InChina,theaverageoffshorewindfarmsizewas436MW,withaweightedaveragewaterdepthof35mandadistancetoshoreof27km,accordingtoprojectdataintheIRENARenewableCostDatabase.Table4.1belowshowsthecharacteristicsofanaverageoffshorewindfarminChinaandEuropebetween2010and2021.ThetrendtositeprojectsindeeperwatersandfurtherfromshoreismostpronouncedinEurope,themostmaturemarketforoffshorewind.MostrecentprojectsinEuropehavebeeninwatersbetween18mand58mdeep,withanincreasingproportionlocatedbetween50kmand120kmout–althoughasignificantnumberofEuropeanprojects,especiallyrecentfloatingoffshorewinddemonstrators,remainclosertoshore.ThemajorityofthemoredistantprojectscanbefoundinGermanyandtheUnitedKingdom.ThelatterisEurope’slargestoffshorewindproponent,with13.8GWofinstalledcapacityattheendof2022.Belgium,China,DenmarkandtheNetherlandsarestilllargelyexploitingzonesclosertoshore,althoughtheNetherlandsalsohasasignificantshareofitstotalwindfarms50kmormorefromthecoast.Allofthesecountriesare,however,currentlystillabletoexploitareasinshallowwater,from20mto40mdeep(Figure4.3).WithrelativelyfewcommissionedoffshorewindfarmsoutsidethemajormarketsofEuropeandChina,however,thereisnorealglobaltrendinwaterdepthanddistancefromshore.Mostcountriescontinuetoprioritisezonesclosetoshore(lessthan15kmfromthecoast),albeitwithaverywidespreadofwaterdepths(26mto50mforutility-scaleprojects).Alongwiththewaterdepth,thedistancefromashoreorportthatisabletosupportinstallationhasanimpactontotalinstalledcosts,asthelatterimpactsthetraveltimebetweentheportandwindfarmforfoundationsandturbinesduringinstallation,whiletheformerimpactsthesizeofthefoundations.ThedistancetoportalsohasanimpactonO&Mcostsanddecommissioningcosts.InEuropeanwaters,thetrendtositewindfarmsfartherfromshorehasalsobeencorrelatedwithharsherweatherconditions,whichmakeinstallationmoredifficult.Thishasaddedtimeandcosttothealreadyhighlogisticalcostswhenprojectsarefartherfromports(EEA,2009).Thisimpacthasstabilised,however,evenforthelargewindfarmsthatarenowthenorminEuropeanwaters.Installationcostshavealsobeencomingdownwithlargerturbines,whiletheIRENARenewableCostDatabaseshowsinstallationtimes–fromfirstfoundationtocommissioning–decliningsince2015tobetween1.4and2.4yearsforwindfarmsforwhichdataareavailable.118RENEWABLEPOWERGENERATIONCOSTSIN2022Projectcapacity(MW)≥≤20EuropeChinaandtherestoftheworldWaterdepth(m)Distancefromshore(km)Distancefromshore(km)Waterdepth(m)Figure4.2AveragedistancefromshoreandwaterdepthforoffshorewindinEurope,Chinaandtherestoftheworld,2000-2022David_Maddock©Shutterstock.com119OFFSHOREWINDProjectcapacity(MW)≤20BelgiumChinaDenmarkGermanyNetherlandsUnitedKingdomDistancefromshore(km)Distancefromshore(km)Waterdepth(m)Waterdepth(m)Distancefromshore(km)Distancefromshore(km)Waterdepth(m)Waterdepth(m)Distancefromshore(km)Distancefromshore(km)Waterdepth(m)Waterdepth(m)Figure4.3Distancefromshoreandwaterdepthforoffshorewindprojectsbycountry,1999-2025120RENEWABLEPOWERGENERATIONCOSTSIN2022Inadditiontooffshorewindfarmsincreasinglybeinglocatedfartherfromportsandanchoredindeeperwaters,therehasalsobeenatrendtowardshighercapacityturbines,withhigherhubheightsandlonger,moreefficientanddurableblades.Theseturbines,nowspeciallydesignedfortheoffshoresector,increaseenergycapture.ThisiscrucialinreducingtheLCOEofoffshoreprojects.Thelargerturbinesalsoprovideeconomiesofscale,withareductionininstallationcostsandanamortisationofprojectdevelopmentandO&Mcosts(Figure4.4).Rotordiametersarealsogrowing.China,GermanyandBelgiumtendtouselargerrotordiameters.Theweightedaveragerotordiameterincreasedby55%between2010and2022.In2022,Germanyhadaweightedaveragerotordiameterof167m,whileinChinaitwas181m.TheweightedaveragerotordiameterforEuropewas117min2010,rising39%to162min2022.Table4.1ProjectcharacteristicsinChinaandEuropein2010,2015and2021TheaverageoffshorewindfarminChinavsEurope2010201520202021Projectsize(MW)China67109350245Europe155270347591Distancefromshore(km)China12102112Europe18494123Waterdepth(m)China9122931Europe21293939Hubheight(m)China-90103102Europe838797108Rotordiameter(m)China-130162163Europe112119162159Turbinesize(MW)China2.84.05.96.7Europe3.14.27.98.5Atrendtowardshighercapacityturbineswithhigherhub-heightsandlongerbladesdesignedfortheoffshoresectorhasincreasedenergycaptureandreducedtheLCOEofprojects121OFFSHOREWINDOtherChinaEuropeCapacity(MW)≤≥Turbinecapacity(MW)Averagewindfarmcapacity(MW)Figure4.4Projectturbinesize,globalweightedaverageturbinesizeandwindfarmcapacityforoffshorewind,2000-2022TOTALINSTALLEDCOSTSComparedtoonshorewind,offshorewindfarmshavehighertotalinstalledcosts.Installingandoperatingwindturbinesintheharshmarineenvironmentoffshoreincreasescosts.Planningandprojectdevelopmentcostsarehigherandleadtimeslongerasaresult.Datamustbecollectedonseabedcharacteristicsandthesitelocationsfortheoffshorewindresource,whileobtainingpermitsandenvironmentalconsentsisoftenmorecomplexandtimeconsuming.Logisticalcostsarehigherthefarthertheprojectisfromasuitableport,whilegreaterwaterdepthsrequiremoreexpensivefoundations.Offshorewind,however,hastheadvantageofeconomiesofscale,meaningthatsomeofthesecostsarenotdisproportionatelyhigherthanthoseforonshorewind.Atthesametime,highercapacityfactorsareavailableoffshore,withthemorestablewindoutput(duetohigheraveragewindspeedsandreducedwindshearandturbulence).Inmanyregions,offshorewindcanbelocatedclosetocoastaldemandcentresatscale(e.g.inChinaandSouthKorea),whileinEuropegenerationishigherinwinter,coincidingwithwinterdemandpeaks.Thesefactors,andothers,ensureoffshorewindcanprovidesignificantoutputand,inmanycases,ahighervaluetotheelectricitysystemthanonshorewind.122RENEWABLEPOWERGENERATIONCOSTSIN2022Thepromiseofoffshorewindhasthereforealwaysbeenevidentand,inthelastfewyears,ithasstartedtorealiseitspotentialthroughscaling.Between2010and2022,theaverageoffshorewindprojectsizeincreasedby149%,from136MWto339MW.Since2020,therehavebeenprojectsthathavecapacitiesexceeding1GW.TheglobalweightedaveragetotalinstalledcostofoffshorewindfarmsincreasedfromaroundUSD2873/kWin2000toUSD6112/kWin2008.ItthenbouncedaroundtheUSD5500/kWmarkfortheperiod2008to2015,asprojectsmovedfartherfromshoreandintodeeperwaters(Figure4.5).Theglobalweightedaveragetotalinstalledcostthenbegantodeclineafter2015,fallingrelativelyrapidlytoUSD3052/kWin2021andslightlyrisingagaintoUSD3461/kWin2022.OtherChinaEuropeUSDkW≤Capacity(MW)≥Figure4.5Projectandglobalweightedaveragetotalinstalledcostsforoffshorewind,2000-2022balipadma©Shutterstock.com123OFFSHOREWINDAnumberoffactorsexplaintheincreaseintotalinstalledcoststhatoccurredafter2006,including:•Theshifttoprojectsindeeperwatersandfartherfromshore/portsincreasedlogisticalcosts,installationcostsandfoundationcosts.•Theincreasingscaleandcomplexityofprojectsrequiredaproportionalincreaseinprojectdevelopmentcosts(surveys,licensing,etc.).•Theindustrywasinitsinfancy,andthespecialisedinstallationvesselsoftodaywerenotavailable,resultinginlessefficientinstallationprocesses.Additionally,supplychainswerenotyetoptimised,operatingatscaleandwithwidespreadcompetition.•Risingcommoditypricesinthisperiodalsohadadirectimpactonthecostoftransportationandontheoffshorewindmaterialsusedinturbinesandtheirfoundations,transmissioncabling,andothercomponents(IRENA,2019).Someofthecontributingfactorstocostincreases,suchassupplychainbottlenecksforturbinesandcablesandlogisticsissues,weretransient(Green,2011;Anzinger,2015).Consequently,theweightedaveragetotalinstalledcostshavesincefollowedadownwardcost-reductiontrend,falling42%fromtheirpeakin2011toaglobalweightedaverageofUSD3461/kWforprojectscommissionedin2022.Majorsupportforthistrendcamefromlowercommodityprices,lowerrisksfromstablegovernmentpoliciesandsupportschemes,improvedturbinedesigns,standardisationofdesignandindustrialisedmanufacturing,improvementsinlogistics(especiallywithspecialisedinstallationvesselsandlargerturbinesforoffshorewind),andeconomiesofscalefromclusteredprojectsinEurope.Yet,duetotherelativelythinmarketcomparedtoonshorewindandsolarPV,theannualglobalweightedaveragetotalinstalledcostremainsvolatile.Thatyearlyvolatilityisalsoduetothesite-specificnatureofoffshorewindprojects,thedifferencesinmarketmaturity,andthescaleofthelocalorregionalsupplychain.Deploymentineachyearisdistributedslightlydifferentlyacrossmarkets,too,addingtothedriveannualvolatility.In2022,forexample,Chinadominatedtotaldeployment.TheglobalweightedaveragetotalinstalledcostswerethereforeheavilyinfluencedbyChina’slowercosts–duetolowercommoditypricesandlabourcosts–aswellasthenear-shoreandinter-tidalnatureofmostChinesewindfarms.Themostnotableotherdriveroftotalinstalledcostsisthepartyresponsibleforthewindfarm-to-shoretransmissionassets.Thischoicevariesbycountry.Insomecases,thetransmissionassetsareownedbythenationalorregionaltransmissionnetworkowner,andinothercasestheyareownedbythewindfarmdeveloper.4242Otherarrangementsarealsopossible.IntheUnitedKingdom,forexample,theprojectdeveloperisresponsiblefordevelopingthetransmissionasset,whichcanthenbeownedbyathirdparty.124RENEWABLEPOWERGENERATIONCOSTSIN2022Itisthereforeimportanttolookattotalinstalledcosttrendsonacountry-by-countrybasistounderstandhowcoststructuresareevolving.Between2010and2020,Belgiumhadthehighestpercentagedecrease(44%)inweightedaveragetotalinstalledcost–fromUSD6777/kWtoUSD3793/kW.Overasimilarperiod,in2010-2022,China,whichhasthelargestcumulativeoffshorewinddeploymentglobally(roughly30.5GW),experienceda43%declineinweightedaveragetotalinstalledcost,fromUSD4962/kWtoUSD2811/kW43(Table4.2).InChina,gridconnectionassetsaredevelopedbyprojectowners,orthetransmissionnetworkowner.InDenmark,gridconnectionsaredevelopedandownedbythenetworkoperatorandasaresult,itsproject-specificweightedaveragetotalinstalledcostsin2021wereUSD2449/kW.IntheUnitedKingdom,whichhadthesecondlargestoffshorewindaddedcapacityin2022(2.6GW),theproject-specificweightedaveragetotalinstalledcostwasUSD3891/kW.Thatyear,alltheregionsandcountrieslistedinTable4.2withtheexceptionofJapanexperiencedadecreaseinweightedaveragetotalinstalledcosts.Offshoreandonshorewindfarmshavedifferingcostbreakdowns.Thisistobeexpected,givenoffshorewindfarms’higheraveragecostsforinstallationandfoundations.Dataavailabilityforproject-leveltotalinstalledcostbreakdownsis,however,verydifficulttoobtainduetoconfidentialityissues.Yet,numerousstudiesdoprovideestimatesforspecificmarkets,oftenbasedondiscussionswithprojectdevelopers–althoughitissometimesunclearexactlyhowcomparablethesedataare.Offshore,turbines(includingtowers)generallyaccountforbetween33%and43%ofthetotalinstalledcost(Figure4.6).Othercosts,however–includinginstallation,foundationsandelectricalinterconnection–aresignificant,andtakeupasizeableshareofthetotalinstalledcosts.Installationcosts,fortheestimatesavailable,rangefrom8%to19%oftotalinstalledcosts,whilecontingency/othercostsrangebetween10%and14%,electricalinterconnectionbetween8%and24%,andfoundationcostsbetween14%and22%.Developmentcosts,whichincludeplanning,projectmanagementandotheradministrativecosts,comprise2%to7%oftotalinstalledcosts.Offshorewindsitecharacteristicsandcountrypoliciescanalsoaccountfordifferencesincostbreakdowns.Forexample,whetherdevelopersareresponsibleornotforelectricalinterconnectioncosts(besidesthecostofelectricalarraysforconnectingtheturbines)hasamaterialimpactontotalinstalledcosts.Between2010and2022,globalweightedaveragetotalinstalledcostsofoffshorewindfell34%,fromUSD5217toUSD3461/kW43Thismay,however,beanoverestimate.AsfeedbackfromdevelopersinChinasuggeststhattheactualcostsin2022mayhavebeenaslowasUSD1700toUSD2000/kW(personalcommunicationwithYuetaoXi,30June,2023).125OFFSHOREWINDTable4.2Regionalandcountryweightedaveragetotalinstalledcostsandrangesforoffshorewind,2010and2022201020225thpercentileWeightedaverage95thpercentile5thpercentileWeightedaverage95thpercentile(2022USD/kW)Asia318950085607212831565561China311649625513227328113271Japan547154715471663766376637RepublicofKorean.a.n.a.n.a.560567177830Europe3941522572112693390713136Belgium677767776777360737934147Denmark366236623662244924492449Germany721172117211286742204187Netherlands460046004600260426042604UnitedKingdom452150865427381438913990Notes:Countrieswheredatawereonlyavailableforprojectscommissionedin2020,not2022.Countrieswheredatawereonlyavailableforprojectscommissionedin2021,not2022.TheNetherlandshadnoprojectscommissionedin2010,sodataforprojectscommissionedin2015areshown.Contingency&otherTurbineElectricalinterconnectionDevelopmentFoundationsInstallationEurope()JRC()IEAwindgeneric()IEAwindgeneric()UnitedKingdom()UnitedStates()UnitedStates()GenericOECDaverage()ShareoftotalinstalledcostFigure4.6Representativeoffshorewindfarmtotalinstalledcostbreakdownsbycountry/region,2013,2016,2017and2019Note:OECD=OrganisationforEconomicCo-operationandDevelopment126RENEWABLEPOWERGENERATIONCOSTSIN2022AsdetailedinFigure4.6,installationcostsforturbinesareamajorcontributortothetotalcost.Thisreflectstheexpenseoftransporting,operatingandinstallingfoundationsandturbinesoffshore,withdistancetoportrepresentinganothermajorcontributingcostfactor.Forfloatingturbines,installationcostsareproportionatelylower,whilefoundationcostsarehighergiventheadditionalmass.Aslarger,dedicatedinstallationvesselshavebecomeavailable,however,experiencehasbeengatheredandlargerturbineshavebeenemployed.Asaresult,installationtimesforprojectshavefallen.Fromanaverageoftwoormoreyearsperwindfarmbetween2010and2015,by2020,theinstallationtimehadfallentolessthan18months.Tocapturethedynamicsmentionedabove–andgivenvaryingprojectsizes–abettermetricthaninstallationtimeisMWinstalledperyearbyproject.Inthelatterterms,amuchstrongertrendcanbeseeninthedataavailableforEuropesince2018.Inthesedata,thefiguresincreasefrom100MWto200MWfrom2010to2015tobetween200MWand300MWperyearperprojectfrom2015to2020.From2016,projectsalsoroutinelyexceeded300MWperyear(Figure4.7).Capacity(MW)≥30GermanyDenmarkBelgiumUnitedKingdomConstructionduration(years)MWinstalledperyearFigure4.7InstallationtimeandMWinstalledperyearbyoffshorewindprojectinEurope,2010-2020Note:Durationdatarepresentsthetimefromfirstfoundationtolastturbine.127OFFSHOREWINDCAPACITYFACTORSTherangeofcapacityfactorsforoffshorewindfarmsisverywideduetodifferencesinthemeteorologybetweenwindfarmsites,thetechnologyusedandthewindfarm’sconfiguration,i.e.theoptimalturbinespacingtominimisewakelossesandincreaseenergyyields.OptimisationoftheO&Mstrategyoverthelifeoftheprojectisalsoanimportantdeterminantoftherealisedlifetimecapacityfactor.Between2010and2022,theglobalweightedaveragecapacityfactorofnewlycommissionedoffshorewindfarmsgrewfrom38%to42%.Thiswasdrivenbywindturbineswithhigherhubheightsandlargersweptareasthatenableturbinestoharvestmoreelectricityfromthesameresource.In2022,thecapacityfactorrange(5thand95thpercentile)fornewlyinstalledprojectswasbetween28%and50%(Figure4.8).Thedeclineintheglobalweightedaveragecapacityfactorsince2017anduntil2021haspredominantly,butnotentirely,beendrivenbytheincreasedshareofChinainglobaldeployment(around54%ofnewcapacityaddedin2022).Asdiscussed,China’swindresourceisgenerallynotasgoodasintheNorthSea,evenwelloffshore,whileprojects,historically,tendedtobenear-shoreorinter-tidal–locationsthatgenerallyhavepoorerwindresourcesthanthoseavailablefurtheroffshore.China’sprojectsalsodidnotusetheverylarge,turbinesdeployedinEuropeandelsewhere.However,turbinesizejumpedin2022,asdevelopershadtoadjusttonew'gridparity'regimewiththeendoftheFiTprogramme.TheweightedaveragecapacityfactorforprojectscommissionedinEuropeincreasedby26%(ortenpercentagepoints)from39%in2010to49%in2022.InEurope,the5thand95thpercentilecapacityfactorsforprojectscommissionedin2022were45%and52%,respectively.Incontrast,theweightedaveragecapacityfactorforprojectscommissionedinChinain2022was37%,whilethe5thand95thpercentileswere30%and43%,respectively.Figure4.9showsthatbothoffshorewindrotordiameterandhubheightfollowedasimilar,increasingtrendovertheperiod2010to2022.Theturbinerotordiameterexperienceda56%increaseoverthatperiod,growingfromaweightedaveragevalueof112mto175m.Overthesameperiod,turbinehubheightgrewby35%,fromaweightedaverageof83mto112m.Withrotordiametersincreasingfasterthanbothhubheightsandturbinesizes,thespecificpowerofwindturbines(measuredinwattspersquaremetre[W/m2])hasfallenovertime,particularlyinEurope.Thishasimportantimplicationsforcapacityfactortrends,as,allelsebeingequal,inmanysituations,lowerspecificpowerlevelswillresultinhighercapacityfactors.Therehasalsobeenatrendtowardsreduceddowntimeasmanufacturershaveintegratedexperiencefromoperatingwindfarmmodelsintonew,morereliabledesigns.ItisalsoworthnotingtheexperienceinoptimisingO&Mpracticestoreduceunscheduledmaintenancethathasbeenunlockedbyimprovementsindatacollectionandanalytics,allowingforpredictivemaintenanceandproductionoutputoptimisation.Inaddition,improvementsinthedevelopmentstage,duetogreaterexperience,haveledtobettermethodsforwindresourcecharacterisationwhenitcomestoidentifyingthebestsites,andimprovedwindfarmdesignsthatoptimiseoperationaloutput.128RENEWABLEPOWERGENERATIONCOSTSIN2022Fortheperiod2010to2022,anexaminationofweightedaveragecapacityfactorimprovementsincountrieswithoffshorewindinstallationsshowsthatthegreatestimprovementwasintheUnitedKingdom,wheretherewasa36%increaseovertheperiod(Table4.3).Germanywastheexceptiontogenerallyincreasingcapacityfactorsovertheperiod.Thiscanbeattributedtothealreadyrelativelyhighcapacityfactorachievedin2010,significantlyabovethecountry’speers,andthegrowingweightofprojectsthathavebeencommissionedintheBalticSea,whereloweraveragewindspeedsthanintheNorthSeaarethenorm(Wehrmann,2020).SimilartrendscanbealsoseenintheNetherlands.OtherChinaEurope≤≥Capacity(MW)CapacityfactorFigure4.8Projectandglobalweightedaveragecapacityfactorsforoffshorewind,2000-2022HubheightRotordiameterRotordiameterhubheight(m)Figure4.9Globalweightedaverageoffshorewindturbinerotordiameterandhubheight,2010-2022129OFFSHOREWINDWindspeedCapacityfactorIndex()Figure4.10CapacityfactorandwindspeedtrendsbyprojectinEurope,2010-2025ThetrendsinglobalweightedaverageoffshorehubheightsandrotordiametersfornewlycommissionedprojectsareshowninFigure4.9.Theweightedaveragehubheightincreasedfrom83min2010to112min2022,whilethatofrotordiametersincreasedfrom112min2010to174min2022.ThedataforEuropeshowtheclearcontributiontechnologyimprovementshavemadeinboostingthecapacityfactorsofoffshorewindfarmsoverthelastdecade,withthislikelytocontinueforthenextfewyears.Between2010and2020,theweightedaveragecapacityfactorofnewlycommissionedprojectsincreasedbyaround8%,whiletheweightedaveragewindresourceforthoseprojectsincreasedbyonly2%.Theyear2020wassomethingofanoutlierforwindprojectsinEurope,however.Lookingat2019and2021,thenumberswere+22%and+4%,and+13%and+3%,respectively,relativetoprojectsin2010(Figure4.10).Table4.3Weightedaveragecapacityfactorsforoffshorewindprojectsinsevencountries,2010and202220102022Percentagechange2010-2022%Belgium38418%China303723%Denmark445014%Germany50468%Japan28307%Netherlands48492%UnitedKingdom364936%Notes:Countrieswheredatawereonlyavailableforprojectscommissionedin2020,not2022.Countrieswheredatawereonlyavailableforprojectscommissionedin2021,not2022.TheNetherlandshadnoprojectscommissionedin2010,sodataforprojectscommissionedin2015areshown.130RENEWABLEPOWERGENERATIONCOSTSIN2022Figure4.11showstherelationshipbetweenspecificpower(mappedinversely)andcapacityfactorsforoffshorewindprojectsforwhichIRENAhasdata.Allelsebeingequal,largerrotorbladeswillharnessmoreenergyfromthewind,turningtherotorbladesathigherratesthanshorterblades.Thismeansturbinegeneratorsoperateathigheroutputlevelsandatmaximum-ratedcapacitiesforlongerperiods.Thecombinedimpactofthiswillbeahighercapacityfactor.Thedataavailablesuggestthat,overtime,thisincreasehashappenedinEurope.Thereisastatisticallysignificantrelationship–albeitonethatdoesnotexplainalotofthevariationseeninthechart(e.g.alowcoefficientofdetermination,orR2)–suggestingotherfactorsarealsoinplay.Theimpactofhubheightsandwindresourcequalitiesacrossthecountriesrepresentedinthechartarelikelyhavingasignificantimpact,althoughafullstatisticalanalysiswouldberequiredtoidentifythemaindrivers.Turbinecapacity(MW)10UnitedKingdomGermanyDenmarkBelgiumNetherlandsCapacityfactorSpecificpower(wattsm)Figure4.11OffshorewindcapacityfactorsandspecificpowerbyprojectandcountryLargerrotorbladesharnessmoreenergyfromthewind,allowingturbinegeneratorstooperateathigheroutputlevelsandatmaximum-ratedcapacitiesforlongerperiods131OFFSHOREWINDOPERATIONANDMAINTENANCECOSTSO&McostsforoffshorewindfarmsperkWarehigherthanthoseforonshorewind.Thisismainlyduetothehighercostofaccessingthewindsitetoperformmaintenanceonturbinesandcabling.Thelatterisheavilyinfluencedbyweatherconditionsandtheavailabilityofskilledpersonnelandspecialisedvessels.Giventhehighercapacityfactorsoffshore,however,O&Mcostsarealsoamortisedoveralargeroutput,meaningoffshorewindO&Mcoststypicallyconstitute16%to25%oftheLCOEforoffshorewindfarmsdeployedintheGroupof20(G20)countries.Aswithonshorewind,however,limiteddataareavailableforoffshorewindO&Mcosts.ThereisalsogeneraluncertaintyaroundlifetimeO&Mcostsforoffshorewind,owingtolimitedoperationalexperience–especiallyinsitesfartheroffshore.Asmentionedinthecapacityfactordiscussion,O&Mpracticesarebeingcontinuouslyrefinedtoreducecostsandimproveavailability,however.Asaresultofimprovedcapacityfactors,andduetoincreasedcompetitioninO&Mprovision,O&McostsperkWhhavethereforebeenfalling.For2018,representativerangesforcurrentprojectsfellbetweenUSD70/kWperyeartoUSD129/kWperyear(Noonanetal.,2018andØrsted,2018).ThelowerrangewasobservedforprojectsinestablishedEuropeanmarketsandinChina,usuallywithsitesclosertoshore.TherangeisbroadbecausetheO&McostsvarydependingonlocalO&Moptimisationandsynergiesfromoffshorewindfarmzoneclustering,aswellasontheapproachtakenbytheoffshorewindfarmownersaftertheinitialturbineoriginalequipmentmanufacturer(OEM)warrantyperiod.Asthesectorhasgrown,increasedcompetitioninO&MprovisionhasemergedandhasresultedinavarietyofstrategiestominimiseO&Mcosts(e.g.theuseofindependentserviceproviders,turbineOEMs’ownservicearms,in-houseO&M,marinecontractorsoracombinationthereof).BesidestheimpactofexperienceandcompetitiononO&Mcostreduction,higherturbineratingshavereducedtheunitO&Mcosts.AnexampleoftheO&McostreductionimpactfromthesefactorscomesfromØrsted,amajoroffshorewinddeveloperwithaportfolioofupto9.9GWofoffshorewindfarmsinoperationorunderconstructionglobally.ØrstedwasabletoreduceO&Mcostsbyover43%between2015and2018,fromUSD118/kW/yeartoUSD67/kW/year(Ørsted,2018).Basedonprojectscommissionedoverthelastfiveyears,IRENAanalysisshowsthatO&McostsaccountforbetweenUSD0.017/kWhandUSD0.030/kWh,44withthelowercostrangeobservedinestablishedmarketsinEuropeandChinaandthehighercostrangesinless-establishedmarketswhereO&Msupplychainshavenotbeenfullysetup,e.g.RepublicofKorea(whichalsohaslowerweightedaveragecapacityfactors).44ThisexcludesJapan,wheredeploymenthasnotyetreachedcommercialscaleandtheO&Mcostsarenotrepresentativeofcommercialprojects.132RENEWABLEPOWERGENERATIONCOSTSIN2022LEVELISEDCOSTOFELECTRICITYInrecentyears,increasingexperienceandcompetition,advancesinwindturbinetechnology,theestablishmentofoptimisedlocalandregionalsupplychains–andstrongpolicyandregulatorysupport–haveresultedinasteadypipelineofincreasinglycompetitiveprojects.Between2010and2022,theglobalweightedaverageLCOEofoffshorewindfell59%,fromUSD0.197/kWhtoUSD0.081/kWh(Figure4.12).The2022figurewas8%downonits2020valueofUSD0.088/kWh.Fromitspeakin2007,theglobalweightedaverageLCOEofoffshorewindhadfallen65%by2021.DenmarkhadthelowestweightedaverageLCOEforprojectscommissionedin2021(thelatestyearwithavailabledata),atUSD0.043/kWh(Table4.4).In2022,theNetherlandshadthelowestweightedaverageLCOE,atUSD0.058/kWh.However,theUnitedKingdomhadthehighestpercentagereductionincountryweightedaverageLCOEvaluesbetween2010and2022,at71%.Belgiumwassecond-highestinthispercentagereduction(63%)overroughlythesameperiod(thelatestavailabledataforBelgiumarefor2020).BelgiumalsohadthehigheststartingpointforweightedaverageLCOEin2010,atUSD0.238/kWh.Denmarkwasalsothefirstcountrytopioneeroffshorewindatacommercialscale,withthecommissioningoftheVindebywindprojectin1991.Denmark’slowLCOEisthereforepartlydrivenbyexperience,aswellasbyprojectsthatarelocatedclosetoshoreandinshallowerwatersthanmanyofitsneighbours',andthefactthatwindfarm-to-shoretransmissionassetsarenottheresponsibilityoftheprojectdeveloper.KMPT©Shutterstock.com133OFFSHOREWINDOtherChinaEuropeCapacity(MW)≥≤USDkWhFigure4.12OffshorewindprojectandglobalweightedaverageLCOE,2000-2022Table4.4RegionalandcountryweightedaverageLCOEofoffshorewind,2010and2022201020225thpercentileWeightedaverage95thpercentile5thpercentileWeightedaverage95thpercentile(2022USD/kW)Asia0.1290.1900.2100.0620.0850.152China0.1260.1890.2080.0610.0770.092Japan0.2000.2000.2000.2210.2210.221RepublicofKorean.a.n.a.n.a.0.1410.1910.240Europe0.1350.2000.2350.0580.0740.113Belgium0.2380.2380.2380.0870.0880.090Denmark0.1140.1140.1140.0430.0430.043Germany0.1870.1890.1960.0590.0780.078Netherlandsn.a.n.a.n.a.0.0580.0580.058UnitedKingdom0.2100.2190.2270.0600.0640.067Countrieswheredatawereonlyavailableforprojectscommissionedin2020,not2022.Countrieswheredatawereonlyavailableforprojectscommissionedin2021,not2022.JohnTheodor©Shutterstock.com05CONCENTRATINGSOLARPOWER135HIGHLIGHTS•Between2010and2022,theglobalweightedaveragelevelisedcostofelectricity(LCOE)ofconcentratingsolarpower(CSP)plantsfellby69%,fromUSD0.380/kilowatthour(kWh)toUSD0.118/kWh.However,onlyasingleplanthasbeencommissionedin2021and2022,sotheseyearsarenotnecessarilyrepresentative.•Between2010and2020,thedeclineintheglobalweightedaverageLCOEwasprimarilydrivenbyreductionsintotalinstalledcosts(down64%),highercapacityfactors(up17%),loweroperationsandmaintenance(O&M)costs(down10%)andareductionintheweightedaveragecostofcapital(down9%).•Between2010and2020,globalaveragetotalinstalledcostsforCSPdeclinedbyhalf,toUSD5079/kilowatt(kW).Thiswasachievedinasettingwhereprojectenergystoragecapacitieswereincreasingcontinuously.•During2021,however,totalinstalledcostsincreasedtoUSD9728/kW–just4%lowerthanin2010.Thisreflectedthefactthatonlyoneprojectcameonlinein2021–aChileanCSPschemewith17.5hoursofstorage.In2022,anotherverythinmarketalsosawonlyoneprojectcomeonline,thistimeinChina.Thetotalinstalledcostsofthatprojectwere56%lowerthanthe2021value,however,atUSD4274/kW.Thisalsorepresenteda58%declineincostscomparedto2010.•Theglobalweightedaveragecapacityfactorofnewly-commissionedCSPplantsincreasedfrom30%in2010to42%in2020,asthetechnologyimproved,costsforthermalenergystoragedeclinedandtheaveragenumberofhoursofstorageforcommissionedprojectsincreased.TheexcellentsolarresourceinthelocationoftheCerroDominadorCSPprojectmeantaveryhighcapacityfactorvaluefor2021,at80%.Thevaluefor2022wasestimatedtobe36%.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure5.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforCSP,2010-2022136RENEWABLEPOWERGENERATIONCOSTSIN2022INTRODUCTIONCSPsystemsworkbestandhavebettereconomicsinareaswithahighdirectnormalirradiance(DNI)–thatis,above2000kWh/squaremetre(m2)/year–butcanstillworkatlowervalues.CSPsystemsusemirrorstoconcentratethesun’sraysandcreateheat,withmostcontemporarysystemsthentransferringthatheattoaheattransfermedium–typicallyathermaloilormoltensalt.Electricityisthengeneratedthroughathermodynamiccycle.Thiscouldbe,forexample,oneusingtheheattransferfluidtocreatesteamandthengenerateelectricity,asinconventionalRankine-cyclethermalpowerplants.Mostcommonly,atwo-tank,moltensaltstoragesystemisused,butdesignsvary.Today,CSPplantsalmostexclusivelyalsoincludelow-costandlong-durationthermalstoragesystems.ThisgivesCSPgreaterflexibilityindispatchandtheabilitytotargetoutputtoperiodsofhighcostintheelectricitymarket.Indeed,thisisalsousuallytheroutetolowest-costandhighest-valueelectricity,becausethermalenergystorageisnowacost-effectivewaytoraiseCSPcapacityfactors.ItispossibletoclassifyCSPsystemsaccordingtothemechanismbywhichsolarcollectorsconcentratesolarirradiation.Suchsystemsareeither‘lineconcentrating’or‘pointconcentrating’,withthesetermsreferringtothearrangementoftheconcentratingmirrors.Today,mostCSPprojectsuselineconcentratingsystemscalledparabolictroughcollectors(PTCs).Typically,singlePTCsconsistofaholdingstructurewithanindividuallinefocusingcurvedmirrors,aheatreceivertubeandafoundationwithpylons.Thecollectorsconcentratethesolarradiationalongtheheatreceivertube(alsoknownasanabsorber),whichisathermallyefficientcomponentplacedinthecollector’sfocalline.ManyPTCsaretraditionallyconnectedin‘loops’throughwhichtheheattransfermediumcirculatesandwhichhelptoachievescale.Lineconcentratingsystemsrelyonsingle-axistrackerstomaintainenergyabsorptionacrosstheday,increasingtheyieldbygeneratingfavourableincidenceanglesofthesun’sraysontheapertureareaofthecollector.SpecificPTCconfigurationsmustaccountforthesolarresourcesatthelocationandthetechnicalcharacteristicsoftheconcentratorsandheattransferfluid.Thatfluidispassedthroughaheatexchangesystemtoproducesuperheatedsteam,whichdrivesaconventionalRankine-cycleturbinetogenerateelectricity.Anothertypeoflinear-focusingCSPplant–thoughmuchlesscommon–usesFresnelcollectors.Thistypeofplantreliesonanarrayofalmostflatmirrorsthatconcentratethesun’sraysontoanelevatedlinearreceiverabovethemirrorarray.Unlikeparabolictroughsystems,inFresnelcollectorsystems,thereceiversarenotattachedtothecollectors,butsituatedinafixedpositionseveralmetresabovetheprimarymirrorfield.Solartowers(STs),sometimesknownas‘powertowers’,arethemostwidelydeployedpointfocusCSPtechnology,althoughsuchsystemsrepresentedonlyaroundafifthoftotalCSPdeploymentattheendof2020(SolarPACES,2023).InSTsystems,thousandsofheliostatsarearrangedinacircularorsemi-circularpatternaroundalargecentralreceivertowertoredirectthesun’sraystowardsit.137CONCENTRATINGSOLARPOWEREachheliostatisindividuallycontrolledtotrackthesun,orientatingconstantlyontwoaxestooptimisetheconcentrationofsolarirradiationontothereceiver,whichislocatedatthetopofatower.Thecentralreceiverabsorbstheheatthroughaheattransfermedium,whichturnsitintoelectricity–typicallythroughawater-steamthermodynamiccycle.SomeSTdesignsdoawaywiththeheattransfermedium,however,andsteamisdirectlygeneratedatthereceiver.STscanachieveveryhighsolarconcentrationfactors(above1000suns)andthereforeoperateathighertemperaturesthanPTCs.ThiscangiveSTsystemsanadvantage,ashigheroperatingtemperaturesresultingreaterefficiencieswiththesteam-cycleandpowerblock.Higherreceivertemperaturesalsounlockgreaterstoragedensitieswithinthemoltensalttanks,drivenbyalargertemperaturedifferencebetweenthecoldandhotstoragetanks.Bothfactorscutgenerationcostsandallowforhighercapacityfactors.Forthisreason,andthefacttheyrepresentthemajorityofnewprojectsannouncedinChina,theirsharemaygrowincomingyears.Globally,cumulativeCSPinstalledcapacitygrewjustoverfive-foldbetween2010and2020,reachingaround6.5gigawatts(GW)bytheendofthatperiod.Breakingthelastfiveyearsofthisdown,aftermodestactivityin2016and2017–withannualadditionshoveringaround100megawatts(MW)peryear–theglobalmarketforCSPgrewin2018and2019.Inthoseyears,anincreasingnumberofprojectscameonlineinChina,MoroccoandSouthAfrica.Yet,comparedtootherrenewablepowergenerationtechnologies,newcapacityadditionsoverallremainedrelativelylow,at860MWperyearin2018and550MWin2019.In2020,only150MWwascommissionedglobally,withallofthiscomingonlineinChina.Hopesforgrowthin2021didnotmaterialise,though110MW(allfromtheCerroDominadorproject)wascommissionedduringthatyearinChile.Atthesametime,about265MWfromtheSolarEnergyGeneratingSystems(SEGS)plantintheUnitedStates–inoperationsincethelate1980s–wasretired.Afterlimiteddeploymentin2022,thecumulativeglobalinstalledcapacityofCSPattheendof2022ataround6.5GW.Thesectorremainsdynamic,though.China’splanstoscaleupthetechnologydomesticallycouldprovideaboosttotheindustryandtakedeploymenttonewlevels.Yet,progressonChina’spolicytobuild-outseveralcommercial-scaleplantstoscaleupavarietyoftechnologicalsolutions,developsupplychainsandgainoperatingexperiencehasprovedmorechallengingthananticipated.Developershavestruggledandsomeprojectshavebeenlagging.Somehavefoundnewdevelopers,whileothersappearunlikelytobecompleted.Theoutlookfor2023issomewhatbrighter,withtheNoorEnergy1/DEWAIV–100MWtowersegmentintheUnitedArabEmiratesalreadycommerciallyoperationalsinceFebruary2023.ThepossibilityremainshighfornewcapacitytocomeonlineinChinaaswell.In2022,Spainlaunchedanauctionthatincluded200MWofCSPcapacity,buttheauctionwasunsuccessfulasbidswherehigherthanthemaximumallowed,inpartduetothelackofindexationtoinflation(Kraemer,2022).TheCSPprojectpipelineincludesa100MWsolartowerprojectwith12hoursofstorageexpectedtocomeonlineby2024inSouthAfrica.Botswana’sMinistryofMineralResources,GreenTechnologyandEnergySecurityhasinitiatedapre-qualificationprocessforparticipationina200MWCSPtender,whileNamibiahasannouncedplanstolaunchaCSPtenderin2022forbetween50MWand130MWofCSPcapacity.Inadditiontothis,a300MWprojectisplannedtocomeonlinein2025inQinghai,China.TheNationalEnergyandClimatePlans(NECPs)ofsomeEUmemberstatesgiveanindicationofthepotentialdevelopmentoftheCSPprojectpipelineinthefuture.Forexample,Spainplanstoadd5GWandItaly880MWofnewCSPcapacityby2030.138RENEWABLEPOWERGENERATIONCOSTSIN2022ContingenciesBalanceofplantEngineeringOwnerscostsHTFsystemPowerblockSolarﬁeldThermalenergystorageReceiverPowerblockHeliostatﬁeldBoPandengineeringContingenciesTowerOwnerscostsThermalenergystorageUSDkWhPercentoftotalParabolictroughUSDkWhPercentoftotalSolartowerFigure5.2TotalinstalledcostbreakdownofCSPplantsbytechnology(2010-2011and2019-2020)Source:IRENARenewableCostDatabase;Hinkley,2010;Fichtner,2011.Notes:HTF=heattransferfluid;BoP=balanceofplant.Percentagefiguresmaynottotal100duetoroundingup.Dataisrepresentativeofglobaltechnologyvalues.TOTALINSTALLEDCOSTSIntheearlyyearsofCSPplantdevelopment,addingthermalenergystoragewasoftenuneconomicandgenerallyunwarranted,soitsusewaslimited.Since2015,however,hardlyanyprojectshavebeenbuiltorplannedwithoutthermalenergystorage.Addingthisisnowacost-effectivewaytoraisecapacityfactors,whileitalsocontributestoalowerLCOEandgreaterflexibilityindispatchduringthecourseoftheday.TheaveragethermalstoragecapacityforsolarthermalplantsintheIRENARenewableCostDatabaseincreasedfrom3.5to11hoursbetween2010and2020.Commissionedin2021,theCerroDominador110MWSTproject,locatedinChile’sAtacamaDesert,featuresastoragecapacityof17.5hours.During2022thecapacityinstalledinChinaaveraged9hoursofstorage.ItislikelythatallnewCSPprojectsdevelopedworldwidewillincludethermalstorage.TotalinstalledcostsforbothPTCandSTplantsaredominatedbythecostofthecomponentsthatmakeupthesolarfield.Althoughdataonthetotalinstalledcostbreakdownfor2010relyonbottom-up,techno-economicanalyses(Fichtner,2010;Hinkley,2011),thedatacanbepairedwithIRENA’sprojectlevelinstalledcosttogetanunderstandingofthetotalinstalledcostbreakdownin2010-2011and2019-2020(Figure5.2).139CONCENTRATINGSOLARPOWERIn2010,thesolarfieldofaPTCplantcostanestimatedUSD4503/kW(44%ofthetotalinstalledcost),butby2020,thisFigurehadfallen68%toUSD1440/kW(30%ofthetotal).Withsuchadramaticreductionincostsforthesolarfield,othercostareaswithsmallerdeclinessawtheirshareoftotalinstalledcostsincrease.Thepowerblock’sshare,forexample,increasedfrom15%in2010to19%in2020,despiteitscostfallingby40%overthesameperiod,fromUSD1499/kWtoUSD892/kW.Thiswasalsothecasefortheheattransferfluidsystem,whichincreaseditssharefrom9%to11%,despitethesecostsperkWfalling47%overthe2010-2020period,fromUSD948/kWtoUSD503/kW.Thisalsooccurredforthermalenergystorage.Thatcomponent’sshareoftotalinstalledcostsincreasedfrom9%in2010to15%in2020,despitethecostitselffallingfromUSD873/kWtoUSD706/kW.Atthesametime,duringthatperiod,theowner’scostssharerosefrom5%to9%,withanabsolutevaluechangefromUSD465/kWtoUSD427/kW.Overthe2010to2020period,thecostsofthebalanceofplant,engineeringandcontingenciesforPTCplantsdeclinedby60%,64%and57%respectively.Asaresult,overthesameperiod,theshareofbalanceofplantintotalinstalledcostsdeclinedfromUSD626/kW(6%ofthetotal)toUSD252/kW(5%),whileengineeringcostsfellfromUSD507/kW(5%ofthetotal)toUSD180/kW(4%).AmeasureofhowfartheweightedaveragetotalinstalledcostsforPTCplantshavefallenisthefactthatthecostsofthesolarfieldalonein2010wereonly5%lowerthantheweightedaveragetotalinstalledcostin2020.ForSTplants,thiscomparisonisverysimilar,with2010heliostatfieldcostsbeingonly7%lowerthantheSTweightedaveragetotalinstalledcostvaluein2019.Overthatdecade,thereductioninthecostoftheheliostatfieldwassignificant,withcostsfalling70%between2011and2019,fromUSD5916/kWtoUSD1768/kW.Thisdrovedownthefield’sshareoftotalinstalledcostsfrom31%to28%.Thecostofthereceiverfellby71%overthe2011to2019period,fromUSD3069/kWtoUSD876/kW,withthereceiver’sshareoftotalcostsfallingfrom16%to14%.Balanceofplantandengineeringsawthelargestreduction,however,falling93%overthesameperiod,fromUSD3001/kWtoUSD219/kW.Thismadethisfactor’sshareoftotalcostsfallfrom16%tojust3%.ContingenciesremainanimportantoverallcostcomponentforSTs.Thisisdespitetheircostsfallingby42%between2011and2019,fromUSD1520/kWtoUSD878/kW.In2019,contingenciesforSTsmadeup14%ofoverallcosts.ForPTCplants,datafor2020putthatshareat8%.ContingenciesforSTsareoftenhigherperkilowatt,asexperiencewithSTsremainsrelativelylimited(althoughithasincreasedinrecentyears).However,thereisstillgreateruncertaintyoverthereplicabilityofdevelopmentandconstructionprocessesforSTsthanthereisforPTCplants.Thelatterhavealongercommercialtrackrecordandasignificantlylargernumberofinstalledprojects.Thismayalsobewhyowner’scostsforSTsfellbyonly12%between2011and2019,withtheirshareofoverallcostsincreasingto14%in2019(upfrom5%in2010).Between2010and2020,theweightedaveragetotalinstalledcostvalueforCSPplantsintheIRENARenewableCostDatabasefellbyaround50%toreachUSD5079/kW.ThisFigurethenfelltoUSD4274/kWin2022,whichrepresenteda58%declinefrom2010(Figure5.3).140RENEWABLEPOWERGENERATIONCOSTSIN2022tohhtohnostorageStorage(hours)tohCapacity(MW)≥SolartowerLinearFresnelParabolictroughUSDkWFigure5.3CSPtotalinstalledcostsbyprojectsize,collectortypeandamountofstorage,2010-2022Note:Onlyprojectsinthedatabasewithinformationavailableforallthevariablesdisplayedareshown.Datacanthereforedivergefromtheglobaldataset.Figure5.3alsoshowsthattotalinstalledcostsincreasedtoUSD9728/kWin2021,beforefallingbacktoUSD4274/kWin2022.Thistrendshouldbeinterpretedwithcare,however,asthe2021valuecorrespondstothatofthefirstsolarpowerplantdevelopedinLatinAmerica,whichwasinauguratedinJunethatyear.Takingthatvalueintoaccount,thetotalinstalledcostdeclinebetween2010and2021was4%.ThiswasdespitethefactthattheLCOEdeclineforthatperiodstayedatasimilarleveltothatrecordedbetween2010and2021,giventhehighcapacityfactoroftheChileanCerroDominadorproject,whichboasts17.5hoursofstorage.During2022,deploymentshiftedtoChina,andwithit'slowercostsstructuresawtheweightedaveragetotalinstalledcostvaluefalltoUSD4274/kW.DatafromtheIRENARenewableCostDatabaseshowthattotalinstalledcostsforCSPplantsdeclinedduringthelastdecade,evenasthesizeoftheseprojects’thermalenergystoragesystemsincreased.TotalinstalledcostsforCSPplantsfellby50%between2010and2020;thisoccurredevenasthesizeoftheseprojects’thermalenergystoragesystemsincreased141CONCENTRATINGSOLARPOWERDuring2018and2019,theinstalledcostsofCSPplantswithstoragewereatparorlowerthanthecapitalcostsofplantswithoutstoragecommissionedinthe2010to2014period–sometimesevendramaticallylower.Theprojectscommissionedin2018and2019andlistedintheIRENARenewableCostDatabasehadanaverageof7.4hoursofstorage.Thisis2.8timesmorethantheaveragestoragevalueforprojectscommissionedbetween2010and2014.Storagecontinuedtogrowafterthat,too.Forinstance,theweightedaveragestoragelevelforprojectscommissionedin2020and2021was13.8hours,whichwas85%higherthanthelevelin2018and2019.ThecapitalcostsforCSPprojectscommissionedin2020forwhichcostdataareavailableintheIRENARenewableCostDatabaserangedbetweenUSD4761/kWandUSD5713/kW.Thatyear,onlytwoprojectswerecompleted,however.BothwereinChinaandtotalled150MW.Sothedatareflectnationalcircumstances,muchastheyears2010to2012sawSpaindominateCSPdeploymentandthereforeCSPdata.ThetwoprojectscompletedinChinawerealsopartofaprogrammeof20pilotprojects.Theseweredesignedtotestarangeoftechnologyconceptsandgainexperienceinintegratingawiderangeoftechnologiesandplantconfigurationsintotheelectricitysystem.Theprogramme,launchedin2016andaimingtodevelop1.35GWofcapacity,initiallytargetedcompletionby2018,butundoubtedlythistimelinewastooambitious.WithweightedaveragetotalinstalledcostsofUSD5079/kWin2020,costswere31%lowerthantheweightedaverageofUSD7382/kWforprojectscommissionedin2019.During2018and2019,IRENA’sRenewableCostDatabaseshowsacapitalcostrangeofbetweenUSD3571/kWandUSD9699/kWforCSPprojectswithstoragecapacitiesofbetweenfourandeighthours.Inthesameperiod,thecostrangeforprojectswitheighthoursormoreofthermalstoragecapacitywasnarrower–betweenUSD4574/kWandUSD7774/kW.AerialPerspecytiveWorks©Gettyimages.com142RENEWABLEPOWERGENERATIONCOSTSIN2022CAPACITYFACTORSForCSP,thedeterminantsoftheachievablecapacityfactorforagivenlocationandtechnologyarethequalityofthesolarresourceandthetechnologicalconfiguration.CSPisdistinctiveinthatthepotentialtoincorporatelow-costthermalenergystoragecanincreasethecapacityfactor45andreducetheLCOE.Thisis,however,acomplexdesignoptimisationthatisdrivenbythedesiretominimisetheLCOEand/ormeettheoperationalrequirementsofgridoperatorsorshareholdersincapturingthehighestwholesaleprice.ThisoptimisationofaCSPplant’sdesignalsorequiresdetailedsimulations,whichareoftenaidedbytechno-economicoptimisationsoftwaretoolsthatrelyincreasinglyonadvancedalgorithms.Inrecentyears,advancedoptimisationtoolscaneasilyexploresimulationsthatconsiderthesite’ssolarresource,theproject’sstoragecapacityandthenecessarysolarfieldsizetominimiseLCOEandensureoptimalutilisationoftheheatgenerated.Thisisadelicatebalance,assmallerthanoptimalsolarfieldsizesresultinunder-utilisationofthethermalenergystoragesystemandtheselectedpowerblock.Alargerthanoptimalsolarfieldsize,however,wouldaddadditionalcapitalcosts,butincreasethecapacityfactor–albeitatthepotentialriskofheatgenerationbeingcurtailedattimes,duetolackofstorageand/orpowergenerationcapacity.Overthelastdecade,fallingcostsforthermalenergystorageandincreasedoperatingtemperatureshavebeenimportantdevelopmentsinimprovingtheeconomicsofCSP.Thelatteralsolowerthecostofstorage,ashigherheattransferfluid(HTF)temperaturesreducestoragecosts.ForagivenDNIlevelandplantconfigurationconditions,higherHTFtemperaturesallowforalargertemperaturedifferentialbetweenthe‘hot’and‘cold’storagetanks.Thismeansgreaterenergy(andhencestorageduration)canbeextractedforagivenphysicalstoragesize,oralternatively,lessstoragemediumvolumeisneededtoachieveagivennumberofstoragehours.Combined,thesefactorshaveincreasedtheoptimallevelofstorageatagivenlocationsince2010,helpingminimiseLCOE.Thesedrivershavecontributedtotheglobalweightedaveragecapacityfactorofnewly-commissionedplantsrisingfrom30%in2010to42%in2020–anincreaseof41%overthedecade.The5thand95thpercentilesofthecapacityfactorvaluesforprojectsintheIRENARenewableCostDatabasecommissionedin2019were22%and54%,respectively.In2020,therangeforbothprojectswasfrom40%to46%.TheexcellentsolarresourceinChile’sAtacamaDesert,thelocationoftheCerroDominadorCSPproject,meantaveryhighcapacityfactorvaluefor2021,at80%.In2022,aprojectlocatedinChinawith9hoursofstoragedrovethecapacityfactorto36%,avalueclosertothe2019level.TheincreasingcapacityfactorsforCSPplants,drivenbyincreasedstoragecapacity,canclearlybeseeninFigure5.4.Overtime,CSPprojectshavebeencommissionedwithlongerstoragedurations.45Uptoacertainlevel,giventhattherearediminishingmarginalreturns.143CONCENTRATINGSOLARPOWERCapacityfactorDNIbin(kWhmyear)nostoragetohtohtohhthpercentilethpercentileYearCapacity(MW)SolartowerLinearFresnelParabolictrough≥Figure5.4CapacityfactortrendsforCSPplantsbydirectnormalirradianceandstorageduration,2010-2022Source:IRENARenewableCostDatabaseandCSPGuru,2022,forDNIvalues.Forplantscommissionedfrom2016to2020,inclusive,aroundfour-fifthshadatleastfourhoursofstorageand39%hadeighthoursormore.Theimpactoftheeconomicsofhigherenergystoragelevelsisevidentinthatin2020,newly-commissionedplantshadaweightedaveragecapacityfactorof42%,withanaverageDNIthatwaslowerthanforplantscommissionedduringthe2010to2013period.Indeed,duringthatperiod,theweightedaveragecapacityfactorfornewly-commissionedplantswasbetween27%and35%.BoththeearlyperiodofCSPdevelopmentinSpainandthemorerecentoneinChinahavebeencharacterisedbysmall,50MWprojects.InChina’scase,thesehavepredominantlybeentechnologydemonstrationprojectsamong20initialpilotschemes.However,inordertounlockeconomiesofscale–andascompetitiveprocurementhasencouragedgreaterdeveloperchoiceinplantspecifications–averageprojectsizeshaverisenovertime.Itislikelythatfuturecommercialprojectswillgravitatetowardsthe100MWto150MWrange,whichrepresentstheeconomicoptimuminmostlocations.144RENEWABLEPOWERGENERATIONCOSTSIN2022CSPplantsarealsonowroutinelybeingdesignedtomeeteveningpeaksandovernightdemand.CSPwithlow-costthermalenergystoragecanintegratehighersharesofvariablesolarandwindpower,meaningthatwhileoftenunderrated,CSPcouldplayanincreasinglyimportantroleinthefuture.Therecentincreaseinstoragecapacityhasalsobeendrivenbydecliningcostsofthermalenergystorageasthemarkethasmatured.Thisistheresultofbothdecliningcapitalcostsandofhigheroperatingtemperatures,whichallowlargertemperaturedifferentialsinthemoltensaltstoragesystems,increasingtheenergystoredforthesamevolume.Theresulthasbeenanincreaseintheweightedaveragenumberofstoragehoursthroughtime.Thisrosemorethanthree-foldbetween2010and2020,from3.5hoursto11hours.TheCerroDominadorprojectinChilethatcameonlinein2021featuresthehighestknownstoragecapacityintheword,at17.5hours.In2022thisvaluewasninehours,aFigureclosertothe2019level(Figure5.5).AverageprojectsizeAveragestoragehoursMWStoragehoursFigure5.5AverageprojectsizeandaveragestoragehoursofCSPprojects,2010-2022Theglobalweightedaveragecapacityfactorofnewly-commissionedplantsincreasedfrom30%in2010to42%in2020–anincreaseof41%overthedecade145CONCENTRATINGSOLARPOWERAlthough,allelsebeingequal,ahigherDNIleadstoalargercapacityfactor,thereisamuchstrongercorrelationbetweencapacityfactorsandstoragehours.Thisis,however,onlyonepartoftheeconomicsofplantsathigherDNIlocations.HigherDNIsalsoreducethefieldsizeneededforagivenprojectcapacityandhencethesizeoftheinvestment(Figure5.6).Storage(hours)htohtohNostoragetohDNICapacityfactorHoursofstorageDirectnormalirradiance(kWhm/year)CapacityfactorFigure5.6Capacityfactors,storagehoursandthesolarresource,2010-2022Yet,technologyimprovementsandcostreductionsforthermalenergystoragealsomeanthathighercapacityfactorscanbeachievedeveninareaswithoutworldclassDNI.The2020datashowtheimpactofhigherstoragelevels,withnewly-commissionedplantsrecordingaweightedaveragecapacityfactorof42%thatyear,eventhoughtheaverageDNIin2020waslowerthanforplantscommissionedbetween2010and2013,inclusive.Duringthatearlierperiod,theweightedaveragecapacityfactorwasbetween27%and35%fornewlycommissionedplants.OPERATIONANDMAINTENANCECOSTSForCSPplants,all-inO&Mcosts,whichincludeinsuranceandotherassetmanagementcosts,aresubstantialcomparedtosolarPVandonshorewind.Theyalsovaryfromlocationtolocation,dependingondifferencesinirradiation,plantdesign,technology,labourcostsandindividualmarketcomponentpricing,whichislinkedtolocalcostdifferences.146RENEWABLEPOWERGENERATIONCOSTSIN2022Historically,thelargestindividualO&McostforCSPplantshasbeenexpenditureonreceiverandmirrorreplacements.Asthemarkethasmatured,however,experience–aswellasnewdesignsandimprovedtechnology–havehelpedreducefailureratesforreceiversandmirrors,drivingdownthesecosts.Inaddition,personnelcostsrepresentasignificantcomponentofO&M,withthemechanicalandelectricalcomplexityofCSPplantsrelativetosolarPV,inparticular,drivingthis.InsurancechargesalsocontinuetobeanimportantfurthercontributortoO&Mcosts.Thesetypicallyrangebetween0.5%and1%oftheinitialcapitaloutlay(afigurethatislowerthanthetotalinstalledcost).Withsomeexceptions,typicalO&McostsforearlyCSPplantsstillinoperationtodayrangefromUSD0.02/kWhtoUSD0.04/kWh.ThisislikelyagoodapproximationforthecurrentlevelsofO&Minrelevantmarketsforprojectsbuiltinandaround2010,globally.Thisisso,evenifitisbasedonananalysisrelyingonamixofbottom-upengineeringestimatesandbest-availablereportedprojectdata(IRENA,2018;Lietal.,2015;Turchi,2017;Zhou,XuandWang,2019).AnalysisbyIRENAundertakenincollaborationwiththeInstituteofSolarResearch(DasInstitutfürSolarforschungdesDeutschenZentrumsfürLuft-undRaumfahrt[DLR])shows,however,thatmorecompetitiveO&Mcostsarepossibleinarangeofmarkets(Table5.1).Inthese,projectsachievedfinancialclosurein2019and2020.TheO&McostsperkWhinmanyofthesemarketsarehighinabsoluteterms,comparedtosolarPVandmanyonshorewindfarms.However,theyareabout18%to20%oftheLCOEforcomparableprojectsinG20countries.Takingthisintoaccount,theLCOEcalculationsinthefollowingsectionreflectO&McostsintheIRENARenewableCostDatabasethatdeclinedfromacapacityweightedaverageofUSD0.037/kWhin2010toUSD0.022/kWhin2022(41%lowerthanin2010).Theweightedaveragevaluehasstayedflatsince2020.Table5.1All-in(insuranceincluded)O&McostestimatesforCSPplantsinselectedmarkets,2019-2020CountryParabolictroughcollectorsSolartower(2022USD/kWh)(2022USD/kWh)Argentina0.0280.026Australia0.0300.029Brazil0.0220.022China0.0240.020France0.0350.030India0.0170.017Italy0.0280.026Mexico0.0180.017Morocco0.0140.013RussianFederation0.0270.025SaudiArabia0.0130.012SouthAfrica0.0140.013Spain0.0270.025Türkiye0.0200.018UnitedArabEmirates0.0200.022UnitedStatesofAmerica0.0270.024147CONCENTRATINGSOLARPOWERLEVELISEDCOSTOFELECTRICITYWithtotalinstalledcosts,O&Mcostsandfinancingcostsallfallingascapacityfactorsrose,theLCOEforCSPfellsignificantlybetween2010and2022.Indeed,overthatperiod,theglobalweightedaverageLCOEofnewlycommissionedCSPplantsfellby69%,fromUSD0.380/kWhtoUSD0.118/kWh.Withdeploymentduringthe2010to2012periodbeingdominatedbySpain–andmostlycomprisedofPTCplant–theglobalweightedaverageLCOEbyprojectdeclinedonlyslightly,albeitwithinawideningrange,asnewprojectscameonline.Thischangedin2013,whenacleardownwardtrendintheLCOEofprojectsemergedasthemarketbroadened,experiencewasgainedandmorecompetitiveprocurementstartedtohaveanimpact.Ratherthantechnology-learningeffectsalonedrivinglowerprojectLCOEsfrom2013onward,theshiftindeploymenttoareaswithhigherDNIsduringtheperiod2013to2015alsoplayedarole(Lilliestametal.,2017).Intheperiod2016to2019,costscontinuedtofallandthecommissioningofprojectsinChinabecameevident,withprojectscommissionedtherein2018andbeyondachievingestimatedLCOEsofbetweenUSD0.08/kWhandUSD0.14/kWh.Incontrast,thecostsforprojectscommissionedin2018and2019inMoroccoandSouthAfricatendedtobehigher.tohhtohnostorageStorage(hours)tohCapacity(MW)≥LinearFresnelParabolictroughSolartowerUSDkWhFigure5.7LCOEforCSPprojectsbytechnologyandstorageduration,2010-2022148RENEWABLEPOWERGENERATIONCOSTSIN2022Forprojectscommissionedbetween2014and2017,theirlocationinplaceswithhigherDNIswasamajorcontributortoincreasedcapacityfactors(andthereforelowerLCOEvalues).TheweightedaverageDNIofprojectscommissionedduringthatperiod,ataround2600kWh/m2/year,was28%higherthanintheperiod2010to2013.Asalreadynoted,however,thiswasnottheonlydriverofLCOEtrends,astechnologicalimprovementssawamovetowardsplantconfigurationswithhigherstoragecapacities.CSPwithlow-costthermalenergystoragehasshownitcanplayanimportantroleinintegratinghighersharesofvariablerenewablesinareaswithgoodDNI.In2016and2017,onlyahandfulofplantswerecompleted,witharound100MWaddedineachyear.Theresultsforthesetwoyearsarethereforevolatileanddrivenbyspecificplantcosts.In2016,theincreaseinLCOEwasdrivenbythehighercostsoftheearlyprojectsinSouthAfricaandMoroccocommissionedthatyear.In2017,theglobalweightedaverageLCOEfellbacktothelevelsetin2014and2015.Newcapacityadditionsthenreboundedin2018and2019,withatleast600MWaddedineachyear.In2018,plantswerecommissionedinChina,MoroccoandSouthAfrica,withLCOEsrangingfromalowofUSD0.080/kWhinChina,toahighofUSD0.249/kWhinSouthAfrica.Incontrast,2019sawhigherLCOEs,astwodelayedIsraeliprojectscameonline.CoststhatyearrangedfromUSD0.113/kWhforaprojectinChinatoUSD0.430/kWhfortheIsraeliPTCproject.In2020,deploymentdidnotexceed150MW,thoughlowcapitalcostsfortheprojectsoccurringinChinapusheddowntheweightedaverageLCOEforthatyeartoUSD0.118/kWh.In2021,theLCOEvaluewas2%higherthanin2020,atUSD0.121/kWh–althoughthiswasstill68%lowerthanin2010.The2021figurewas,however,basedonaverythinmarket,asisthe2022figureofUSD0.118/kWh.Giventhis,Figure5.8unpacks45the68%declineinglobalweightedaverageLCOEofCSPovertheperiod2010to2020,showingitsmainconstituents.LCOETotalinstalledcostCapacityfactorO&MWACCLCOEUSDkWhFigure5.8ReductioninLCOEforCSPprojects,2010-2020,bysource45Thisreliesonasimpledecompositionanalysisthatchangesonevariablewhileholdingallothersconstant,thenapportionsthesevaluesasashareoftheactualtotalreductioninLCOEovertheperiod.Theresultsareindicativeonlyandshouldbetreatedwithcaution.149CONCENTRATINGSOLARPOWERAt64%,thelargestshareofthedeclinewastakenbythefallinthetotalinstalledcostofCSPplantsovertheperiod.Improvementsintechnologyandcostreductionsinthermalenergystorage–whichledtoprojectswithlongerstoragedurationbeingcommissionedin2020–ledtoanimprovementincapacityfactors.This,inturn,accountedfor17%ofthereductioninLCOEoverthe2010to2020period.LowerO&Mcostsaccountedfor10%ofthetotaldeclineinLCOEduringthattime,whilethereductionintheweightedaveragecostofcapitalaccountedfortheremaining9%.Theroleofincreasinglyexperienceddevelopersinreducingcostsateverystepofthedevelopment,constructionandcommissioningprocessalsoneedstobeacknowledged.Thissameanalysisyieldsquitedifferentresultsfortheperiod2010to2021,giventhehightotalinstalledcosts/highcapacityfactorstructureofthe2021projectinChile.Accountingforthisresultsinthecapacityfactorbeingthemajorcontributor(77%)tocostreductionbetween2010and2021.LowerO&Mcostsaccountforatenthofthereduction,whilereductionsintheglobalweightedaveragetotalinstalledcostsofnewlycommissionedCSPplantsaccountedfor7%.Improvementsintheweightedaveragecostofcapitalaccountfor6%ofthetotaldeclineinLCOEovertheperiod.IntheabsenceofstrongpolicysupportforCSP,themarketremainssmallandthepipelinefornewprojectsunambitious.Thisisdisappointing,giventheremarkablesuccessinreducingcostssince2010,despitejust6.4GWbeingdeployedgloballybytheendof2021.Giventhegrowthinthecompetitivenessofvariablerenewablessince2010,thevalueofCSP’sabilitytoprovidedispatchablepower24/7inareaswithhighDNIatreasonablecostisonlysettogrow.Greaterpolicysupportwouldbeinstrumentalinbringingcostsdownevenfurther–andinreducingoverallelectricitysystemcosts–byprovidingfirm,renewablecapacityandflexibilityservicestointegrateveryhighsharesofrenewables.chuyuss©Shutterstock.com06HYDROPOWERJuananBarrosMoreno©Shutterstock.com151HIGHLIGHTS•Theglobalweightedaveragelevelisedcostofelectricity(LCOE)ofnewlycommissionedhydropowerprojectswasUSD0.061/kilowatthour(USD/kWh)in2022–18%higherthantheUSD0.052/kWhrecordedin2021and45%higherthantheprojectscommissionedin2010(Figure6.1).•Despitethisincrease,in2022,96%ofthenewlydeployedcapacityofhydropowerprojectscommissionedthatyearhadanLCOElowerthanthecountry-orregion-specificweightedaveragecostofnewly-commissionedfossil-fuelfiredcapacity.•TheincreaseinLCOEsince2010hasbeendrivenbyrisinginstalledcosts,notablyinAsia.Thiswaslikelyduetoanincreaseinprojectsinlocationswithmorechallengingsiteconditionsandmorerecentsupplychaininflation,whichdroveupcosts.•In2022,theglobalweightedaveragetotalinstalledcostofnewlycommissionedhydroprojectsincreasedtoUSD2881/kilowatt(kW).Thiswashigherthanthe2021figureofUSD2299/kW.•Theglobalweightedaveragetotalinstalledcostin2022wasthehighestrecordedvalueyet.ThisincreasecamedespitethemajorityofnewcapacityadditionsoccurringinChina,whichadded13GWandgenerallyhaslower-than-averageinstalledcosts.However,2022wasalsocharacterisedbyanumberoflargeprojects,notablyinCanadaandLaoPeople’sDemocraticRepublic,withverylargecostoverruns.•Between2010and2022,theglobalweightedaveragecapacityfactorforhydropowerprojectscommissionedvariedbetweenalowof44%in2010-2011andahighof51%in2015.Forprojectscommissionedin2022,itwas46%.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure6.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforhydropower,2010-2022152RENEWABLEPOWERGENERATIONCOSTSIN2022Hydropowerisamatureandreliablerenewablegenerationtechnology.Itwasalsothemostwidelydeployedworldwidein2022,eventhoughitsshareofglobalrenewableenergycapacityhasbeenslowlydeclining.Indeed,between2010and2022,hydropower’ssharefellfrom72%to41%.Althoughthetotalglobalinstalledhydropowercapacity(excludingpumpedhydro)hadrisenfrom881GWto1256GWattheendof2022,itispossiblethatitwillbesurpassedbysolarPVbytheendof2023.Hydropowerprovidesalow-costsourceofelectricitywhilealso(especiallyiftheplantincludesreservoirstorage)providingasourceofflexibility.Thisenablestheplanttoprovideservicessuchasfrequencyresponse,blackstartcapabilityandspinningreserves.These,inturn,increaseplantviabilitybyincreasingassetownerrevenuestreams.Theyalsoenablebetterintegrationofvariablerenewableenergysourcesinordertomeetdecarbonisationtargets.Inadditiontothegridflexibilityserviceshydropowercanprovide,itcanalsostoreenergyoverweeks,months,seasonsorevenyears,dependingonthesizeofthereservoir.Inaddition,hydropowerprojectscombineenergyandwatersupplyservices.Thesecanincludeirrigationschemes,municipalwatersupply,droughtmanagement,floodcontrol,andnavigationandrecreation–allofwhichprovidelocalsocio-economicbenefits.Indeed,insomecasesthehydropowercapabilityisdevelopedbecauseofanexistingneedtomanageriverflows,withhydropowerincorporatedintothedesign.Theseadditionalservicesincreasetheviabilityofhydropowerprojects.YettheLCOEanalysiscarriedoutinthisreportdoesnotcalculatethevalueofanyservicesbeyondelectricitygenerationthatarenotspecifictothesiteandpowermarket.TOTALINSTALLEDCOSTSTheconstructionworkassociatedwithahydropowerprojectvariesdependingonthesizeandscopeoftheproject,aswellasotherpropertiesinfluencedbytheproject’slocation.Therearealsokeytechnicalcharacteristicswhichdeterminethetypeandsizeofturbineused.Amongotherfactors,thesekeyparametersinclude:the‘head’(thewaterdroptotheturbinedeterminedbythelocationanddesign);thereservoirsize;theminimumdownstreamflowrate;andseasonalinflows.Inaddition,hydropowerplantsfallintothreecategories:•Reservoir-orstorage-hydropower,whichprovidesadecouplingofhydroinflowsfromtheturbines.Waterstorageservesasabufferthatdamscanusetostoreorregulatehydroinflows,decouplingthetimeofgenerationfromtheinflow.•Run-of-riverhydropower,inwhichhydroinflowsmainlydeterminegenerationoutput,becausethereislittleornostoragetoprovideabufferforthetimingandsizeofinflows.153HYDROPOWER•Pumpedstoragehydropower,inwhichthereareupperandlowerstoragereservoirs.Electricityisusedtopumpwaterfromthelowertotheupperreservoirintimesoflowdemand(mostlyduringoff-peakperiods)andisthenreleasedintimesofhighelectricitydemand.Pumpedhydroismostlyusedforpeakgeneration,gridstabilityandancillaryservices.Itcanalsobeusedtointegratemorevariablerenewablesbystoringabundantrenewablegenerationthatisnotneededduringperiodsoflowelectricitydemand.Thischaptercoversthecostsofreservoirandrun-of-riverhydropowerandexcludespumpedstoragecostsfromalldata,givenitisastroagetechnology,notageneratingtechnology.Hydropowerisacapitalintensivetechnology,withprojectsoftenrequiringlongleadtimesfordevelopment,permitting,sitedevelopment,constructionandcommissioning.Suchprojectsarelarge,complexcivilengineeringworksrequiringextensivesitesurveys,collectionofinflowdata(ifnotalreadyavailable),andenvironmentalassessments.Theseoftenhavetobecompletedbeforesiteaccessandpreparationcanbeundertaken.Thisalltakesadditionaltime,especiallywithlargecapacityprojects.Overall,therearetwomajorcostscomponentsforhydropowerprojects:•Thecivilworksforthehydropowerplantconstruction,whichincludeanyinfrastructuredevelopmentrequiredtoaccessthesite,gridconnection,worksassociatedwithmitigatingidentifiedenvironmentalissues,andtheprojectdevelopmentcosts.•Theprocurementcostsrelatedtoelectro-mechanicalequipment.Civilconstructionwork(whichincludesthedam,tunnels,canalandconstructionofthepowerhouse)usuallymakesupthelargestshareoftotalinstalledcostsforlargehydropowerplants(Table6.1).Followingthis,costsforfittingoutthepowerhouse(includingshaftsandelectro-mechanicalequipment,inspecificcases)arethenextlargestcapitaloutlay,accountingforaround30%oftotalcosts.Thelongleadtimesforthesetypesofhydropowerprojects(7‑9yearsormore)meanthatownercosts(includingprojectdevelopmentcosts)canalsobeasignificantportionoftheoverallcosts,duetotheneedforworkingcapitalandinterestduringconstruction.Additionalitemsthatcanaddsignificantlytooverallcostsincludethepre-feasibilityandfeasibilitystudies,consultationswithlocalstakeholdersandpolicymakers,environmentalandsocio-economicmitigationmeasuresandlandacquisition.Incertaincircumstances,however,costsharescanvarywidely.Thisisespeciallytrueifaprojectisaddingcapacitytoanexistinghydropowerdamorriverscheme,orwherehydropowerisbeingaddedtoanexistingdamthatwasdevelopedwithoutelectricitygenerationinmind.Thetotalinstalledcostsforthemajorityofhydropowerprojectscommissionedbetween2010and2022rangefromalowofaroundUSD500/kWtoahighofaroundUSD5000/kW(Figure6.2).Itisnotunusual,however,tofindprojectsoutsidethisrange.Forinstance,addinghydropowercapacitytoanexistingdamthatwasbuiltforotherpurposesmayhavecostsaslowasUSD450/kW,whileremotesites,154RENEWABLEPOWERGENERATIONCOSTSIN2022Table6.1Totalinstalledcostbreakdownbycomponentandcapacity-weightedaveragesfor25hydropowerprojectsinChina,IndiaandSriLanka,2010-2016,andEurope,2021China,IndiaandSriLanka2010-2016ProjectcomponentShareoftotalinstalledcosts(%)MinimumWeightedaverageMaximumCivilworks174565Mechanicalequipment183366Planningandother61629Gridconnection1617Costofland138Europe2021TypeofHydroShareoftotalinstalledcosts(%)CivilMechanicalElectricalLarge-scaleReservoirStorage(highhead)701020Large-scaleRunofriver(lowhead)503020Small-scaleRunofriver503020Pumpedstorage30-5020-3030-40Source:IRENARenewableCostDatabaseandInternationalHydropowerAssociation(IHA).withpoorinfrastructureandlocatedfarfromexistingtransmissionnetworks,cancostsignificantlymorethanUSD5000/kW,duetohigherlogistical,civilengineeringandgridconnectioncosts.Between2010and2022,theglobalweightedaveragetotalinstalledcostofnewhydropowerrosefromUSD1407/kWin2010toUSD2881/kWin2022.Afterrisingrelativelysteadilybetween2010and2017,in2018theglobal-weightedaveragetotalinstalledcostdroppedtoUSD1610/kW,onlytoseeaconsistentrisethereafter.Theyear2022representedanew,highercostlevel,withincreasesdrivennotjustbytheshareofdeploymentindifferentregions,butalsoanupwardtrendinproject-specificcosts.MichelleMealing©Shutterstock.com155HYDROPOWERCapacity(MW)1≥USDkWFigure6.2Totalinstalledcostsbyprojectandglobalweightedaverageforhydropower,2010-2022TheincreasehasbeendrivenbyrisinginstalledcostsforprojectsinAsia,Europe,andNorthandSouthAmerica.Thedataappeartosuggestthatbehindthisisthefactthatmanycountriesintheseregionsarenowdevelopinghydropowerprojectsatlessidealsites.Suchprojectsmaybelocatedfurtherfromexistinginfrastructure,orthetransmissionnetwork,resultinginhigherlogisticalcosts,aswellasboostinggridconnectioncosts.Theymayalsobeinlocationswithmorechallenginggeologicalconditions,requiringmoreextensiveandexpensiveworkfortheconstructionofthedamitself.Thisresults,overall,inhigherinstallationcosts.Theglobalweightedaveragetotalinstalledcosttrendsforlargehydro(greaterthan10MWincapacity)andsmallhydro(10MWorless)suggestthataverageinstalledcostsforsmallhydrohaveincreasedatafasterratethanforlargehydroprojects(Figure6.3).Thistrendremainstobeconfirmed,however,giventhatdataintheIRENARenewableCostDatabaseforsmallhydropowerprojectsarenoticeablythinnerfortheyears2015to2018inclusive,andwhilebetterinrecentyears,remainsbelowwhatwasavailableintheperiodupto2015.ThefulldatasetofhydropowerprojectsintheIRENARenewableCostDatabasefortheyears2000to2022(Table6.2)doesnotsuggestthattherearestrongeconomiesofscaleinhydropowerprojectsthatarelessthanaround450MWinsize.Thenumberofprojectsisnotevenlydistributed,however,andcouldlikelysupportdifferenthypothesesbyregion.Thereareclearlyeconomiesofscaleforprojectsabove700MW,buttheseonlyrepresentabout6%ofthedatacapacityforhydropowerfortheperiodofcommissioningbetween2000and2022.156RENEWABLEPOWERGENERATIONCOSTSIN2022USDkWSmall(MW)Large(MW)Figure6.3Totalinstalledcostsforsmallandlargehydropowerprojectsandtheglobalweightedaverage,2010-2022Figure6.3presentsthedistributionoftotalinstalledcostsbycapacityforsmallandlargehydropowerprojectsintheIRENARenewableCostDatabase.Astheglobalweightedaveragehasrisenoverthetwoperiods,itispossibletoseethereasonforthisinthelargehydropowerdata.NicoElNino©Shutterstock.com157HYDROPOWERTable6.2Totalinstalledcostsforhydropowerbyweightedaverageandcapacityrange,2000-20222000-2022Capacity(MW)5thpercentile(2022USD/kW)weightedaverage(2022USD/kW)95thpercentile(2022USD/kW)0-508951753382251-10092119784052101-15099018743750151-20089618493354201-25097020573761251-30089622324140301-35099821134788351-40073717173358401-450128121353278451-500107717693067501-550119324644697551-600145019582774601-650114615533587651-70085221272850701-750103616402234751-800114616842377801-8501267395211999851-900103817241989901-95070411781432951-1000n.a.23862386Note:n.a.=datanotavailable.PercentageofcapacityLarge(MW)---Small(MW)-USDkW(binsofUSDkW)USDkW(binsofUSDkW)PercentageofcapacityPercentageofcapacityPercentageofcapacityFigure6.4Distributionoftotalinstalledcostsoflargeandsmallhydropowerprojectsbycapacity,2010-2015and2016-2022158RENEWABLEPOWERGENERATIONCOSTSIN2022Comparedtotheperiod2010to2015,thedatafor2016to2022showareductionintheshareofnewlycommissionedprojectsintheUSD600/kWtoUSD1200/kWrange.Theyalsoshowanincreaseinthecapacityofprojectsabovethat.Theshiftinthedistributionofsmallhydropowerprojectsismorepronounced,buthasalsobeenaccompaniedbyareductionintheskewofthedistributionofprojects.Therehas,however,alsobeengrowthinthetailofmoreexpensiveprojects,comparedtothe2010to2016period.Forthe2016to2022period,thetotalinstalledcostsforlargehydropower(morethan10MWincapacity)werehighestintheNorthAmericaandAfricaregions.Inthesetwoareas,therewereweightedaverageinstalledcostsofUSD5825/kWandUSD2604/kW,respectively.ThenexthighesttotalinstalledcostwasinEurope,wheretheweightedaveragewasUSD2101/kW.ThelowestweightedaverageinstalledcostforlargehydropowerwasinIndia–atUSD1525/kW–andOtherAsia,whereitwasUSD1877/kW(Figure6.5).InBrazil,theweightedaverageinstalledcostwasUSD1639/kW,whileinChinaitwasUSD1860/kW.IntheMiddleEast,thisfigurewasUSD1913/kW,whileinEurasiaitwasUSD2344/kW.InOtherSouthAmerica,CentralAmericaandtheCaribbeanandOceaniaregions,theweightedaverageinstalledcostswereUSD2537/kW,USD3826/kWandUSD4417/kW,respectively.Unsurprisingly,regionswithhighercoststendedtohavelowerdeploymentrates.Duetotheverysite-specificdevelopmentcostsofhydropowerprojects,therangeininstalledcostsforhydropowertendstobewide.Partofthisisduetovariationsinthecostofdevelopment,civilengineering,logisticsandgridconnection.Somevariationmayalsobedrivenbythenon-energyrequirementsintegratedintodifferentprojects.Thesecaninclude,forexample,obligationstoprovideotherservices,suchaspotablewater,floodcontrol,irrigationandnavigation.Theseservicesareincludedinthehydropowerprojectcosts,butaretypicallynotremunerated.ItisthereforeworthnotingthatthesebenefitsarenotincludedintheLCOEcalculationsinthischapter.Acomparisonbetweeninstalledcostsforlargeandsmallhydroplantsshowsthatsmallhydroplantsgenerallyhavebetween20%and80%higherinstalledcostswhencomparedtolargehydroplants.TheexceptionsareintheCentralAmericaandtheCaribbeanandOceaniaregions.Inthesetwoareas,installedcostsarehigherforlargehydropowerplantsasaresultoftherelativelysmallnumberoflargeprojectsbeingdeveloped(Figure6.6).Between2016and2022,thetotalinstalledcostforsmallhydropowerprojectsinIndiawasUSD1995/kW,whichissomewhathigherthanduringtheperiod2010to2015.ThetotalinstalledcostsofsmallhydropowerinBrazilaveragedUSD2368/kWintheperiod2016to2022,afigure8%lowerthanintheperiod2010to2015.TheweightedaverageinstalledcostforsmallhydropowerinChinawasUSD1299/kWovertheperiod2010to2015.Duringtheperiod2016to2022,thiscostwentuptoUSD1764/kW.IntheCentralAmericaandtheCaribbean,OceaniaandOtherSouthAmericaregions,dataforsmallhydropowerprojectscommissionedintheperiod2016to2022aresparse.Resultsarethereforeonlypresentedfortotalinstalledcostsduringthe2010to2015period.159HYDROPOWERAfricaBrazilCentralAmericaandtheCaribbeanChinaEurasiaEuropeIndiaMiddleEastNorthAmericaOceaniaOtherAsiaOtherSouthAmericaUSDkW------------------------Capacity(MW)≤≥Figure6.5Totalinstalledcostbyprojectandcapacity-weightedaveragesforlargehydropowerprojectsbycountry/region,2010-2022≤Capacity(MW)-----------------AfricaBrazilCentralAmericaandtheCaribbeanChinaEurasiaEuropeIndiaOceaniaOtherAsiaOtherSouthAmericaUSDkWFigure6.6Totalinstalledcostsbyprojectandcapacity-weightedaveragesforsmallhydropowerprojectsbycountry/region,2010-2022Duringthattime,theweightedaverageinstalledcostforsmallhydropowerinOceaniawasUSD3729/kW,whileinCentralAmericaandtheCaribbeanitwasUSD3244/kWandinOtherSouthAmerica,USD3116/kW.160RENEWABLEPOWERGENERATIONCOSTSIN2022CAPACITYFACTORSBetween2010and2022,theglobalweightedaveragecapacityfactorofnewlycommissionedhydropowerprojectsofallsizesincreasedfrom44%to46%.Theaverageincreaseovertheperiod,however,was47%,withthe5thand95thpercentilesofprojectswithinthe23%to80%range.Thiswidespreadistobeexpected,giventhateachhydropowerprojecthasverydifferentsitecharacteristics.Inaddition,lowcapacityfactorsaresometimesadesignchoice,withturbinessizedtohelpmeetpeakdemandandprovideotherancillarygridservicesandnon-energyservices,likefloodcontrol,wherewaterlevelsmaybekeptdeliberatelylowatcertaintimesoftheyear.Theaveragecapacityfactorforprojectscommissionedbetween2010and2022was47%forlargehydroprojectsand53%forsmall,withmostprojectsintherangeof25%to80%(Tables6.3and6.4).EuropeandNorthAmericawerenotableexceptions,havingarangeofprojectswithcapacityfactorslowerthan20%,aswereBrazilandOtherSouthAmerica,whichhadarangeofprojectswithcapacityfactorsexceeding80%.Between2010and2022,theannual,globalweightedaveragecapacityfactorsofthe5thpercentileoflargehydropowerprojectsrangedfromalowof23%in2017,tohighsof35%in2019and2022.Forthe95thpercentile,thefigurerangedfromalowof66%in2010toahighof80%in2015.Thefigurefor2022was67%.Between2010and2021,theglobalweightedaveragecapacityfactorofnewly-commissionedsmallhydropowerprojectsincreasedfrom48%to57%.Excludingtheyears2017and2018,forwhichthereisalackofdata,between2010and2022theannual,globalweightedaveragecapacityfactorsofthe5thpercentileofsmallhydropowerprojectsrangedfromalowof28%–in2021–toahighof39%in2016.Forthe95thpercentile,thesecapacityfactorsrangedfromalowof67%in2011toahighof81%in2016.IntheIRENAdatabase,thereisoftenasignificantregionalvariationintheweightedaveragecapacityfactor.Tables6.3and6.4representhydropowerprojectcapacityfactorsandcapacityweightedaveragesforlargeandsmallhydropowerprojectsbycountryandregion.Between2010and2015,averagecapacityfactorsfornewly-commissionedlargehydropowerprojectswerehighestinBrazilandOtherSouthAmerica,with61%and62%,respectively.Between2015and2022,OtherSouthAmericamaintainedthehighestaveragecapacityfactor,at59%,followedbyNorthAmerica,with55%.Meanwhile,between2010and2015,NorthAmericarecordedthelowestaveragecapacityfactorfornewly-commissionedlargehydropowerprojects,with37%,whilebetween2016and2023,Europehadthelowestrecordedaverage,at33%.Smallhydropowerprojects(lessthan10MW)showedasmallerrangeofcountry-level,weightedaveragevariation(Table6.4).Forthese,therewerecountry-levelaveragelowsof46%and40%inChina,duringtheperiods2010to2015and2016to2022,respectively.Similarly,weightedaveragecapacityfactorsfornewly-commissionedsmallhydropowerprojectsbetween2010and2015werehighestinOtherSouthAmericaandBrazil,with65%and63%,respectively.161HYDROPOWERTable6.3Hydropowerprojectweightedaveragecapacityfactorsandrangesforlargehydropowerprojectsbycountry/region,2010-20222010-20152016-20225thpercentile(%)Weightedaverage(%)95thpercentile(%)5thpercentile(%)Weightedaverage(%)95thpercentile(%)Africa284771345178Brazil516180394662CentralAmerica274863335155China314657374654Eurasia284361294266Europe144170163359India294763214259NorthAmerica183778355572Oceania253847n.a.n.a.n.a.OtherAsia374665384974OtherSouthAmerica466285465979Note:n.a.=datanotavailable.Table6.4Hydropowerprojectweightedaveragecapacityfactorsandrangesforsmallhydropowerprojectsbycountry/region,2010-20222010-20152016-20225thpercentile(%)Weightedaverage(%)95thpercentile(%)5thpercentile(%)Weightedaverage(%)95thpercentile(%)Africa335668515665Brazil426388495459CentralAmerica455975n.a.n.a.n.a.China334660384043Eurasia445874435871Europe234870284366India285071395561OtherAsia375079365676OtherSouthAmerica436582n.a.3737Note:n.a.=datanotavailable.Between2015and2022,duetothelimitednumberofnewlycommissionedsmallhydropowerprojectsinthedatabaseforOtherSouthAmerica,thisregion’sweightedaveragecapacityfactorwasconsiderednotrepresentative.Eurasiashowedthehighestweightedaveragecapacityfactorforthisperiod,with58%,followedbyOtherAsiaandAfrica,withafactorof56%each,whileweightedaveragecapacityfactorinBrazildroppedto54%.162RENEWABLEPOWERGENERATIONCOSTSIN2022OPERATIONANDMAINTENANCECOSTSAnnualoperationandmaintenance(O&M)costsareoftenquotedasapercentageoftheinvestmentcostperkWperyear,withtypicalvaluesrangingfrom1%to4%.IRENApreviouslycollectedO&Mdataon25projects(IRENA,2018)andfoundaverageO&Mcostsvariedbetween1%and3%oftotalinstalledcostsperyear,withanaveragethatwasslightlylessthan2%.LargerprojectshaveO&Mcostsbelowthe2%average,whilesmallerprojectsapproachthehigherendoftherange,orhaveO&Mcostshigherthantheaverage.Table6.5presentsthecostdistributionofindividualO&Mitemsinthesample.Ascanbeseen,operationsandsalariestakethelargestslicesoftheO&Mbudget.Maintenancevariesfrom20%to61%oftotalO&Mcosts,whilesalariesvaryfrom13%to74%.Materialsareestimatedtoaccountforaround4%(Table6.5).TheInternationalEnergyAgency(IEA)assumesO&Mcostsof2.2%forlargehydropowerprojectsand2.2%to3%forsmallerprojects,withaglobalaverageofaround2.5%(IEA,2010).Thiswouldputlarge-scalehydropowerplantsinasimilarrangeofO&Mcostsasthoseforwind,whenexpressedasapercentageoftotalinstalledcosts,althoughnotaslowastheO&Mcostsforsolarphotovoltaic(PV).Whenaseriesofplantsareinstalledalongariver,centralisedcontrol,remotemanagementandanoperationsteamdedicatedtomanagingthechainofstationscanalsoreduceO&Mcoststomuchlowerlevels.Othersources,however,quotelowerorhighervalues.Foraconventional,500MWhydropowerplantcommissionedin2020,theEnergyInformationAgency(EIA),forexample,assumes0.06%oftotalinstalledcostsasfixedannualO&Mcosts,alongwithUSD0.003/kWhasvariableO&Mcosts(EIA,2017).Otherstudies(Greenpeace,2015)indicatethatfixedO&Mcostsrepresent4%ofthetotalcapitalcost.Thisfiguremayrepresentsmall-scalehydropower,withlargehydropowerplantshavingsignificantlylowerO&Mcosts.AnaveragevalueforO&Mcostsof2%to2.5%isconsideredthenormforlarge-scaleprojects(IPCC,2011),whichisequivalenttoaveragecostsofbetweenUSD20/kW/yearandUSD60/kW/yearforanaverageproject,byregion,intheIRENARenewableCostDatabase.O&Mcostsusuallyincludeanallowancefortheperiodicrefurbishmentofmechanicalandelectricalequipment,suchasturbineoverhaul,generatorrewindingandreinvestmentsincommunicationandcontrolsystems.Yet,theyusuallyexcludemajorrefurbishmentsoftheelectro-mechanicalequipment,ortherefurbishmentofpenstocks,tailracesandotherdurableitems.Replacementoftheseisinfrequent,withdesignlivesof30yearsormoreforelectro-mechanicalequipmentand50yearsormoreforpenstocksandtailraces.Thismeansthattheoriginalinvestmenthasbeencompletelyamortisedbythetimetheseinvestmentsneedtobemade.Therefore,theyarenotincludedintheLCOEanalysispresentedhere.Theymay,however,representaneconomicopportunitybeforethefullamortisationofthehydropowerproject,inordertoboostgenerationoutput.163HYDROPOWERLEVELISEDCOSTOFELECTRICITYHydropowerhashistoricallyprovidedthebackboneoflow-costelectricityinasignificantnumberofcountriesaroundtheworld.TheserangefromNorwaytoCanada,NewZealandtoChina,andParaguaytoBrazilandAngola–tonamejustafew.Investmentcostsarehighlydependentonlocationandsiteconditions,however,whichexplainsthewiderangeofplantinstalledcostsandalsomuchofthevariationinLCOEbetweenprojects.Itisalsoimportanttonotethathydropowerprojectscanbedesignedtoperformverydifferentlyfromeachother,whichcomplicatesasimpleLCOEassessment.Asanexample,aplantwithalowinstalledelectricalcapacitycouldruncontinuouslytoensurehighaveragecapacityfactors,butattheexpenseofbeingabletorampupproductiontomeetpeakdemandloads.Alternatively,aplantwithahighinstalledelectricalcapacityandlowcapacityfactorwouldbedesignedtohelpmeetpeakdemandandprovidespinningreserveandotherancillarygridservices.Thelatterstrategywouldinvolvehigherinstalledcostsandlowercapacityfactors,butwheretheelectricitysystemneedstheseservices,hydropowercanoftenbethecheapestandmosteffectivesolutionfortheseneeds.Thestrategypursuedineachcasewilldependonthecharacteristicsofthesiteinflowsandtheneedsofthelocalmarket.Thisisbeforetakingintoaccounttheincreasingvalueofhydropowersystemswithsignificantreservoirstorage,whichcanprovideverylowcostandlong-termelectricitystoragetohelpfacilitatethegrowingshareofvariablerenewableenergy.In2022,theglobalweightedaveragecostofelectricityfromhydropowerwasUSD0.061/kWh,up56%fromtheUSD0.039/kWhrecordedin2011.Theglobalweightedaveragecostofelectricityfromhydropowerprojectscommissionedintheyears2010to2015averagedUSD0.042/kWh.ThisincreasedtoanaverageofUSD0.051/kWhforprojectscommissionedovertheyears2016to2022.Table6.5HydropowerprojectO&Mcostsbycategoryfromasampleof25projectsProjectcomponentShareoftotalO&Mcosts(%)MinimumWeightedaverageMaximumOperationcosts205161Salary133974Other51628Material344164RENEWABLEPOWERGENERATIONCOSTSIN2022Despitetheseincreasesthroughtime,however,96%ofthehydropowerprojectscommissionedin2022hadanLCOEwithinorlowerthantherangeofnewlycommissionedfossilfuel-firedcapacitycost.Thiswasbeforeconsideringthatasignificantproportionofthoseprojectswithcostsabovethelowestfossilfuelcostmayhavebeendeployedinremoteareas.Intheselocations,hydropowerwasstillthecheapestsourceofnewelectricity,giventheextensiveuseofsmallhydropower,inparticular.Suchprojectscanprovidelow-costelectricityinremotelocationsandincreaseoverallelectrification.Theweightedaveragecountry/regionalLCOEofhydropowerprojects,largeandsmall,intheIRENARenewableCostDatabasereflectsthevariationinsite-specificandcountry-specificprojectinstalledcostsandcapacityfactors.Thefiguresforprojectsbycountrycommissionedin2022rangefromalowofUSD0.016/kWhinNorwayfora47MWprojecttoahighofUSD0.225/kWhfora200MWCanadianprojectthatranovertimeandbudgettargets.Figures6.7and6.8presenttheLCOEsoflargeandsmallhydropowerprojectsandthecapacityweightedaveragesbycountry/region.Forlargehydropowerprojects,anumberofcountries/regionssawanincreaseintheweightedaverageLCOEbetweentheperiods2010to2015and2016to2022.TheexceptionswereCentralAmericaandtheCaribbean,Europe,IndiaandOtherAsia,wheretheweightedaverageLCOEdecreased.Meanwhile,Chinasawa23%increaseintheweightedaverageLCOEbetweentheperiods2010to2015and2016to2022.SmallhydropowerprojectsshowedadecreaseintheweightedaverageLCOEinAfrica,Brazil,Eurasia,EuropeandIndiabetweentheperiods2010to2015and2016to2022.Therewas,however,adifferenttrendinChinaandOtherAsia,wheretheweightedaverageLCOEincreased.Forsmallhydro,theavailabledatawereinsufficientforCentralAmericaandtheCaribbean,andnon-representativeforOtherSouthAmerica,sothetrendforweightedaverageLCOEforsmallhydroprojectsinthoseregionscannotbecalculatedaccurately.leezsnow©Gettyimages.com165HYDROPOWERUSDkWh----------------AfricaBrazilCentralAmericaandtheCaribbeanChinaEurasiaEuropeIndiaOtherAsiaOtherSouthAmericaCapacity(MW)≤Figure6.8SmallhydropowerprojectLCOEandcapacity-weightedaveragesbycountry/region,2010-2022USDkWh------------------------AfricaAsiaBrazilCentralAmericaandtheCaribbeanChinaEurasiaEuropeIndiaMiddleEastNorthAmericaOceaniaOtherAsiaOtherSouthAmericaCapacity(MW)≥Figure6.7LargehydropowerprojectLCOEandcapacity-weightedaveragesbycountry/region,2010-202207GEOTHERMALVasilyGureev©Shutterstock.com167HIGHLIGHTS•Worldwide,around181megawatts(MW)ofnewgeothermalpowergenerationcapacitywascommissionedin2022.Thiswaslowerthanthe279MWaddedin2021.•Theglobalweightedaveragelevelisedcostofelectricity(LCOE)oftheprojectscommissionedin2022wasUSD0.056/kilowatthour(kWh).ThiswasnoticeablydownfromthefigureofUSD0.072/kWhrecordedin2021andthesecondlowestvaluesince2010.•Newcapacityadditionsin2022werejustoveraquarterofthedecade’srecorddeploymentin2015,when661MWwascommissioned.Infact,2022sawthelowestannualdeploymentsince2011.•Thelowdeploymentrateforgeothermalmeansthatweightedaveragecostsandperformancearebeingdeterminedbyonlyahandfulofplantseachyear.•In2022,theglobalweightedaveragetotalinstalledcostofthetenplantsinIRENA’sdatabasewasUSD3478/kilowatt(kW).ThiswaslowerthantherecenthighofUSD4300/kWrecordedin2021,andlowerthanthevaluesoverthepastdecade.Thetotalinstalledcostsofthetenprojectscommissionedin2022rangedfromalowofUSD2300/kWtoahighofUSD4812/kWfora55MWplant.•Geothermalplantsaretypicallydesignedtorunasoftenaspossibletomaintainconstantflowsfromthereservoirandtoprovidepoweraroundtheclock.In2022,theglobalweightedaveragecapacityfactorfornewlycommissionedplantswas85%.Thiswasinlinewithcapacityfactorfiguresrecordedsince2010.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure7.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforgeothermal,2010-2022168RENEWABLEPOWERGENERATIONCOSTSIN2022INTRODUCTIONAttheendof2022,geothermalpowergenerationstationsaccountedfor0.4%oftotalinstalledrenewablepowergenerationcapacity,worldwide,withatotalinstalledcapacityofaround14.9gigawatts(GW).Cumulativeinstalledcapacityattheendof2022was45%higherthanin2010.Thiscapacityismostlylocatedinactivegeothermalareas.ThecountrieswiththelargestinstalledcapacitiesincludeIndonesia,Italy,Kenya,Mexico,NewZealand,thePhilippines,TürkiyeandtheUnitedStates.ThebestgeothermalresourcesarefoundinactivegeothermalareasonornearthesurfaceoftheEarth’scrust.Thekeyadvantageoftheseresourcesisthattheycanbeaccessedatlowercostthantheevenlydistributedheatavailableatgreaterdepthseverywhereelseontheplanet.Inactivegeothermalareas,shallowdrillingintotheEarth’ssurfacecancheaplytapintonaturallyoccurringsteamorhotwater,whichcanthenbeusedtogenerateelectricityinsteamturbinesand/orprovideheattohomesorindustry.Geothermalresourcesconsistofthermalenergy,storedasheatintherocksoftheEarth’scrustandinterior.Atshallowdepths,fissurestodeeperdepthsinareassaturatedwithwaterwillproducehotwaterand/orsteamthatcanbetappedforelectricitygenerationatrelativelylowcost.Theseareas,withhigh-temperaturewaterorsteamatornearthesurface,arecommonlyreferredtoas“active”geothermalareas.Wherethisisnotthecase,geothermalenergycanstillbeextractedbydrillingtodeeperdepthsandinjectingwaterintothehotareathroughwells–thusharnessingtheheatfoundinotherwisedryrocks.Geothermalisamature,commerciallyproventechnology.Itcanprovidelow-cost,always-oncapacityingeographieswithverygoodtoexcellenthigh-temperatureconventionalgeothermalresourcesclosetotheEarth’ssurface.Thedevelopmentofunconventionalgeothermalresources,however,usingtheenhancedgeothermalorhotdryrocksapproach,ismuchlessmature.Inthisinstance,projectscomewithcoststhataretypicallysignificantlyhigherduetothedeepdrillingrequired,renderingtheeconomicsofsuchinitiativescurrentlymuchlessattractive.Researchanddevelopmentintomoreinnovative,low-costdrillingtechniquesandadvancedreservoirstimulationmethodologiesareneeded.Thiswouldhelplowerdevelopmentcostsandrealisethefullpotentialofenhancedgeothermalresourcesbymakingthemmoreeconomicallyviable,butdevelopmentwouldlikelyalwaysberiskierthaninareaswithactiveresources.Giventhesomewhatuniquenatureofgeothermalresources,geothermalpowergenerationisverydifferentinnaturecomparedtootherrenewablepowergenerationtechnologies.Indeed,developingageothermalprojectpresentsauniquesetofchallengeswhenitcomestoassessingtheresourceandhowthereservoirwillreactonceproductionstarts.Subsurfaceresourceassessmentsandreservoirmappingareexpensivetoconduct.Oncecompleted,theymustbeconfirmedbytestwellsthatallowdeveloperstobuildmodelsofthereservoir’sextentandflowandhowitwillreacttotheextractionofwaterandsteamforpowergeneration.169GEOTHERMALMuch,however,willremainunknownabouthowthereservoirwillperformandhowbesttomanageitovertheoperationallifeoftheprojectuntilactualoperationalexperienceisgained.Inadditiontoincreasingdevelopmentcosts,theseissuesgivegeothermalprojectsverydifferentriskprofilescomparedtootherrenewablepowergenerationtechnologies,intermsofbothprojectdevelopmentandoperation.Oneofthemostimportantchallengesfacedwhendevelopinggeothermalpowergenerationprojectsliesintheavailabilityofcomprehensivegeothermalresourcemapping.Whereitisavailable,thisreducestheuncertaintiesthatdevelopersfaceduringthefieldexplorationperiod,whichinturnalsopotentiallyreducesthedevelopmentcost.Thisisbecausepoorerthanexpectedresultsduringtheexplorationphase–suchaslowerthanprojectedflowratesorreservoirpermeability–mightrequireadditionaldrillingorthedeploymentofwellsoveramuchlargerareatogeneratetheexpectedelectricity.Thereispotentialforgovernmentstoundertakesomeresourcemappingandmakethisavailabletoprojectdeveloperstoreduceprojectdevelopmentrisksandcoststoconsumers.Globally,around78%ofproductionwellsdrilledaresuccessful,withtheaveragesuccessrateimprovinginrecentdecades.Thisismostlikelyduetobettersurveyingtechnology,whichisabletomoreaccuratelytargetthebestprospectsforsitingproductivewells,althoughgreaterexperienceineachregionhasalsoplayedapart(IFC,2013).Inaddition,geothermalplantsaredistinctintermsofthequalityoftheirresourcesandmanagementneeds.Asaresult,experiencewithoneprojectmaynotyieldspecificlessonsthatcanbedirectlyappliedtonewdevelopments.Suchexperiencemay,however,providebroaderindustryknowledgethathelpsbetterinformotherfactors,fromreservoirmodellingtooperationandmaintenance(O&M)practices.Nonetheless,adherencetobestinternationalpracticesforsurveyandmanagement–withthoroughdataanalysisfromtheprojectsite–isthebestriskmitigationtoolavailabletodevelopers(IFC,2013),anditsimportancecannotbeunderestimated.Anotherpointofdifferenceforgeothermalplantsisthatoncecommissioned,themanagementoftheplantanditsreservoirevolvesalmostconstantlyovertimeinawaythatismuchmorechallengingthan,forexample,windorsolarphotovoltaic(PV).Theprocessofextractingreservoirfluidandreinjectingitoverthelifeoftheprojectcreatesadynamicsituationwherereservoirfluidmigrationwilllikelychangeovertime,withimplicationsfortheproductivityofindividualproductionwells.Withmoreinformationbecomingavailablefromoperationalexperience,operators’understandingofhowtobestmanagethereservoirwillalsoconstantlyevolveovertime.Anotherimportantconsiderationforgeothermalpowerplantsisthatonceproductivityatexistingwellsdeclines,therewilloftenbeaneedforreplacementwellstomakeupforthisloss.Asaresult,lifetimeO&Mcostsare,onaverage,higherinfixedtermsthanforotherrenewabletechnologies.Yet,withhighercapacityfactors,theycanbesimilaronaperkWhbasis.170RENEWABLEPOWERGENERATIONCOSTSIN2022TOTALINSTALLEDCOSTSGeothermalpowergenerationprojectshave,onaverage,relativelyhighcapitalcostscomparedtohydropower,solarPVandonshorewind,withinstalledcostsmoreinlinewithoffshorewindandconcentratedsolarpower(CSP).Projectdevelopment,fieldpreparation,productionandreinjectionwells,thepowerplant,andassociatedcivilengineeringentailsignificantupfrontcosts.Geothermalprojectsarealsosubjecttovariationsindrillingcosts,thetrendsofwhichareofteninfluencedbythebusinesscycleintheoilandgasindustry.Thesefluctuationshaveadirectimpactondrillingcostsandthusthecostsofengineering,procurementandconstruction(EPC).Geothermalpowerplantinstalledcostsarehighlysitesensitive.Inthisrespect,theyhavemoreincommonwithhydropowerprojectsthanthemorestandardisedsolarPVandonshorewindfacilities.Inparticular,geothermalpowerprojectcostsareheavilyinfluencedbyreservoirquality–thatistosay,temperature,flowratesandpermeability–becausethisinfluencesboththetypeofpowerplantandthenumberofwellsrequiredforagivencapacity.Thenatureandextentofthereservoir,itsthermalproperties,anditsfluids–andatwhatdepthstheylie–willallhaveanimpactonprojectcosts.Inaddition,thequalityofthegeothermalresourceanditsgeographicaldistributionwilldeterminethepowerplanttype.Thiscanbeaflash,directsteam,binary,enhancedorhybridapproachtoprovidethesteamthatwilldriveaturbineandcreateelectricity.Typically,costsforbinaryplantsdesignedtoexploitlowertemperatureresourcestendtobehigherthanthosefordirectsteamandflashplants,becauseextractingtheelectricityfromlowertemperatureresourcesismorecapitalintensive.Thetotalinstalledcostsofgeothermalpowerplantsalsoincludethecostofexplorationandresourceassessment(includingseismicsurveysandtestwells).Thiscostcategoryalsoappliestosolarandwindresources,butresourceassessmentwithweatherstationscostsmuchlessthanthatforgeothermalpowerplants.Theothermainadditionalcostdriverforgeothermalisthedrillingcostoftheproductionandinjectionwells.Ifalargegeothermalfieldneedstobeexploited,thecostsforfieldinfrastructure,geothermalfluidcollection,disposalsystemsandothersurfaceinstallationscanalsobesignificant.Inlinewithrisingcommoditypricesanddrillingcosts,between2000and2009,thetotalinstalledcostsforgeothermalplantsincreasedbybetween60%and70%(IPCC,2011).ProjectdevelopmentcostsfollowedgeneralincreasesincivilengineeringandEPCcostsduringthatperiod,withcostincreasesindrillingassociatedwithsurgingoilandgasmarkets.Costsappeartohavestabilisedsince,however,albeitwithsignificantvolatilityduetothinmarketsupto2015.171GEOTHERMALCapacity(MW)≥BinaryDirectsteamFlashtypesEnhancedHybridnaSingleﬂashbinaryUSDkWFigure7.2Geothermalpowertotalinstalledcostsbyproject,technologyandcapacity,2007-2022In2009,thetotalinstalledcostsofconventionalcondensingflashgeothermalpowergenerationprojectswerebetweenUSD2097/kWandUSD4183/kW.Binarypowerplantsweremoreexpensive:installedcostsfortypicalprojectswerebetweenUSD2481andUSD6062/kWthesameyear(IPCC,2011).Since2010,mostflashpowerplantsforwhichIRENAhasdatawereintherangeofUSD2260/kWtoUSD5580/kW,andbinaryplantswereintherangeofUSD2890/kWtoUSD5210/kW.Figure7.2presentsthegeothermalpowertotalinstalledcostsbyproject,technologyandcapacityfrom2007to2022.BasedonthedataavailableintheIRENARenewableCostDatabase,installedcostsfrom2010onwardhavegenerallyfallenwithintherangeofUSD2000/kWtoUSD6000/kW,althoughtherewereanumberofprojectoutliers,especiallyforsmalland/orremotelylocatedprojects.Since2013,theweightedaveragetotalinstalledcosthasbeenrelativelyflat–withsomeinter-yearvariation–rangingfromahighofUSD4624/kWin2018toalowofUSD3478/kWin2022,withanaverageofaroundUSD4150/kWinthatperiod.The2022figure,althoughnoticeablylowerthanUSD4300/kWin2021,wasstillhigherthantheUSD2904/kWreportedin2010.Inthemoreexceptionalcaseofprojectswherecapacityisbeingaddedtoanexistinggeothermalpowerproject,theIRENARenewableCostDatabasesuggeststhecostofageothermalpowerplantcanbeaslowasUSD560/kW.Thisishoweverbynomeansthenorm,anditisnowraretoseeprojectswithcostsbelowUSD2000/kW.172RENEWABLEPOWERGENERATIONCOSTSIN2022CAPACITYFACTORSByaccessingthesteamorheatedwaterneartheEarth’ssurface,geothermalplantshaveacontinuoussourceofenergyandtendtooperateformosthoursoftheyear.Fortheyears2007to2022,datafromtheIRENARenewableCostDatabaseindicatethatgeothermalpowerplantstypicallyhadcapacityfactorsthatrangedfrom50%tomorethan95%,withsomeexceptions.Therewere,however,significantvariationsbyproject,andtoalesserextentbetweencountries.Thesevariationsweredrivenbythequalityoftheresourceandreservoirdynamics,aswellasbyeconomicfactors,tonamejustthreeofthemostimportantdrivers.Figure7.3presentsthecapacityfactorsofgeothermalpowerplantprojectsintheIRENARenewableCostDatabasebyyear,projectsizeandtechnology.Theaveragecapacityfactorofgeothermalplantsusingdirectsteamisaround85%,whiletheaverageforflashtechnologiesis82%.Binarygeothermalpowerplantsthatharnesslowertemperatureresourcesareexpectedtoachieveanaveragecapacityfactorof80%.In2022,theglobalweightedaveragecapacityfactorfornewlycommissionedgeothermalprojectswas85%,upfrom77%in2021(the2021dipwasmainlydrivenbyasingleTurkishplant,withareportedlifetimecapacityfactorof42%).Capacity(MW)≥BinaryDirectsteamFlashtypesEnhancedHybridnaCapacityfactorFigure7.3Capacityfactorsofgeothermalpowerplantsbytechnologyandprojectsize,2007-2022173GEOTHERMALLEVELISEDCOSTOFELECTRICITYThetotalinstalledcosts,weightedaveragecostofcapital,economiclifetimeandO&McostsofageothermalplantdetermineitsLCOE.Geothermalpowerplantstendtohavehigherinstalledcosts,O&Mcostsandcapacityfactorsthanhydropower,somebioenergyplants,solarPVandonshorewindprojects.Thehighercapacityfactorshelptooffsetthehighercapitalandoperatingcosts,whilealsoindicatingthattheplantrunsduringmosthoursoftheyear.Evenmorethanwithsolarandwindtechnologies,geothermalpowerprojectsrequirecontinuousoptimisationthroughouttheirlifetime,withsophisticatedmanagementofthereservoirandproductionwellstoensureoutputmeetsexpectations.ThisleadstohigherO&Mcosts.ThisLCOEanalysisassumesO&McostsofUSD115/kW/yearandaneconomiclifeof25yearsfortheproject.Capacityfactorsweretakenfromprojectdatawhereavailable,andnationalaverageswereusedifnonewereavailable.Figure7.4presentstheLCOEofgeothermalpowerprojectsbytechnologyandsizefortheperiod2007to2022.Duringthisperiod,theLCOEvariedfromaslowasUSD0.026/kWhforsecondstagedevelopmentofanexistingfieldtoashighasUSD0.174/kWhforsmallgreenfielddevelopmentsinremoteareas.Cardaf©Shutterstock.com174RENEWABLEPOWERGENERATIONCOSTSIN2022O&McostsforgeothermalprojectsarehighrelativetoonshorewindandsolarPV,inparticular,becauseovertimethereservoirpressurearoundtheproductionwelldeclines,leadingtopoorerflowrates.Wellproductivitythereforedeterioratesovertime.Eventually,powergenerationproductionfallsaswellifremedialmeasuresarenottaken.Tomaintainproductionatthedesignedcapacityfactor,thereservoirandproductionprofileofthegeothermalpowerplantsrequireagilemanagement,whichwillalsotypicallyincludetheneedtoincorporateadditionalproductionwellsoverthelifetimeoftheplant.TheO&McostassumptionofUSD110/kW/yearthereforeincludestwosetsofwellsformakeupandreinjectionoverthe25-yearlifeoftheprojecttomaintainperformance.TheglobalweightedaverageLCOEofaroundUSD0.056/kWhin2022almostcamebackdowntothe2010figureofUSD0.053/kWh.Althoughthereareannualvariationsintheglobalweightedaveragecapacityfactorofnewlycommissionedprojects,thisisoftenlesssignificantthanforbioenergy,forexample,wheresignificantcostdifferencesoccurbetweentechnologiesandcountries.Withtypicallylittlevariationincapacityfactors,theLCOEofgeothermalpowerprojectstendstofollowthetrendsintotalinstalledcosts.Fortheperiod2016to2021,thedataavailablesuggesttheLCOEwasrelativelystableformostyears,withaglobalweightedaverageofbetweenUSD0.071/kWhandUSD0.075/kWh.Theexceptionwas2020,whenalowofUSD0.060/kWhwasdrivenbythecommissioningofaverycompetitiveKenyanproject.Capacity(MW)≥BinaryDirectsteamFlashtypesEnhancedHybridnaUSDkWhFossilfuelcostrangeFigure7.4LCOEofgeothermalpowerprojectsbytechnologyandprojectsize,2007-2022175BaehakiHariri©Shutterstock.com08BIOENERGYJanOtto©Gettyimages.com177HIGHLIGHTS•Between2010and2022,theglobalweightedaverageLCOEofbioenergyforpowerprojectsfellfromUSD0.082/kWhtoUSD0.061/kWh.Thisfigurefor2022isthesecondlowestsince2010andislowerthanthecostofelectricityfromnew,fossilfuel-firedprojects.•Bioenergyforelectricitygenerationoffersasuiteofoptions,spanningawiderangeoffeedstocksandtechnologies.Wherelow-costfeedstocksareavailable–suchasby-productsfromagriculturalorforestryprocessesonsite–theycanprovidehighlycompetitive,dispatchableelectricity.•Forbioenergyprojectsnewlycommissionedin2022,theglobalweightedaveragetotalinstalledcostwasUSD2162kW(Figure8.1).Thisrepresentedadecreaseonthe2021weightedaverageofUSD2518/kW.•Capacityfactorsforbioenergyplantsareheterogeneous,dependingontechnologyandfeedstockavailability.Between2010and2022,theglobalweightedaveragecapacityfactorforbioenergyprojectsvariedbetweenalowof67%in2012and2016andahighof86%in2017.Itdecreasedto68%in2021andagainincreasedto72%in2022.•In2022,bycountry/region,theweightedaverageLCOErangedfromalowofUSD0.060/kWhinIndiaandUSD0.062/kWhinChinatohighsofUSD0.092/kWhinEuropeandUSD0.101/kWhinNorthAmerica.TotalinstalledcostCapacityfactorLevelisedcostofelectricityCapacityfactorUSDkWhUSDkWFigure8.1Globalweightedaveragetotalinstalledcosts,capacityfactorsandLCOEforbioenergy,2010-2022178RENEWABLEPOWERGENERATIONCOSTSIN2022BIOENERGYFORPOWERPowergenerationfrombioenergycancomefromawiderangeoffeedstocks.Itcanalsouseavarietyofdifferentcombustiontechnologies,runningfrommature,commerciallyavailablevarietieswithlongtrackrecordsandawiderangeofsupplierstolessmaturebutinnovativesystems.Thelattercategoryincludesatmosphericbiomassgasificationandpyrolysis,technologiesthatarestilllargelyatthedevelopmentalstagebutarenowbeingtriedoutonacommercialscale.Maturetechnologiesinclude:directcombustioninstokerboilers,low-percentageco-firing,anaerobicdigestion,municipalsolidwasteincineration,landfillgasandcombinedheatandpower(CHP).Toanalysetheuseofbiomasspowergeneration,itisimportanttoconsiderthreemainfactors:feedstocktypeandsupply,theconversionprocess,andthepowergenerationtechnology.Althoughtheavailabilityoffeedstockisoneofthemainelementsfortheeconomicsuccessofbiomassprojects,thisreport’sanalysisfocusesonthecostsofpowergenerationtechnologiesandtheireconomics,whileonlybrieflydiscussingdeliveredfeedstockcosts.BIOMASSFEEDSTOCKSTheeconomicsofbiomasspowergenerationaredifferentfromthoseofwind,solarorhydro.Thisisbecausebiomassisdependentontheavailabilityofafeedstocksupplythatispredictable,sustainablysourced,lowcostandadequateoverthelongterm.Anaddedcomplicationisthatthereisarangeofcaseswhereelectricitygenerationisnottheprimaryactivityofsiteoperations.Instead,asiteistiedtoforestryoragriculturalprocessingactivitiesthatmayimpactwhenandwhyelectricitygenerationhappens.Forinstance,withelectricitygenerationatpulpandpapermills,asignificantproportionoftheelectricitygeneratedwillbeusedtorunthesefacilities’operations.Biomassistheorganicmaterialofrecentlylivingplants,suchastrees,grassesandagriculturalcrops.Biomassfeedstocksarethusveryheterogeneous,withthechemicalcompositionhighlydependentontheplantspecies.Thecostoffeedstockperunitofenergyishighlyvariable,too.Thisisbecausethefeedstockcanrangefromonsiteprocessingresiduesthatwouldotherwisecostmoneytodisposeof,todedicatedenergycropsthatmustpayforthelandused,theharvestingandlogisticsofdelivery,andstorageonsiteatadedicatedbioenergypowerplant.Examplesoflow-costresiduesthatarecombustedforelectricityandheatgenerationinclude:sugarcanebagasse,ricehusks,blackliquorandotherpulpandpaperprocessingresidues,sawmilloffcutsandsawdust,andrenewablemunicipalwastestreams.179BIOENERGYInadditiontocost,thephysicalpropertiesofthefeedstocksmatterbecausetheywilldifferinashcontent,density,particlesizeandmoisture,withheterogeneityinquality.Thesefactorsalsohaveanimpactonthetransportation,pre-treatmentandstoragecosts,aswellastheappropriatenessofdifferentconversiontechnologies.Someofthesearerelativelyrobustandcancopewithvariedfeedstocks,whileothersrequiremoreuniformity(e.g.somegasificationprocesses).Akeycostconsiderationforbioenergyisthatmostformshaverelativelylowenergydensity.Collectionandtransportcostsoftenthereforedominatethecostsoffeedstocksderivedfromforestresiduesanddedicatedenergycrops.Aconsequenceofthisisthatlogisticalcostsstarttoincreasesignificantlyasthedistancetothepowerplantfromthefeedstocksthatneedtobesourcedincreases.Inpracticalterms,thistendstolimittheeconomicsizeofbioenergypowerplants,asthelowestcostofelectricityisachievedoncefeedstockdeliveryreachesacertainradiusaroundtheplant.Forbiomasstechnologies,thetypicalshareofthefeedstockcostinthetotalLCOErangesbetween20%and50%.Pricesforbiomasssourcedandconsumedlocally,however,aredifficulttoobtain.Thismeansthatwhatevermarketindicatorsforfeedstockcostsareavailablemustbeusedasproxies.Alternatively,estimatesoffeedstockcostsfromtechno-economicanalysesthatmaynotnecessarilyberepresentativeoruptodatecanbeused(seeIRENA[2015]foramoredetaileddiscussionoffeedstockcosts).TOTALINSTALLEDCOSTSDifferentregionshavedifferingcostsinbiomasspowergeneration,withbothatechnologycomponentandalocalcostcomponentintotalcost.ProjectsinemergingeconomiestendtohavelowerinvestmentcoststhanprojectsinOECDcountries.Thisisbecauseemergingeconomiesoftenbenefitfromlowerlabourandcommoditycosts.Thisallowsforthedeploymentoflowercosttechnologieswithreducedemissioncontrolinvestments,albeitwithhigherlocalpollutantemissions,insomecases.Themaincategoriesinthetotalinvestmentcostsofabiomasspowerplantare:planning,engineeringandconstructioncosts;fuelhandlingandpreparationmachinery;andotherequipment(e.g.theprimemoverandfuelconversionsystem).Additionalcostsarederivedfromgridconnectionandinfrastructure(e.g.civilworksandroads).Equipmentcoststendtodominate,butspecificprojectscanhavehighcostsforinfrastructureandlogistics,orforgridconnectionwhenlocatedinremoteareas.CHPbiomassinstallationshavehighercapitalcosts.Yet,theirhigheroverallefficiency(around80%to85%)andtheirabilitytoproduceheatand/orsteamforindustrialprocesses–orforspaceandwaterheatingthroughdistrictheatingnetworks–cansignificantlyimprovetheireconomics.180RENEWABLEPOWERGENERATIONCOSTSIN2022Figure8.2presentsthetotalinstalledcostofbioenergy-firedpowergenerationprojectsfordifferentfeedstocksfortheyears2000to2022,whereIRENAhassufficientdatatoprovidemeaningfulcostranges.Althoughthepatternofdeploymentbyfeedstockvariesbycountryandregion,itisclearthattotalinstalledcostsacrossfeedstockstendtobehigherinEuropeandNorthAmericaandlowerinAsiaandSouthAmerica.ThisreflectsthefactthatbioenergyprojectsinOECDcountriesareoftenbasedonwood,orarecombustingrenewablemunicipalorindustrialwaste,wherethemainactivitymaybewastemanagement.Intheseinstances,energygeneration(potentiallyheatandelectricity)isaby-productofthefactthatCHPhasbeenfoundtobethecheapestwaytomanagewaste.Forthe2000to2022period,inChina,the5thand95thpercentileofprojectsacrossallfeedstockssawtotalinstalledcostsrangefromalowofUSD702/kWforricehuskprojectstoahighofUSD5481/kWforrenewablemunicipalwasteprojects.InIndia,therangewasfromalowofUSD572/kWforbagasseprojectstoahighofUSD4871/kWforlandfillgasprojects.TherangeishigherforprojectsinEuropeandNorthAmerica.CostsinthesetwogeographiesrangedfromUSD701/kWforlandfillgasprojectsinNorthAmericatoahighofUSD7445/kWforrenewablemunicipalwasteprojectsinEurope,duringtheperiodinquestion.Thiswasbecauseintheseregions,thetechnologicaloptionsusedtodevelopprojectsaremoreheterogeneousand,onaverage,moreexpensive.Thedataavailablebyfeedstockfortherestoftheworldweremorelimited,butthe5thand95thpercentiletotalinstalledcostrangeforwoodwasteprojectswasthewidest.Forthese,thedatastretchedfromUSD615/kWtoUSD6539/kW.46TheweightedaveragetotalinstalledcostforprojectsintherestoftheworldtypicallyrangedbetweenthelowervaluesseeninChinaandIndiaandthehighervaluesprevalentinEuropeandNorthAmerica,forthetimeperiodcovered.Figure8.3presentsthetotalinstalledcostbyproject,basedoncapacityranges.Itshowsthatinthepowersector,bioenergyprojectsarepredominantlysmallscale,withthemajorityofprojectsunder25MWincapacity.Thereare,however,cleareconomiesofscaleevidentforplantsroughlyabovethe25MWlevel,atleastinthedataforChinaandIndia.Therelativelysmallsizeofbioenergyforelectricityplantsistheresultofthelowenergydensityofbioenergyfeedstocksandtheincreasinglogisticalcostsinvolvedinenlargingthecollectionareatoprovideagreatervolumeoffeedstocktosupportlarge-scaleplants.TheoptimalsizeofaplanttominimisetheLCOEofaproject,inthiscontext,isatrade-offbetweenthecostbenefitsofeconomiesofscaleandthehigherfeedstockcosts–whichgrowastheaveragedistancetotheplantofthesourcedfeedstocksexpands.46Excludingthetotalinstalledcostsforrenewablemunicipalwaste,whicharenotrepresentativegiventhatthereareonlytwoprojectsinthedatabase.181BIOENERGYCapacity(MW)≥BagasseLandﬁllgasChinaEuropeIndiaNorthAmericaRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldChinaChinaEuropeIndiaIndiaNorthAmericaRestoftheworldRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldOthervegetalandagriculturalwasteRicehusksWoodwasteRenewablemunicipalwasteUSDkWthpercentilethpercentileFigure8.2Totalinstalledcostsofbioenergypowergenerationprojectsbyselectedfeedstocksandcountry/region,2000-2022thpercentilethpercentileUSDkWMW(capacitybins)China------------------------------------------------------IndiaEuropeNorthAmericaRestoftheworldFigure8.3Totalinstalledcostsofbioenergypowergenerationprojectsfordifferentcapacityrangesbycountry/region,2000-2022182RENEWABLEPOWERGENERATIONCOSTSIN2022CAPACITYFACTORSANDEFFICIENCYWhenfeedstockavailabilityisuniformovertheentireyear,bioenergy-firedelectricityplantscanhaveveryhighcapacityfactors,rangingbetween85%and95%.Whentheavailabilityoffeedstockisbasedonseasonalagriculturalharvests,however,capacityfactorsaretypicallylower.Anemergingissueforbioenergypowerplantsistheimpactclimatechangemayhaveonfeedstockavailabilityandhowthismightaffectthetotalannualvolumeavailable,aswellasitsdistributionthroughouttheyear.Thisisanareawheretheneedforresearchwillbeongoing,astheclimatechanges.Figure8.4showsthatbiomassplantsthatrelyonbagasse,landfillgasandotherbiogasestendtohaveloweraveragecapacityfactors(typicallyaround50%to60%)byregion.Plantsrelyingonwood,fuelwood,ricehusks,andothervegetalandagricultural,industrialandrenewablemunicipalwaste,however,tendtohaveweightedaveragecapacityfactorsbyregionintherangeof60%to93%.Capacity(MW)≥BagasseLandﬁllgasChinaEuropeIndiaNorthAmericaRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldChinaChinaEuropeIndiaIndiaNorthAmericaRestoftheworldRestoftheworldChinaEuropeIndiaNorthAmericaRestoftheworldOthervegetalandagriculturalwasteRicehusksWoodwasteRenewablemunicipalwastethpercentilethpercentileCapacityfactorFigure8.4Projectcapacityfactorsandweightedaveragesofselectedfeedstocksforbioenergypowergenerationprojectsbycountryandregion,2000-2022183BIOENERGYAfteraccountingforfeedstockhandling,theassumednetelectricalefficiencyoftheprimemover(thegenerator)averagesaround30%.Thisdoes,however,varyfromalowof25%toahighofaround36%.CHPplantsthatproduceheatandelectricityachievehigherefficiencies,withanoveralllevelof80%to85%notuncommon.Indevelopingcountries,lessadvancedtechnologies–andsometimessub-optimalmaintenancewhenrevenuesarelessthananticipated–resultinloweroverallefficiencies.Thesecanbearound25%,butmanytechnologiesareavailablewithhigherefficiencies.Thelattercanrangefrom31%forwoodgasifierstoahighof36%formodern,well-maintainedstoker,circulatingfluidisedbed(CFB),bubblingfluidisedbed(BFB)andanaerobicdigestionsystems(MottMacDonald,2011).Theseassumptionsareunchangedfromthelastfourreports(sinceIRENA,2018).Table8.1presentsdataforprojectweightedaveragecapacityfactorsofbioenergy-firedpowergenerationprojectsfortheperiod2000to2022.AccordingtotheIRENACostDatabase,NorthAmericashowedthehighestweightedaveragecapacityfactor(85%),followedbyEurope,with81%.Indiaandtherestoftheworldshowedlowerweightedaveragecapacityfactorsof68%each,andChinastoodat66%.Table8.1Projectweightedaveragecapacityfactorsofbioenergyfiredpowergenerationprojects,2000-20222000-20225thpercentile(%)Weightedaverage(%)95thpercentile(%)China396682Europe528193India326886NorthAmerica438594Restoftheworld306891OPERATIONANDMAINTENANCECOSTSFixedO&Mcostsinclude:labour,insurance,scheduledmaintenanceandroutinereplacementofplantcomponents(e.g.boilersandgasifiers),feedstockhandlingequipment,andotheritems.Intotal,theseO&Mcostsaccountforbetween2%and6%ofthetotalinstalledcostsperyear.LargebioenergypowerplantstendtohavelowerperkWfixedO&Mcosts,duetoeconomiesofscale.VariableO&Mcosts,atanaverageofUSD0.005/kWh,areusuallylowforbioenergypowerplantswhencomparedtofixedO&Mcosts.ReplacementpartsandincrementalservicingcostsarethemaincomponentsofvariableO&Mcosts,althoughthesealsoincludenon-biomassfuelcosts,suchasashdisposal.Duetoitsproject-specificnatureandthelimitedavailabilityofdata,inthisreport,variableO&McostshavebeenmergedwithfixedO&Mcosts.184RENEWABLEPOWERGENERATIONCOSTSIN2022LEVELISEDCOSTOFELECTRICITYThewiderangeofbioenergy-firedpowergenerationtechnologies,installedcosts,capacityfactorsandfeedstockcostsresultsinavarietyofobservedLCOEsforbioenergy-firedelectricity.Figure8.5summarisestheestimatedLCOErangeforbiomasspowergenerationtechnologiesbyfeedstockandcountry/region,wheretheIRENARenewableCostDatabasehassufficientdatatoprovidemeaningfulinsights.Assumingacostofcapitalofbetween7.5%and10%andfeedstockcostsbetweenUSD1/gigajoule(GJ)andUSD9/GJ(theLCOEcalculationsinthisreportarebasedonanaverageofUSD1.50/GJ),theglobalweightedaverageLCOEofbiomass-firedelectricitygenerationforprojectscommissionedin2022wasUSD0.061/kWh.ThiswasadecreasefromUSD0.071/kWhin2021.Lookingatthefulldatasetfortheperiodfrom2000to2022,thelowestweightedaverageLCOEofbiomass-firedelectricitygenerationwasfoundinIndia,whereitstoodatUSD0.060/kWh.Inaddition,India’s5thand95thpercentilevalueswereUSD0.040/kWhandUSD0.109/kWh(Figure8.5).ThehighestweightedaverageforthisperiodwasUSD0.101/kWh,recordedinNorthAmerica,wherethe5thand95thpercentilesofprojectsfellbetweenUSD0.050/kWhandUSD0.195/kWh.TheweightedaverageLCOEofbioenergyprojectsinChinawasUSD0.062/kWh,withthe5thand95thpercentilesofprojectsfallingbetweenUSD0.046/kWhandUSD0.124/kWh.TheweightedaverageinEuropeoverthisperiodwasUSD0.092/kWh,whileintherestoftheworlditwasUSD0.074/kWh.Bioenergycanprovideverycompetitiveelectricitywherecapitalcostsarerelativelylowandlow-costfeedstocksareavailable.Indeed,thistechnologycanprovidedispatchableelectricitygenerationwithanLCOEaslowasaroundUSD0.040/kWh.Themostcompetitiveprojectsmakeuseofagriculturalorforestryresiduesalreadyavailableatindustrialprocessingsites,wheremarginalfeedstockcostsareminimalorevenzero.Whereonsiteindustrialprocesssteamorheatloadsarerequired,bioenergyCHPsystemscanalsoreducetheLCOEforelectricitytoaslittleasUSD0.03/kWh,dependingonthealternativecostsforheatorsteamavailabletothesite.Evenhighercostprojectsincertaindevelopingcountriescanbeattractive,however,becausetheyprovidesecurityofsupplyinconditionswherebrownoutsandblackoutscanbeparticularlyproblematicfortheefficiencyofindustrialprocesses.Projectsusinglow-costfeedstocks–suchasagriculturalorforestryresiduesortheresiduesfromprocessingagriculturalorforestryproducts–tendtohavethelowestLCOEs.ForprojectsintheIRENARenewableCostDatabase,theweightedaverageprojectLCOEbyfeedstockisUSD0.06/kWhorlessforthoseusingblackliquor,primarysolidbioenergy(typicallywoodorwoodchips),renewablemunicipalsolidwaste,andothervegetalandagriculturalwaste.185BIOENERGYProjectsrelyingonmunicipalwastecomewithhighcapacityfactorsandaregenerallyaneconomicsourceofelectricity.Yet,theLCOEforprojectsinNorthAmericaissignificantlyhigherthantheaverageinotherareas.Giventhattheseprojectshavebeendevelopedprimarilytosolvewastemanagementissues,andnotprimarilyforthecompetitivenessoftheirelectricityproduction,thisisnotnecessarilyanimpedimenttotheirviability.InEurope,suchprojectsalsosometimessupplyheateithertolocalindustrialusersordistrictheatingnetworks,withtherevenuesfromthesesalesbringingtheLCOEbelowthatpresentedhere.ManyofthehighercostprojectsinEuropeandNorthAmericausingmunicipalsolidwasteasafeedstockrelyontechnologieswithhighercapitalcosts,asmoreexpensivetechnologiesareusedtoensurelocalpollutantemissionsarereducedtoacceptablelevels.Excludingtheseprojects–whicharetypicallynotthelargest–reducestheweightedaverageLCOEinEuropeandNorthAmericabyaroundUSD0.01/kWhandnarrowsthegapwiththeLCOEofnon‑OECDregions.Capacity(MW)≤≥BagasseBiomassenergyBlackliquorEnergycropsFuelwoodBioenergyBiogasdigestersBiomassOtherbiogasesfromanaerobicfermentationOtherprimarysolidbiomassOthervegetalandagriculturalwasteStrawIndustrialwasteLandﬁllgasPulpandpaperresiduesRenewablemunicipalwasteRicehusksWoodwasteChinaEuropeIndiaNorthAmericaRestoftheworldthpercentilethpercentileUSDkWhFigure8.5LCOEbyprojectandweightedaveragesofbioenergypowergenerationprojectsbyfeedstockandcountry/region,2000-2022186RENEWABLEPOWERGENERATIONCOSTSIN2022Figure8.6presentstheLCOEandcapacityfactorbyprojectandweightedaveragesforbagasse,landfillgas,ricehusksandothervegetalandagriculturalwasteusedasfeedstockforbioenergy-firedpowergenerationprojects.Thefigureshowshowthedynamicrelationshipbetweenfeedstockavailabilityinfluencestheeconomicoptimumforaproject.Thedataforbagasseplantsshowthisclearly.Wherethecapacityfactorismorethan30%,thereisnostrongrelationbetweenthecapacityfactorandtheLCOEoftheproject.Thisindicatesthattheavailabilityofacontinuousstreamoffeedstockallowsforhighercapacityfactors.However,itisnotnecessarilymoreeconomicifitmeansthatlow-costseasonalagriculturalresiduesneedtobesupplementedbymoreexpensivefeedstocks.Importantly,theLCOEoftheseprojectsiscomparabletoprojectsrelyingonmoregeneric,woodybiomassfeedstocks,suchaswoodpelletsandchips,whichcanbemorereadilypurchasedyear-round.Thus,accesstolow-costfeedstockoffsetstheimpactonLCOEoflowercapacityfactors.Forprojectsusingothervegetalandagriculturalwastesastheprimaryfeedstock,thedatatendtosuggestthatthereisacorrelationbetweenhighercapacityfactorsandlowerLCOEsindevelopingcountries,giventhatthehighercostprojectswithcapacityfactorsabove80%arealllocatedinOECDcountries.USDkWhUSDkWhBagasseLandfillgasOthervegetalandagriculturalwasteRicehusksCapacityfactorUSDkWhRenewablemunicipalwasteWoodwasteFigure8.6LCOEandcapacityfactorbyprojectofselectedfeedstocksforbioenergypowergenerationprojects,2000-2022RalfGeithe©Shutterstock.com188RENEWABLEPOWERGENERATIONCOSTS2021Anzinger,N.,andKostka,G.(2015),OffshorewindpowerexpansioninGermany:Scale,patternsandcausesoftimedelaysandcostoverruns,HertieSchoolofGovernance,Berlin,Germany,www.hertie-school.org/fileadmin/2_Research/2_Research_directory/Research_projects/Large_infrastructure_projects_in_Germany_Between_ambition_and_realities/4_WP_Offshore_Wind_Energy.pdfBernreuter(2022),Pricetrend:Currentlevel,chart,forecast&historyofthepolysiliconprice,BernreuterResearch,www.bernreuter.com/polysilicon/price-trend/BNEF(2020),2H2020windoperationsandmaintenancepriceindex,BloombergNewEnergyFinance.BNEF(2023),1H2023WindTurbinePriceIndex:DownFromthePeak,BloombergNewEnergyFinance.Bolinger,M.,etal.(2022),Utility-ScaleSolar,2022Edition,LBNL,https://emp.lbl.gov/publications/utility-scale-solar-2022-editionEEA(2009),Europe’sonshoreandoffshorewindenergypotential,EuropeanEnvironmentAgency,Copenhagen,Denmark,www.energy.eu/publications/a07.pdfEIA(2017),AnnualEnergyOutlook2017withprojectionsto2050(summerupdate),USEnergyInformationAdministration(EIA).Ember(2023),EuropeanElectricityReview2023,Ember,https://ember-climate.org/insights/research/european-electricity-review-2023/EnergyTrend(2022),Solarprice,TrendForce,www.energytrend.com/solar-price.htmlEurostat(2023a),“Electricitypricesforhouseholdconsumers-bi-annualdata(from2007onwards)[NRG_PC_204__custom_6511473]”,https://ec.europa.eu/eurostat/databrowser/view/NRG_PC_204/default/table?lang=enEurostat(2023b),“Electricitypricesfornon-householdconsumers-bi-annualdata(from2007onwards)[NRG_PC_205__custom_6511374]”.Eurostat(n.d.),“Comext:Eurostatstatisticsoninternationaltradeingoods”,https://ec.europa.eu/eurostat/comext/newxtweb/(accessed5May2022).Fichtner(2010),TechnologyAssessmentofCSPTechnologiesforaSiteSpecificProjectinSouthAfrica:FinalReport,TheWorldBank&EnergySectorManagementAssistanceProgram(ESMAP),Washington,D.C.Garcia-Casals,X.,andBianco,E.(2022),Potentiallimitationsofmarginalpricingforapowersystembasedonrenewables,TechnicalPaper3/2022,InternationalRenewableEnergyAgency,AbuDhabi,www.irena.org/Technical-Papers/Potential-Limitations-of-Marginal-Pricing-for-a-Power-System-Based-on-RenewablesGlobalData(2023),“SolarPowerSector,GenerationandMarketsDatabase”,www.globaldata.com/data-insights/listing/search/?industry=4800016&q[]=Solar%2520power%2520sector(acce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://atainsights.com/wp-content/uploads/2017/05/Craig-PPT.pdfU.S.EnergyInformationAdministration(2012),“AnnualEnergyReview”,www.eia.gov/totalenergy/data/annual/showtext.php?t=ptb0709U.S.EnergyInformationAdministration(n.d.),“DomesticCrudeOilFirstPurchasePricesbyArea”,www.eia.gov/dnav/pet/PET_PRI_DFP1_K_A.htmVartiainen,E.,etal.(2019),“Impactofweightedaveragecostofcapital,capitalexpenditure,andotherparametersonfutureutility-scalePVlevelisedcostofelectricity”,ProgressinPhotovoltaics,vol.28/6,pp.439–53,https://doi.org/10.1002/pip.3189VestasWindSystemsA/S(2023),“Investorpresentation:Firstquarter2023”.Wehrmann,B.(2020),Germanoffshorewindpower–output,businessandperspectives,CleanEnergyWire,www.cleanenergywire.org/factsheets/german-offshore-wind-power-output-business-and-perspectives(accessed20April2020).Wiser,R.,etal.(2022),Land-basedWindMarketReport:2022Edition,LBNL.WoodMackenzie(2022),O&Meconomicsandcostdataforonshorewindpowermarkets2022,WoodMackenzie.WorldBank(2023),“Globalpopulation,total”,https://data.worldbank.org/indicator/SP.POP.TOTLZhou,E.,etal.(2019),AnalysisofthecostandvalueofconcentratingsolarpowerinChina,No.NREL/TP-6A20-74303,NREL(NationalRenewableEnergyLaboratory),Boulder,CO,www.nrel.gov/docs/fy20osti/74303.pdf191ANNEXICOSTMETRICMETHODOLOGYCostcanbemeasuredindifferentways,withdifferentcostmetricsbringingtheirowninsights.Thecoststhatcanbeexaminedincludeequipmentcosts(e.g.photovoltaicmodulesorwindturbines),financingcosts,totalinstalledcosts,fixedandvariableoperatingandmaintenancecosts(O&M),fuelcosts(ifany),andthelevelisedcostofelectricity(LCOE).Theanalysisofcostscanbeverydetailed,butforcomparisonpurposesandtransparency,theapproachusedhereisasimplifiedonethatfocussesonthecorecostmetricsforwhichgooddataarereadilyavailable.Thisallowsgreaterscrutinyoftheunderlyingdataandassumptions,improvestransparencyandconfidenceintheanalysis,whilefacilitatingthecomparisonofcostsbycountryorregionforthesametechnologies,enablingtheidentificationofthekeydriversinanycostdifferences.Thefivekeyindicatorsthathavebeenselectedare:•equipmentcost(factorygate,freeonboard[FOB],anddeliveredatsite);•totalinstalledprojectcost,includingfixedfinancingcosts;•capacityfactorbyproject;and•theLCOE.Theanalysisinthispaperfocusesonestimatingthecostsofrenewablesfromtheperspectiveofprivateinvestors,whethertheyareastate-ownedelectricitygenerationutility,anindependentpowerproducer(IPP),oranindividualorcommunitylookingtoinvestinsmall-scalerenewables.Theanalysisexcludestheimpactofgovernmentincentivesorsubsidies,systembalancingcostsassociatedwithvariablerenewablesandanysystem-widecost-savingsfromthemeritordereffect.Furthermore,theanalysisdoesnottakeintoaccountanyCO2pricingorthebenefitsofrenewablesinreducingotherexternalities(e.g.reducedlocalairpollutionorcontaminationofthenaturalenvironment).Similarly,thebenefitsofrenewablesbeinginsulatedfromvolatilefossilfuelpriceshavenotbeenquantified.TheseissuesareimportantbutarecoveredbyotherprogrammesofworkatIRENA.192RENEWABLEPOWERGENERATIONCOSTSIN2022Cleardefinitionsofthetechnologycategoriesareprovided,wherethisisrelevant,toensurethatcostcomparisonsarerobustandprovideusefulinsights(e.g.smallhydropowervs.largehydropower).Similarly,functionalityhastobedistinguishedfromotherqualitiesoftherenewablepowergenerationtechnologiesbeinginvestigated(e.g.concentratingsolarpower[CSP]withandwithoutthermalenergystorage).Thisisimportanttoensurethatsystemboundariesforcostsareclearlysetandthattheavailabledataaredirectlycomparable.Otherissuescanalsobeimportant,suchascostallocationrulesforcombinedheatandpowerplants,andgridconnectioncosts.Thedatausedforthecomparisonsinthispapercomefromavarietyofsources,suchasIRENARenewableCostingAlliancemembers,businessjournals,industryassociations,consultancies,governments,auctionsandtenders.Everyefforthasbeenmadetoensurethatthesedataaredirectlycomparableandareforthesamesystemboundaries.Wherethisisnotthecase,thedatahavebeencorrectedtoacommonbasisusingthebestavailabledataorassumptions.Thesedatahavebeencompiledintoasinglerepository–theIRENARenewableCostDatabase–thatincludesamixofconfidentialandpublicdomaindata.Animportantpointisthat,althoughthisreportexaminescosts,strictlyspeaking,thedatapointsavailableareactuallyprices–whicharesometimesnoteventruemarketaverageprices,butpriceindicators(e.g.surveyedestimatesofaveragemodulesellingpricesindifferentmarkets).Thedifferencebetweencostsandpricesisdeterminedbytheamountabove,orbelow,thenormalprofitthatwouldbeseeninacompetitivemarket.Therapidgrowthofrenewablesmarketsfromasmallbasemeansthatthemarketforrenewablepowergenerationtechnologiesissometimesnotwellbalanced.Asaresult,pricescanrisesignificantlyabovecostsintheshorttermifsupplyisnotexpandingasfastasdemand,whileintimesofexcesssupply,lossescanoccur,andpricesmaybebelowproductioncosts.Thiscanmakeanalysingthecostofrenewablepowergenerationtechnologieschallengingforsometechnologiesingivenmarketsatcertaintimes.Wherecostsaresignificantlyaboveorbelowwheretheymightbeexpectedtobeintheirlong-termtrend,everyefforthasbeenmadetoidentifythecauses.Althougheveryefforthasbeenmadetoidentifythereasonswhycostsdifferbetweenmarketsforindividualtechnologies,theabsenceofthedetaileddatarequiredforthistypeofanalysisoftenprecludesadefinitiveanswer.IRENAconductedanumberofanalysesfocusingonindividualtechnologiesandmarketsinanefforttofillthisgap(IRENA,2016aand2016b).TheLCOEofrenewableenergytechnologiesvariesbytechnology,countryandproject,basedontherenewableenergyresource,capitalandoperatingcosts,andtheefficiency/performanceofthetechnology.Theapproachusedintheanalysispresentedhereisbasedonadiscountedcashflow(DCF)analysis.Thismethodofcalculatingthecostofrenewableenergytechnologiesisbasedondiscountingfinancialflows(annual,quarterlyormonthly)toacommonbasis,takingintoconsiderationthetimevalueofmoney.Giventhecapital-intensivenatureofmostrenewablepowergenerationtechnologiesandthefactthatfuelcostsarelow,oroftenzero,theweightedaveragecostofcapital(WACC)usedtoevaluatetheproject–oftenalsoreferredtoasthediscountrate–hasacriticalimpactontheLCOE.193ANNEXITomoreaccuratelyassessthecompetitivenessofrenewablepower,IRENAhascreatedadatabaseoffossilfuelpriceindicesandofthecapitalcosts,efficiencyandO&Mcostsoffossilfuelpowerplants.ThedatacollectedbyIRENA,aswellassourcesofthatdata,canbefoundintheonlineannextothisreport.Therearemanypotentialtrade-offstobeconsideredwhendevelopinganLCOEmodellingapproach.Theapproachtakenhereisrelativelysimplistic,giventhefactthatthemodelneedstobeappliedtoawiderangeoftechnologiesindifferentcountriesandregions.Thishastheadvantage,however,ofproducingatransparentandeasy-to-understandanalysis.Inaddition,moredetailedLCOEanalysesresultinasignificantlyhigheroverheadintermsofthegranularityofassumptionsrequired.Thiscangivetheimpressionofgreateraccuracy,butwhenthemodelcannotberobustlypopulatedwithassumptions,andifassumptionsarenotdifferentiatedbasedonreal-worlddata,thentheaccuracyoftheapproachcanbemisleading.TheformulausedforcalculatingtheLCOEofrenewableenergytechnologiesis:Where:LCOE=theaveragelifetimelevelisedcostofelectricitygenerationIt=investmentexpendituresintheyeartMt=operationsandmaintenanceexpendituresintheyeartFt=fuelexpendituresintheyeartEt=electricitygenerationintheyeartr=discountraten=lifeofthesystemAllcostspresentedinthisreportaredenominatedinreal,2022USdollars;thatistosay,afterinflationhasbeentakenintoaccount,unlessotherwisestated.TheLCOEisthepriceofelectricityrequiredforaprojectwhererevenueswouldequalcosts,includingmakingareturnonthecapitalinvestedequaltothediscountrate.Anelectricitypriceabovethiswouldyieldagreaterreturnoncapital,whileapricebelowitwouldyieldalowerreturnoncapital,orevenaloss.Asalreadymentioned,althoughdifferentcostmeasuresareusefulindifferentsituations,theLCOEofrenewableenergytechnologiesisawidelyusedfirstordermeasurebywhichpowergenerationtechnologiescanbecompared.MoredetailedDCFapproaches–takingintoaccounttaxation,subsidiesandotherincentives–areusedbyrenewableenergyprojectdeveloperstoassesstheprofitabilityofreal-worldprojectsbutarebeyondthescopeofthisreport.ThecalculationofLCOEvaluesinthisreportisbasedonproject-specifictotalinstalledcostsandcapacityfactors,aswellastheO&Mcosts.Thedataforprojectspecific-totalinstalledcostsforthemostrecentyearsareamixofexanteandexpostdata.Thedataforproject-specificcapacityfactorsfor,invirtuallyallcases,areexantedataandsubjecttochange.precludesadefinitiveanswer.IRENAconductedanumberofanalysesfocusingechnologiesandmarketsinanefforttofillthisgap(IRENA,2016aand2016b).enewableenergytechnologiesvariesbytechnology,countryandproject,basednewableenergyresource,capitalandoperatingcosts,andtheormanceofthetechnology.usedintheanalysispresentedhereisbasedonadiscountedcashflow(DCF)methodofcalculatingthecostofrenewableenergytechnologiesisbasedonnancialflows(annual,quarterlyormonthly)toacommonbasis,takingintothetimevalueofmoney.Giventhecapital-‐intensivenatureofmostrenewabletiontechnologiesandthefactthatfuelcostsarelow,oroftenzero,theagecostofcapital(WACC)usedtoevaluatetheproject–oftenalsoreferredtotrate–hasacriticalimpactontheLCOE.nypotentialtrade-‐offstobeconsideredwhendevelopinganLCOEmodellingapproachtakenhereisrelativelysimplistic,giventhefactthatthemodelneedstoawiderangeoftechnologiesindifferentcountriesandregions.Thishasthewever,ofproducingatransparentandeasy-‐to-‐understandanalysis.Inaddition,LCOEanalysesresultinasignificantlyhigheroverheadintermsoftheassumptionsrequired.Thiscangivetheimpressionofgreateraccuracy,butdelcannotberobustlypopulatedwithassumptions,andifassumptionsarenotbasedonreal-‐worlddata,thentheaccuracyoftheapproachcanbemisleading.sedforcalculatingtheLCOEofrenewableenergytechnologiesis:LCOE=𝐼𝐼!+𝑀𝑀!+𝐹𝐹!1+𝑟𝑟!!!!!𝐸𝐸!1+𝑟𝑟!!!!!eragelifetimelevelisedcostofelectricitygenerationtexpendituresintheyeart194RENEWABLEPOWERGENERATIONCOSTSIN2022Thoughtheterms“O&M”and“OPEX”(operationalexpenses)areoftenusedinterchangeably.TheLCOEcalculationsinthisreportarebasedon“all-in-OPEX”,ametricthataccountsforalloperationalexpensesoftheprojectincludingsomethatareoftenexcludedfromquotedO&Mpriceindices,suchasinsuranceandassetmanagementcosts.Operationalexpensedataforrenewableenergyprojectsareoftenavailablewithdiversescopeandboundaryconditionsandwhileeveryeffortismadetoensurethedataisdirectlycomparable,itisoftennotpossibletoverifythiswithcertainty.ThesedatacanbedifficulttointerpretandharmonisedependingonhowtransparentandclearthesourceisaroundtheboundaryconditionsfortheO&Mcostsquoted.However,everyefforthasbeenmadetoensurecomparabilitybeforeusingittocomputeLCOEcalculations.ThestandardisedassumptionsusedforcalculatingtheLCOEincludetheWACC,economiclifeandcostofbioenergyfeedstocks.WeightedaveragecostofcapitalTheanalysisinIRENAcostreportsuptoanincludingtheyear2020aWACCforaprojectof7.5%(real)inOECDcountriesandChina,whereborrowingcostsarerelativelylowandstableregulatoryandeconomicpoliciestendtoreducetheperceivedriskofrenewableenergyprojectsandaWACCof10%fortherestoftheworld.Inthe2021editionofthereport,theWACCassumptionshadbeenreducedtoreflectmorerecentmarketconditions.Consequently,thepreviouseditionofthereportassumedaWACCof7.5%in2010fortheOECDandChina,decliningto5%in2020.Fortherestofworld,thepreviouseditionassumedaWACCof10%2010,fallingto7.5%in2020.For2022editionandthisreport,WACCassumptionsaretechnology-andcountry-specificbenchmarkvaluesfor100countriesfromIRENAsWACCbenchmarktool(IRENA,2023c).IthasbeencalibratedtotheresultsoftheIRENA,IEAWindTask26andETHZurichcostoffinancesurvey.Thisexerciseresultsintechnology-specificWACCdataforonshorewind,offshorewindandsolarphotovoltaictechnologiesin100countries.Thesedatacanbefoundinthedatasetaccompanyingthisreport(visitirena.orgformoredetails).Forcountriesoutsidethe100inthebenchmarktoolandforbioenergy,geothermalandhydropower,simplerassumptionsontherealcostofcapitalofaremadefortheOECDcountriesandChina,andtherestoftheworld,separately.Theseareinlinewiththeassumptionsinthepreviouseditionofthisreport(TableA1.1).TableA1.1StandardisedassumptionsforLCOEcalculationsTechnologyEconomiclife(years)Weightedaveragecostofcapital(real)OECDandChinaRestoftheworldWindpower257.5%in2010fallingto5%in202010%in2010fallingto7.5%in2020SolarPV25CSP25Hydropower30Biomassforpower20Geothermal25195ANNEXIIRENAhassubstantiallyimprovedthegranularityand/orrepresentationoftheWACCandO&McoststhatareutilisedintheLCOEcalculation.ThechangesaredesignedtoimprovetheaccuracyoftheLCOEestimatesbytechnology.However,challengesremaininobtainingaccurateandup-to-dateWACCassumptionsgiventhecostofdebtandtherequiredreturnonequity,aswellastheratioofdebt-to-equity,variesbetweenindividualprojectsandcountries,dependingonawiderangeoffactors.ThiscanhaveasignificantimpactontheaveragecostofcapitalandtheLCOEofrenewablepowerprojects.Italsohighlightsanimportantpolicyissue:inaneraoflowequipmentcostsforrenewables,ensuringthatpolicyandregulatorysettingsminimiseperceivedrisksforrenewablepowergenerationprojectscanbeaveryefficientwaytoreducetheLCOE,byloweringtheWACC.CHANGINGFINANCINGCONDITIONSFORRENEWABLESANDTHEWEIGHTEDAVERAGECOSTOFCAPITALThissectiondiscussesinmoredetailthebackgroundtotheWACCbenchmarkmodelandtheprocessbehindtheIRENA,IEAWindandETHZurichsurveyoffinancingconditionsforsolarandwindtechnologies.HavingmoreaccurateWACCassumptionsnotonlyimprovestheadviceIRENAcangiveitsmembercountries,butalsofillsagapforthebroaderenergymodellingcommunity.Thisisincriticalneedofimprovedrenewableenergycostofcapitaldata(Egli,SteffenandSchmidt,2019).Changesinthecostofcapitalthatarenotproperlyaccountedforovertime–betweencountriesortechnologies–canresultinsignificantmisrepresentationsoftheLCOE,leadingtodistortedpolicyrecommendations.Today,however,reliabledatathatcomprehensivelycoverindividualrenewabletechnologies,acrossarepresentativenumberofcountriesand/orregionsandthroughtimeremainremarkablysparse(DonovanandNunez,2012).Thisistypicallyduetotheextremedifficultyinobtainingproject-levelfinancialinformationdueitsproprietarynature(Steffen,2019).WhileevidencefordecliningandlowerWACCsthanassumptionspreviouslyusedbyisextensive(Steffen,2019),itcanbechallengingtoextractmeaningfulinsightsfromthedatacontainedintoday’sliterature,asthemajorityofstudiestodateuseinconsistentmethodologiesandmayrefertodifferentyears,countriesandtechnologies.Akeychallengeisthesmallnumberofcountriesforwhichdataareavailableforeachtechnology,andtherelativelynarrow‘snapshot’offinancingconditionsmanystudiesprovide.Typically,existingstudieshaveassessedonlyasinglecountry,withjustafewstudiesextendingtheiranalysistofiveormorestates.MoststudieshavealsofocusedononshorewindandsolarPVonlyandlimitedtheirassessmenttohistoricaldata,asopposedtodevelopingamethodanddatabasisforprojectionsandassociatedscenarios.Abroadercoverageofcountries/regionsandtechnologiesandthecapabilitytodevelopscenariosthatincludethefuturecostofcapitaliscriticalforIRENAandotherstakeholders,ifaproperassessmentoftheLCOEacrossdifferentworldregions,technologiesandovertimeistobemade.196RENEWABLEPOWERGENERATIONCOSTSIN2022InNovember2019,IRENAconductedaworkshopwithexpertsinthefieldtodiscusstheseissuesandcurrentWACCassumptions,inordertoidentifyawaytoimprovedataavailability.In2020,thisresultedinIRENA,IEAWindandETHZurichworkingtogethertobenchmarkWACCvaluesbycountry,whilealsoformulatingasurveyonthecostoffinanceforrenewableenergyprojectsthatcanbeimplementedonline,butwillalsobesupportedbyanumberofsemi-structuredinterviewswithkeystakeholdersinordertounderstandthedriversbehindfinancingcostsandconditions.Thelong-termgoalistodevelopasurveymethodologywhichcanberepeatedperiodicallyinthefuture.Thefirstgoalofthiswork,namelytoarriveatdetailedcountryandtechnology-specificWACCdataforsolarPV,onshoreandoffshorewindhasalreadybeenimplementedinthiseditionofthereport.Thishasbeenachievedbyathree-prongedapproachtodatacollection.Thebasisforitarethefollowing:•Desktopanalysis:ThiscombinestwoanalyticalmethodstobetterunderstandWACCs.ThefirstmatchesprojectsintheIRENARenewableCostDatabaseandIRENAAuctionsandPPADatabase.IttakestheadjustedPPA/auctionpriceasthebenchmarktovarytheWACCintheLCOEcalculation,withtheothercomponentsofthatcalculationattheprojectlevel(e.g.economiclife,capacityfactors,O&Mcostsandtotalinstalledcosts)remainingfixed.ThisallowsIRENAtoreverseengineeranindicatorofWACC.Thesecondanalyticalmethodtakesfinancialmarketdataonrisk-freelendingrates,countryriskpremiums,lendersmarginsandequityriskpremiumstodevelopcountry-specificWACCbenchmarksforrenewables.The‘becnhmarktool’isdesignedtogenerateannualcountry-andtechnology-specificWACCdatabasedonupdatedinputassumptionsonanannualbasisforthisreport.•Anonlineexpertelicitationsurvey:UndertakenbyIRENA,IEAWindTask26andETHZurichinQ2andQ32021.ThiswasdistributedwidelytoknowledgeablefinanceprofessionalswithadetailedunderstandingofthefinancingconditionsandaskedstakeholderswithexperienceoffinancingrenewableprojectsabouttheindividualcomponentsthatcontributetotheWACC.•In-depth,semi-structuredinterviews:Targetingasmallnumberoffinanceprofessionalsinvolvedinthefinancingofrenewableprojectstocollectdataaboutthecostofdebtandequityandtheshareofdebtinthetotal,aswellasonthecontextualfactorsthathavebeendrivingthesefinancingcosts–ordifferencesincosts–acrossmarketsandtechnologies.ThesewereconductedinQ3andQ42021andweredesignedtoextractdeeperinsightsaboutwhatisdrivingthedifferencesinfinancingconditionsfortechnologiesindifferentcountries.Theenergymodellingcommunityneedsaccurateweightedaveragecostofcapitalassumptionstoensurecorrectlyestimateelectricitycosts197ANNEXIThedesktopanalysisaimingtoderivebenchmarkWACCcomponents(e.g.debtcost,equitycost,debt-to-equityratio,etc.)servedasaprecursortotheonlinesurveyandthesemi-structuredinterviews.ThebenchmarkingprocesswasalsoapartofdevelopinganenhancedunderstandingoftheconstituentsofWACCandtheirkeydrivers,whilealsoservingtwogoals:first,toprovideinsightsintotheunderlyingdriversoftheWACCcomponents;andsecond,thecreationofabenchmarkingcostofcapitaltoolthatcanbeusedtofillingapsinthesurveyanalysis.47Inadditiontousingthebenchmarkvaluescreatedinthisprocesstoseedtheonlinesurvey,thesurveyprocessitselfhelpedrefinethebenchmarkingtool,thereforeimprovingitsrobustness.Forthefirstpartofthebenchmarkingwork,IRENAandETHZurichworkedtogethertomatchutility-scalesolarPVprojectsintheIRENARenewableCostDatabaseandIRENAAuctionsandPPADatabase,withproject-leveltotalinstalledcostsandcapacityfactors,countryO&Mvaluesandstandardisedeconomiclifetimes.WethenarrivedataWACCthatyieldedanLCOEthatmatchedtheadjustedPPA/auctionprice.IRENA,IEAWindandETHZurichhavealsodevelopedabenchmarkcostofcapitaltool.ThebenchmarkapproachusesthefollowingapproachtocalculatetheWACCforrenewablepowergenerationprojects:Where:Ce=CostofequityCd=CostofdebtD=MarketvalueofdebtE=MarketvalueofequityT=CorporatetaxrateThebenchmarkalsotakesthecostofdebtascalculatedbycombiningtheglobalrisk-freerate(providedbycurrentUSgovernment10-yearbondsat1.68%)withacountryriskpremiumfordebt(basedoncreditdefaultswapvalues)48andlenders’margins(astandardisedassumptionof2%asaglobalbaselineforlendingmarginsforlargeprivateinfrastructuredebt).ThecostofequityisthesumoftheUSlong-runequityrateofreturnof6.4%(orapremiumof4.7%overrisk-freerate)pluscountryequitypremium(ifany),plusthetechnologyequityriskpremium(ifany),plustheUSrisk-freerate.Debt-to-equityratiosandthetechnologyriskpremiumarevariedbytechnology,basedonlocalmarketmaturity.Marketmaturitylevelsarebasedontheshareofpenetrationofeachtechnology.Thesehavebeenarbitrarilydefinedas‘new’,‘intermediate’and‘mature’,dependingonthresholdsof0%-5%,5%-10%and10%+ofcumulativeinstalledcapacity,respectively,andusingfixedvaluesof60%,70%and80%forthedebt-to-equityratio,alongwithequitytechnologyriskpremiumsof1.5%,2.4%and3.25%,dependingonmarketmaturity.47Itisnotfeasibleforsurveystakeholders’projectpartnerstoprovidereal-worldWACCcomponentsforsolarPV,onshoreandoffshorewindinevenamajorityofthecountriesoftheworld.Therefore,thebenchmarkcostofcapitaltoolwillbeessentialinfleshingoutgapsinthesurveyresultstoprovideclimateandenergymodellerswithdataforallthecountries/regionsintheirmodels.48ThisisbasedonworkbyProf.A.Damodaran,themethodologyusedisdescribedathttps://papers.ssrn.com/sol3/papers.cfm?abstract_id=3653512198RENEWABLEPOWERGENERATIONCOSTSIN2022ThebenchmarktoolcreatesnominalvaluesforeachWACCparameter,butassuming1.8%inflation(roughlythevalueintheUnitedStatesoverthelastdecade),wecantransformtheresultsintorealvalues.Theprojectteamdevelopedandrefinedthebenchmarktoolinthesecondhalfof2021andQ12022.IRENAtookthesurveyresultsandthenusedthesetorefinethebenchmarkmodel.Thiswasdonesothatmarginsfordifferentfinancingcostcomponentsforindividualcountries/technologieswereascloseaspossibletothesurveyedresults.MoredetailonthetheprocessandthesummarisedresultsofthesurveycanbefoundinThecostoffinancingforrenewablepower(IRENA,2023c).FigureA1.1presentstheresultsofthecalibratedbenchmarktool,fortherealafter-taxWACCvaluesbycountry/technology.Thecentreofthecolourscaleis7.5%,soallowingtheeasyidentificationofcountriesthatthisyearthathaveahighercostofcapitalthanwasassumedinIRENAreportspriorto2022(IRENA,2021).Inmost,butnotall,OECDcountries,however,therealafter-taxWACCislowerasaresult–insomecases,substantially.ThevaluesusedfortheLCOEcalculationsfordeploymentin2021and2022arethoseinFigureA1.1,withvaluesin2010of7.5%fortheOECDandChina,and10%elsewhere.Valuesbetweenthesetwodatesarelinearlyinterpolated.Forthosecountriesnotcoveredbythebenchmarktoo,asalreadynoted,therealafter-taxWACCvaluesdeclinelinearlyfrom2010to5%fortheOECDandChinaand7.5%elsewherein2022.SolarPVOffshorewindOnshorewind©Mapbox©OpenStreetMap©Mapbox©OpenStreetMap©Mapbox©OpenStreetMapWACCrealFigureA1.1Countryandtechnology-specificrealafter-taxWACCassumptionsfor2021and2022Source:IRENA,2023c.Disclaimer:Thismapisprovidedforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplytheexpressionofanyopiniononthepartofIRENAconcerningthestatusofanyregion,country,territory,cityorareaorofitsauthorities,orconcerningthedelimitationoffrontiersorboundaries.199ANNEXITheWACCvaluessurveyedin2021weregenerallyrepresentativeoffinancingconditionsin2020and2021.GivenmostonshorewindandsolarPVprojectsarefinancedintheyearpriortocommissioningtheWACCvaluesusedfor2022areunchangedformthebenchmarkvaluesfor2021.However,withinflationandinterestratesrisingrapidlyin2022,nextyearsreportwillincludeupdatedbenchmarkWACCvaluesthatwillbesignificantlyhigherthanreportedhere.ThislaggedimpactofrisinginterestratesonLCOEswillbesignificant,giventhelowcostoffinanceforrenewablesthatcharacterisedrecentyears.Overall,thesemorerealisticWACCchangeshaveimprovedtherepresentativenessoftheLCOEcalculationsatacountrylevel,andinthecaseoftheWACCassumptions,havealsobroughtourassumptionsintolinewiththeresultsoftheIRENA,IEAWindTask26andETHZurichcostoffinancesurvey.Theresultingchangesprovideyetanotherstepforwardinensuringthemostaccurateestimationpossibleofthelifetimecostofrenewablepowergenerationcostsbycountry.Thereisstillroomforimprovement,however,andIRENAisalwaysworkingtoimproveitsdata.wadstock©Shutterstock.com200RENEWABLEPOWERGENERATIONCOSTSIN2022TableA1.2O&McostassumptionsfortheLCOEcalculationofonshorewindprojects2022USD/kW/yearSweden36Ireland30Germany43Denmark30UnitedStates26Norway36Japan81Brazil24Canada35Mexico44Spain26UnitedKingdom37France47China26India21Australia34OtherOECD36Othernon-OECD31O&MCOSTSOnshorewindForonshorewind,intheabsenceofproject-specificcostdata,IRENAhasusedsecondarysourcesforO&Mcostassumptions.InmanycasesallthatwasavailablewerecostsperkWhandtheyearofcollectionorapplicabilitywasoftennotclear.Withrisingcapacityfactorsforonshorewind,assumingafixedperkWhfigurewas,inalllikelihood,overstatingtheactualcontributionofO&MtooverallLCOEcostsinsomecases.Consistentwithlastyear’sreport,allO&MassumptionstoaUSD/kWbasis(FigureA1.2).DatacomefromtheIRENARenewableCostsDatabase,IEAWindTask26,regulatoryfilings,investorpresentations,aswellascountry-specificresearch.Wherecountrydataarenotavailablethroughtheseprimarysources,assumptionsfromsecondarysourcesareused.Ifnorobustcountry-specificdatacanbefound,regionalaveragesareused.SolarPVDependingonthecommissioningyear,adifferentO&McostassumptionisusedforthecalculationofthesolarPVLCOEestimatescalculatedinthisreport.AnadditionaldistinctionismadedependingonwhethertheprojecthasbeencommissionedinacountrybelongingtotheOECDornot(TableA1.3).201ANNEXICompletecountryandtechnology-specificO&Massumptionsbyyearalltechnologiescanbefoundintheaccompanyingdatasettothisreport.OffshorewindTheO&McostassumptionshavealsobeenalignedtoasingleUSD/kW/yearmetric.TableA1.4O&McostassumptionsfortheLCOEcalculationofonshorewindprojects2022USD/kW/yearBelgium76Denmark69Netherlands80Germany77UnitedKingdom74France80China52UnitedStates70Japan127OtherOECD75Othernon-OECD62Source:IRENARenewableCostDatabase.TableA1.3O&McostassumptionsfortheLCOEcalculationofPVprojectsYearOECD2022USD/kW/yearNon-OECD2022USD/kW/year201027.125.6201124.023.5201223.418.2201322.915.3201422.413.7201521.712.4201621.111.3201721.510.9201820.110.4201919.29.9202018.29.6202118.29.6202217.89.2Source:IRENARenewableCostDatabase.202RENEWABLEPOWERGENERATIONCOSTSIN2022TOTALINSTALLEDCOSTBREAKDOWN:DETAILEDCATEGORIESFORSOLARPVIRENAhasforsomeyearscollectedcostdataonaconsistentbasisatadetailedlevelforaselectionofPVmarkets.Inadditiontotrackingaveragemoduleandinvertercosts,thebalanceofsystemcostsarebrokendownintothreebroadcategories:non-moduleandinverterhardware,installationcosts,andsoftcosts.Thesethreecategoriesarecomposedofmoredetailedsub-categorieswhichcangreaterunderstandingofthedriversofsolarPVbalanceofsystem(BoS)costsandarethebasisforsuchanalysisinthisreport.Anlaysisofcoal-firedpowerplantoperatingcostsinBulgaria,China,GermanyandIndia,whenitcomestogenerationlevels(inordertocalculatecapacityfactors,andwiththeexceptionoftheBulgarianligniteplants)andin2021forfuelcosts,whereplantsareexposedtomarketprices.49ThefigurealsoincludestheweightedaveragePPApriceforprojectstobecommissionedin2021,orinthecaseofBulgaria,anestimateoftheLCOEofsolarandonshorewindutilisationcosts–representativeforSouthEastEurope–basedonprojectscurrentlyindevelopment.50Thecalculationspresentedhereshouldthereforebetreatedwithcaution,becauseanumberofuncertaintiesexist.Whenlookingatfuelcosts,thereareuncertaintiesaroundtheexactdeliveredcostofcoaltomanyplants.Thisisbecause,outsidetheanalysisfortheUnitedStatesandforcoastalplantsusingimportedcoal,plant-levelfuelcostsarenotreported.Intheirabsence,cost-plusmodelsofmininganddeliverycostsareestimated.Thesemaybeaccurateinaggregate,butnotforindividualplants.Similarly,theavailabilityofplant-levelO&McostsoutsidetheUnitedStatesandBulgariaispatchy,andassumptionsderivedfromplantage,technologyandcountryareused.49Thisanalysisispredominantlybasedonupdatingthefollowingsources:CarbonTracker,2018;Szabó,L.,etal.,2020;Öko-Institut,2017;DIWBerlin,WuppertalInstitutandEcoLogic,2019;andVibrantCleanEnergy,2019.Theupdatesdrawonanumberofsources,includingBooz&Co,2014;CoalIndia,2020;Energy-charts.de,2021;IEA,2021;NPP,2021;andUSEIA,2021.50TheassumptionsforsolarPVareEUR740/kW(USD830/kW)andacapacityfactorof13%,whileforwind,theassumptionsareEUR1500/kW(USD1685/kW)anda36%capacityfactor.surasakjailak©Shutterstock.com203ANNEXITableA1.5BoScostbreakdowncategoriesforsolarPVCategoryDescriptionNon-modulehardwareCabling·Alldirectcurrent(DC)components,suchasDCcables,connectorsandDCcombinerboxes·AllAClowvoltagecomponents,suchascables,connectorsandACcombinerboxesRackingandmounting·Completemountingsystemincludingrammingprofiles,foundationsandallmaterialforassembling·AllmaterialnecessaryformountingtheinverterandalltypeofcombinerboxesSafetyandsecurity·Fences·Cameraandsecuritysystem·Allequipmentfixedinstalledastheftand/orfireprotectionGridconnection·Allmediumvoltagecablesandconnectors·Switchgearsandcontrolboards·Transformersand/ortransformerstations·Substationandhousing·Meter(s)Monitoringandcontrol·Monitoringsystem·Meteorologicalsystem(e.g.irradiationandtemperaturesensor)·SupervisorycontrolanddatasystemInstallationMechanicalinstallation(construction)·Accessandinternalroads·Preparationforcablerouting(e.g.cabletrench,cabletrunkingsystem)·Installationofmounting/rackingsystem·Installationofsolarmodulesandinverters·Installationofgridconnectioncomponents·Uploadingandtransportofcomponents/equipmentElectricalinstallation·DCinstallation(moduleinterconnectionandDCcabling)·ACmediumvoltageinstallation·Installationofmonitoringandcontrolsystem·Electricaltests(e.g.DCstringmeasurement)Inspection(constructionsupervision)·Constructionsupervision·HealthandsafetyinspectionsSoftcostsIncentiveapplication·AllcostsrelatedtocomplianceinordertobenefitfromsupportpoliciesPermitting·Allcostsforpermitsnecessaryfordeveloping,constructionandoperation·AllcostsrelatedtoenvironmentalregulationsSystemdesign·Costsforgeologicalsurveysorstructuralanalysis·Costsforsurveyors·Costsforconceptualanddetaileddesign·CostsforpreparationofdocumentationCustomeracquisition·Costsforprojectrights,ifany·Anytypeofprovisionpaidtogetprojectand/oroff-takeagreementsinplaceFinancingcosts·AllfinancingcostsnecessaryfordevelopmentandconstructionofPVsystem,suchascostsforconstructionfinanceMargin·MarginforEPCcompanyand/orforprojectdeveloperfordevelopmentandconstructionofPVsystemincludesprofit,wages,finance,customerservice,legal,humanresources,rent,officesupplies,purchasedcorporateprofessionalservicesandvehiclefees204RENEWABLEPOWERGENERATIONCOSTSIN2022ANNEXIITHEIRENARENEWABLECOSTDATABASEThecompositionoftheIRENARenewableCostDatabaselargelyreflectsthedeploymentofrenewableenergytechnologiesoverthelasttentofifteenyears.MostprojectsinthedatabaseareinChina(939GW),theUnitedStates(226GW),India(168GW),andBrazil(95GW).CollectingcostdatafromOECDcountries,however,issignificantlymoredifficultduetogreatersensitivitiesaroundconfidentialityissues.TheexceptionistheUnitedStates,wherethenatureofsupportpoliciesleadstogreaterquantitiesofprojectdatabeingavailable.Afterthesefourmajorcountries,Germanyisrepresentedby92GWofprojects,Spainby48GW,theUnitedKingdomby47GW,Japanby46GWofprojects,VietNamby41GW,Italyby35GW,Canadaby33GW,Australiaalsoby33GWandTürkiyeby31GWofprojects.OnshorewindisthelargestsinglerenewableenergytechnologyrepresentedintheIRENARenewableCostDatabase,with871GWofprojectdataavailablefrom1983onwards.Solarphotovoltaicisthesecondlargesttechnologyrepresentedinthedatabasewith694GWofprojects,followedbyhydropowerwith573GWofprojectssince1961,witharound90%ofthoseprojectscommissionedintheyear2000orlater.Costdataareavailablefor69GWofcommissionedoffshorewindprojects,93GWofbiomassforpowerprojects,8GWofgeothermalprojectsandaround7GWofCSPprojects.BORJAPD©Shutterstock.com205ANNEXIIThecoverageoftheIRENARenewableCostDatabaseismoreorlesscompleteforoffshorewindandCSP,wheretherelativelysmallnumberofprojectscanbemoreeasilytracked.Thedatabaseforonshorewindandhydropowerisrepresentativefromaround2007,withcomprehensivedatafromaround2009onwards.Gapsinsomeyearsforsomecountriesthatareinthetop20fordeploymentinagivenyearrequirerecoursetosecondarysources,however,inordertodevelopstatisticallyrepresentativeaverages.DataforsolarPVattheutility-scalehaveonlybecomeavailablemorerecentlyandthedatabaseisrepresentativefromaround2011onwards,andcomprehensivefromaround2013onwards.SolarphotovoltaicHydropowerOshorewindOnshorewind©Mapbox©OpenStreetMapGWGWIRENARenewableCostDatabaseNumberofprojectsGWChinaUSAIndiaOnshorewindSolarPVHydropowerNumberofprojects≤≥FigureA2.1DistributionofprojectsbytechnologyandcountryinIRENA'sRenewableCostDatabaseDisclaimer:Thismapisforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplyanyofficialendorsementoracceptancebyIRENA.206RENEWABLEPOWERGENERATIONCOSTSIN2022AsiaAfghanistan,Bangladesh,Bhutan,BruneiDarussalam,Cambodia,People’sRepublicofChina,DemocraticPeople’sRepublicofKorea,India,Indonesia,Japan,Kazakhstan,Kyrgyzstan,LaoPeople’sDemocraticRepublic,Malaysia,Maldives,Mongolia,Myanmar,Nepal,Pakistan,Philippines,RepublicofKorea,Singapore,SriLanka,Tajikistan,Thailand,Timor-Leste,Turkmenistan,Uzbekistan,VietNam.AfricaAlgeria,Angola,Benin,Botswana,BurkinaFaso,Burundi,CaboVerde,Cameroon,CentralAfricanRepublic,Chad,Comoros,Congo,Côted’Ivoire,DemocraticRepublicoftheCongo,Djibouti,Egypt,EquatorialGuinea,Eritrea,Ethiopia,Eswatini,Gabon,Gambia,Ghana,Guinea,Guinea-Bissau,Kenya,Lesotho,Liberia,Libya,Madagascar,Malawi,Mali,Mauritania,Mauritius,Morocco,Mozambique,Namibia,Niger,Nigeria,Rwanda,SaoTomeandPrincipe,Senegal,Seychelles,SierraLeone,Somalia,SouthAfrica,SouthSudan,Sudan,Togo,Tunisia,Uganda,UnitedRepublicofTanzania,Zambia,Zimbabwe.CentralAmericaandtheCaribbeanAntiguaandBarbuda,Bahamas,Barbados,Belize,CostaRica,Cuba,Dominica,DominicanRepublic,ElSalvador,Grenada,Guatemala,Haiti,Honduras,Jamaica,Nicaragua,Panama,SaintKittsandNevis,SaintLucia,SaintVincentandtheGrenadines,TrinidadandTobago.EurasiaArmenia,Azerbaijan,Georgia,RussianFederation,Türkiye.EuropeAlbania,Andorra,Austria,Belarus,Belgium,BosniaandHerzegovina,Bulgaria,Croatia,Cyprus,CzechRepublic,Denmark,Estonia,Finland,France,Germany,Greece,Hungary,Iceland,Ireland,Italy,Latvia,Liechtenstein,Lithuania,Luxembourg,Malta,Monaco,Montenegro,KingdomoftheNetherlands,Norway,Poland,Portugal,RepublicofMoldova,Romania,SanMarino,Serbia,Slovakia,Slovenia,Spain,Sweden,Switzerland,Ukraine,UnitedKingdom.ANNEXIIIREGIONALGROUPINGS207ANNEXIIIMiddleEastBahrain,IslamicRepublicofIran,Iraq,Israel,Jordan,Kuwait,Lebanon,Oman,Qatar,SaudiArabia,SyrianArabRepublic,UnitedArabEmirates,Yemen.NorthAmericaCanada,Mexico,UnitedStates.OceaniaAustralia,Fiji,Kiribati,MarshallIslands,Micronesia(FederatedStatesof),Nauru,NewZealand,Palau,PapuaNewGuinea,Samoa,SolomonIslands,Tonga,Tuvalu,Vanuatu.SouthAmericaArgentina,Bolivia(PlurinationalStateof),Brazil,Chile,Colombia,Ecuador,Guyana,Paraguay,Peru,Suriname,Uruguay,Venezuela(BolivarianRepublicof).huangyifei©Shutterstock.comwww.irena.org©IRENA2023

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